20241230Appendices.pdf

Appendix A
2025 Electric Integrated
Resource Plan
Appendix A — 2025 Technical
Advisory Committee and Public
Presentations and Meeting
Minutes
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2025 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 1 Agenda
Tuesday, September 26, 2023
Virtual Meeting
Topic Time Staff
Introductions 8:30 John Lyons
CEIP Update 8:45 Kelly Dengel
TAC Process and Methods Proposals 9:15 James Gall
PLEXOS Overview and Back Cast Analysis 9:45 Mike Hermanson
Break 10:45
Available Resource Options Discussion 11 :00 Lori Hermanson
Work Plan 11 :30 John Lyons
Adjourn 12:00
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'AI VISTA
2023 IRP TAC 1 Introductions
John Lyons, Ph.D.
Technical Advisory Committee Meeting No. 1
September 26, 2023

Appendix A
Meeting Guidelip'Oft 'aft' 'r
• IRP team is in office Monday - Wednesday and also available
by email , phone and Teams for questions and comments
• Stakeholder feedback responses shared with TAC at meetings,
in Teams and in Appendix
• Working IRP data posted to Teams
• Virtual IRP meetings on Teams, in person available for full day
meetings
• Final TAC presentations, meeting notes and recordings posted
on IRP page
2

Appendix A
Virtual TAC Meeting Reminders
• Please mute mics unless speaking or asking a question
• Raise hand or use the chat box for questions or comments
• Respect the pause
• Please try not to speak over the presenter or a speaker
• Please state your name before commenting for the note taker
• This is a public advisory meeting — presentations and comments will be
documented and recorded
3

Appendix A
Integrated Resource Planning
The Integrated Resource Plan (IRP):
• Required by Idaho and Washington* every other year
— Washington now requires IRP every four years and update at two years
• Guides resource strategy over the next twenty years
• Current and projected load & resource position
• Develop alternative load/customer forecasts
• Resource strategies under different future policies
— Generation resource choices
— Energy efficiency / demand response
— Transmission and distribution integration
— Avoided costs
• Market and portfolio scenarios for uncertain future events and
issues
4

Appendix A
Technical Advisory Committee
• The public process piece of the IRP — input on what to study, how
to study, and review of assumptions and results
• Wide range of participants involved in all or parts of the process
— Ask questions
— Always looking for help with soliciting new TAC members
• Open forum while balancing need to get through topics
• Welcome requests for studies or different assumptions.
• Available by email or phone for questions or comments between
meetings
5

Appendix A
Todav's Agenda
8:30 Introductions, John Lyons
8:45 CEIP Update, Kelly Dengel
9: 15 TAC Process and Methods Proposals, James Gall
9:45 PLEXOS Overview and Back Cast Analysis, Mike Hermanson
10:45 Break
11 :00 Available Resource Options Discussion, Lori Hermanson
11 :30 Work Plan, John Lyons
12:00 Adjourn
6

Appendix A
Clean Energy Implementation Plan
Biennial Report Update
September 26, 2023 — IRP TAC Meeting

Appendix A
Agenda
■ CETA/ CEIP Background
■ CEIP Biennial Update:
■ Energy Supply Specific Actions
■ Customer Benefit Indicators
■ Energy Efficiency & Demand Response Specific Actions
■ Named Communities Investment Fund
■ Public Participation
■ Conditions
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Appendix A
CETA / CEIP Background
Clean Energy Transformation Act
i (CETA) Law — May 2019
Clean Energy Implementation Filed October 1, 2021, for 2022-2025 compliance period
Plan (CEIP) — Every 4 Years
Clean Energy Progress
Report — Annually Filed June 29, 2023, for 2022 compliance period
■ -
Biennial CEIP — Every Two Years, To be filed November 1, 2023
Except where a CEIP is required
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Appendix A
Energy Supply Specific Actions
Washington Clean Energy Targets
100
■Clean Energy Target
90 ■Available Clean Generation 83.5
G 80 76.7
J 71.6
70 66.0
62.5
(D 60 55.0
0 50 47.5
(D 40.0
v 40
L
d 30
20
10
0
2022 2023 2024 2025
Notes:
1) Available generation through July 1, 2023, is actual generation;
2) Beyond July 1, 2023, assumes normal weather conditions;
3) Excess generation/ environmental attributes may be sold to reduce customer cost burden.
All excess 2022 environmental attributes were sold.
4 -
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Appendix A
Energy Efficiency & Demand Response Specific Actions
■ Demand Response Pilots for 2024-2025
■ Small Business Lighting Direct-Install Program •
■ Avista-Spokane Tribe Energy Partnership `
■ Low Income Weatherization & Deferred Maintenance Pilot I'
■ Named Communities Investment Fund
https://www.myavista.com/energy-savings/rebate-overview
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Appendix A
Customer Benefit Indicators
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ao o
Affordability Energy Security Access to Environmental Community Public Health
& Resilience Clean Energy Development
Participation in Energy Availability Methods/Modes of Outdoor Air Quality Named Community Employee Diversity
Company Programs Outreach & Clean Energy
Households with Communication
Energy Generation Greenhouse Gas Supplier Diversity
High Energy Location Emissions Investments in
Burden Transportation Named
Residential Arrears Electrification Communities Indoor Air Quality
& Disconnects
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Appendix A
Named Communities Investment Fund
■ Specific action dedicated to the $2M $1 M
equitable distribution of energy , , - - nt Investments in
•
and non-energy benefits and Ener Efficiency Distribution Resiliency
reduction in burdens to Named
Communities $1 M $500,000
Incentives & Grants Outreach &
Cust• , Parties Engagement
■ Funding is limited to 1 % of retail
revenue or - $5.0 million annually
$500000
Other Projects, • •
or Initiatives
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Appendix A
NCIF Application 'Ard,,.
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■ Open to government/community/non-profit
n Proposal
t aniza
agencies and organizations i
Welcome Page Contact Information Organization
Information
Proposal Information
■ Establish a user ID and password *Project Name
*Requested Cash Amount
*Date Funds Needed MM/DDNYYY
*Project Start Date MMIDDIMv
■ Information about the applicant and proposal *Project End Date 'JM/DDNYYV
*Total Project Cost
*What is your organization's mission
statement and purpose?
■ Application is open continuously
(4000 character maximum)
*Project Overview File Please provide a project overview.
es your
■ Award decisions communicated within 45 *Whataretionh the pesic outcomvewith
organization hopes to achieve with
this grant and how will you measure
the outcomes?i?)
days o submission (4000 character maximum)
*Named Communities(?) What named communities will benefit from this project?
https://www.cybergrants.com/pis/cybergrants/guiz.display question?x gm id=5440&x quiz id=11888
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Appendix A
Equity Advisory Group's NCIF Prioritization
- • 19 EAGPrioritized Initiatives
1 Focus efforts on improving energy efficiency (and EE awareness/education) for schools, community
centers, and other places where Named Communities spend time
1 Focus efforts on improving energy efficiency for Spokane Tribe partners
2 Improve energy efficiency in multi-family and mobile home communities
3 Increase tree canopy and shade in Named Communities (consider tradeoffs with solar)
3 Increase access to energy efficient products and appliances for Named Communities
4 Increase awareness of and engagement in energy efficiency programs while also meeting whole-house
needs through community-based partnerships and referrals to services
5 Set aside funds to match for energy efficiency grant applications for community organizations and tribal
partners (could have higher feasibility)
6 Focus efforts on improving energy efficiency for community members without stable housing (consider
including with other initiatives)
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Appendix A
NCIF Requirements
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�o p
Pro osal assessments include. Affordability Energy Access to Environmental Community Public Health
p Security & Clean Energy Development
Resiliency
■ Serving Named Communities
Customer Benefit Indicators
Participation in Company Programs
■ Equity Areas Number of households with a high energy burden
Availability of Methods/Modes of Outreach & Communication
Transportation Electrification
Named Community Clean Energy
■ Customer Benefit Indicators Investments in Named Communities
Energy Availability
Energy Generation Location
Outdoor Air Quality
Greenhouse Gas Emissions
Employee Diversity
Supplier Diversity
Indoor Air Quality
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Appendix A
Named Communities Investment Fund Projects
Energy Efficiency Distribution
■ Health & Safety for Mobile Homes ■ MLK Center — Solar & Battery Kids Making Sense — Air Monitors
■ EE for Affordable Housing Storage
■ EE for Homes in Malden, WA ■ Town of Malden — Solar & Ground
■ Lincoln County Fairgrounds Lighting Source Heat Pump
■ Spokane Tribe Building Energy Audits
■ EE for Spokane Tribe Buildings
EngagementOutreach & •
■ Public Participation Plan ■ Medical Battery Back Up Pilot
■ NCIF Online Application ■ Christ Kitchen
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Appendix A
Public Participation Updates
Avista's Public Participation Plan was filed May 1 , 2023
dam—
Plait ■ Mitigate public participation barriers
■ Implement meaningful strategies to engage all
customers including vulnerable populations and
highly impact communities,
■ Ensure the equitable distribution of energy
and non-energy benefits
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Appendix A
Public Participation Updates
■ Multi-Language Strategy
■ CEIP Newsletter
■ Public Comment Form
■ Frequently Asked Questions & Answers
■ Public Participation Meeting
■ Equity Advisory Group (EAG)
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Appendix A
Conditions
38 Conditions across 11 categories
■ Interim & Specific Targets
■ Baseline Conditions
■ Specific Actions
■ Demand Response
■ Distributed Energy Resources & Distribution
Planning
■ Energy Efficiency
■ Customer Benefit Indicators
■ Public Participation & Equity Advisory Group
■ Incremental Cost of Compliance
■ Integrated Resource Plan
■ Cost Recovery
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Appendix A
TAC Biennial CEIP Review
■ Post on I RP Teams site October 1
■ Deadline for comments/questions October 13, 2023
Contact Kelly Dengel, Kelly.denqelC@_avistacorp.com
■ Include comments/questions in filing Biennial CEIP November 1 , 2023
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Appendix A
Thank
www.myavista.com/ceta
ceta(@-avistacorp.com
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Appendix

Appendix A
CEIP Conditions
Condition 1 Once the Commission has adopted final "use" rules in Docket UE-210183, in its Clean
Energy Implementation Plan (CEIP) docket, if different than Table 2.1 on page 2-3 in the
CEIP, Avista shall update its CEIP to reflect the percentage of retail sales of electricity
supplied by non-emitting resources and renewable resources in 2020 within 30 days.
Condition 2 Avista will apply Non-Energy Impacts (NEIs) and Customer Benefit Indicators (CBIs) to all
resource and program selections in determining its Washington resource strategy, in its
2023 Integrated Resource Plan (IRP) Progress Report and will incorporate any guidance
given by the Commission on how to best utilize CBIs in CEIP planning and evaluation.
Avista agrees to engage and consult with its applicable advisory groups (IRP Technical
Advisory Committee (TAC) and Energy Efficiency Advisory Group (EEAG)) regarding an
appropriate methodology for including NEIs and CBIs in its resource selection.
Condition 3 Regarding transparency of resource acquisitions, Avista will provide an update at its next
IRP TAC meeting following the acquisition, of any material demand-side resource
acquisition or utility scale resource acquisition with a term longer than 2 years.
Condition 4 While inclusion in the CEIP could factor into a prudence determination, Avista agrees not
to rely solely on the 2021 CEIP to justify prudence of utility scale renewable resource
acquisitions made on or after January 1, 2022. While the CEIP may include specific
actions Avista may take to comply with CETAs clean energy targets, prudence
determinations of utility scale renewable resource acquisitions will be made through the
general rate case process.
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Appendix A
CEIP Conditions
Condition 5 In its 2023 Biennial CEIP Update and in future CEIPs, Avista will include descriptions of
quantitative (i.e., cost based) and qualitative (e.g., equity considerations) analyses that
support interim targets to comply with the Clean Energy Transformation Act's (CETA) 2030
and 2045 clean energy standards.
Condition 6 In its 2023 Biennial CEIP Update and in future CEIPs, Avista will include quantitative and
qualitative risk analysis, if risk is used to justify deviating from the lowest reasonable cost
solution that complies with CETA.
Condition 7 Avista commits to the following minimum Interim Renewable Energy Targets for the 2022-
2025 CEIP implementation period:
Year Interim Target
2022 40%
2023 47.5%
2024 55%
2025 62.5%
Condition 8 Avista in its IRP resource selection model for the 2023 IRP Progress Report will give the
model the option to meet CETA goals with a choice between an Idaho allocated existing
renewable resource at market price (limited to Kettle Falls, Palouse Wind, Rattle Snake
Flats Chelan PUD purchase contracts 2 & 3) or acquiring a new 100% allocated
Washington renewable resource for primary compliance. Further, the model will have the
option to acquire new 100% allocated resource, market REC, or Idaho allocated REC (at
market prices) to meet alternative compliance.
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Appendix A
CEIP Conditions
Condition 9 Avista agrees to update and expand its Vulnerable Populations areas within its 2023
Biennial CEIP Update taking into account the additional criteria developed by the EAG
and Energy Assistance Advisory Group (EAAG) and to ensure updates are in line with the
definition of Vulnerable Populations outlined in RCW 19.405.020(40). Additional work is
needed to develop a consistent methodology and data source identification. This
additional work is primarily related to identifying a consistent data source(s) to evaluate
each characteristic and then overlaying it onto a map.
Condition 10 By December 1, 2022, in collaboration with its EAG and EAAG and per WAC 480-100-
640(5)(a) and (c), Avista agrees to identify at least one specific action that will serve a
designated subset of Named Communities, to be funded by the Named Communities
Investment Fund, and to identify and track all CBIs relevant to this specific action. The
location identified for the specific action will be at the granularity of the designated Named
Communities subset.
Condition 11 Avista will share and present the results, analysis, and conclusions of its pricing pilots with
its EEAG, EAAG, and IRP TAC following the completion of the third-party evaluator's
review of the pilots. If Avista develops pricing programs based on the results of its pricing
pilots, it will work with its advisory groups to develop program targets.
Condition 12 When the Department of Commerce adopts a permanent standard for grid-enabled water
heaters in WAC 194-24-180, Avista will develop a pilot demand response program. Avista
will work with its EEAG on the pilot program implementation timing and how to incorporate
results into its planning efforts.
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Appendix A
CEIP Conditions
Condition 13 Avista will initiate its Distribution Planning Advisory Group (DPAG) no later than the end of
2022, and it must invite all existing advisory groups to participate in the new group. Avista
acknowledges that stakeholders have limited resources and will consult between existing
advisory groups and stakeholders regarding streamlining.
Condition 14 Avista will include a Distributed Energy Resources (DERs) potential assessment for each
distribution feeder no later than its 2025 electric IRP. Avista will develop a scope of work
for this project no later than the end of 2022, including input from the IRP TAC, EEAG, and
DPAG. The assessment will include a low-income DER potential assessment. Avista will
document its DER potential assessment work in the Company's 2023 IRP Progress
Report in the form of a project plan, including project schedule, interim milestones, and
explanations of how these efforts address WAC 480-100-620(3)(b)(iii) and (iv).
Condition 15 Avista agrees to evaluate the need for a targeted DER Request for Proposals (RFP) if a
need is demonstrated as part of its DPAG process.
Condition 16 Avista will update its energy efficiency (EE) target no later than the 2023 Biennial CEIP
Update, when the next Biennial Conservation Plan is due on November 1, 2023, based on
continued discussion of its residential EE savings target and programs with its EEAG.
Discussion will include program design elements which could promote more participation
and additional uses of the Named Communities Investment Fund, if approved.
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Appendix A
CEIP Conditions
Condition 17 As part of its CBI Participation in Company Programs, Avista agrees to track the number
of residential appliance and equipment rebates provided to customers residing in Named
Communities and the number of residential rebates provided to customers residing in
rental units and commits to work to expand data availability during this CEIP period. Avista
agrees to discuss programs to increase the number of participating households in Named
Communities with its EEAG and move forward with feasible programs, if identified.
Condition 18 Avista agrees that the CBI — Number of Households with a High Energy Burden (>6%),
will be separately tracked for all Avista electric customers, Known Low Income (KLI)
customers and Named Communities. KLI customers are defined as those who have
received energy assistance during the prior two years.
Condition 19 Avista agrees that for its CBI —Availability of Methods/Modes of Outreach and
Communications, an additional metric will be identified to track increased availability of
translation services by October 1, 2022. Once identified, a baseline for the metric will be
established and the metric will be reported in the 2023 Biennial CEIP Update.
Condition 20 Avista agrees that for the CBI — Outdoor Air Quality, it will adopt a metric related to
decreased wood use for home heating in its 2023 Biennial CEIP Update. The data
included in this metric may include the data from the Company's wood stove replacement
program offered in partnership with the Spokane Clean Air Agency, as well as data from
other sources. Avista will work with its EEAG and other appropriate advisory groups to
identify and evaluate additional wood stove usage metrics to be proposed in the 2023
Biennial CEIP Update, if applicable.
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Appendix A
CEIP Conditions
Condition 21 Avista agrees that the CBI — Energy Availability will include a metric related to the
frequency of customer outages for all customers, Vulnerable Populations, and Highly
Impacted Communities.
Condition 22 Avista agrees to add the following CBI and metrics related to Energy Security:
CBI: Residential Arrearages and Disconnections for Nonpayment Measurement 1.
Arrearages and 2. Disconnections
Condition 23 Avista must formally present and discuss any Joint Advocate or other stakeholder
proposed CBI that was not included in the Company's filed CEIP and the final Commission
approved CEIP with conditions, to its advisory groups, customers, and other interested
stakeholders at a CEIP Public Participation Meeting(s) and at a separate joint advisory
group meeting(s), to include the EEAG, EAAG, and EAG. Following these discussions
and careful consideration of the feedback received, Avista will propose an updated set of
CBIs and associated metrics in its 2023 Biennial CEIP Update.
Condition 24 Avista must engage collaboratively with its advisory groups (EAG, EEAG, EAAG) to
create a metric for Indoor Air Quality and submit formal metric for evaluation no later than
in its 2023 Biennial CEIP Update.
Condition 25 Avista agrees that in its 2023 Biennial CEIP Update and future CEIPs and CEIP updates,
CBIs will be categorized by statutory benefit area.
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Appendix A
CEIP Conditions
Condition 26 For the CBI — Named Community Clean Energy Avista agrees to eliminate the current
metric on "percent non-emitting renewable energy located in Named Communities," and
instead measure the following in Named Communities: (1) total MWh of distributed energy
resources 5 MW and under; (2) total MWs of energy storage resources 5 MW and under;
and (3) number (i.e., sites, projects, and/or households) of distributed renewable
generation resources and energy storage resources.
Condition 27 Avista's EAG shall not be responsible for the designation of Highly Impacted Communities
and the Company's advisory groups should be facilitated such that this designation is not
under consideration.
Condition 28 Avista will include a publicly available and regularly updated list of its EAG members and
their organization or community affiliations on its website and in future Biennial CEIP
Updates and CEIPs.
Condition 29 Avista agrees that all future EAG meetings will be fully open to the public.
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Appendix A
CEIP Conditions
Condition 30 On or before October 1, 2022, Avista must file with the Commission:
a. A progress report on what actions have been taken since October 2021 to reduce
barriers to public participation (e.g., steps taken to reduce barriers including but not limited
to non-English speaking customers).
b. An update to the Company's customer engagement plan it will implement during the
2022-2025 timeframe and provide a progress report of this plan in the 2023 Biennial CEIP
Update.
Condition 31 On or before October 1, 2022, Avista agrees to provide in its CEIP docket a report on the
changes regarding the EAG Equity Lens Sessions discussed and made with the EAG in
March 2022, the facilitator, and the Company.
Condition 32 Avista will participate in any further discussions and/or workshops regarding incremental
cost calculations and incorporate any changes necessary to their methodology.
Condition 33 Avista agrees to model a scenario in the 2025 Electric IRP meeting the minimum level of
primary compliance requirements beginning in 2030 that will create the glide path to 2045.
If the results of this modeling differ from the Company's PRS and Clean Energy Action
Plan, it must explain why.
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Appendix A
CEIP Conditions
Condition 34 For its 2023 IRP Progress Report, Avista commits to reevaluate its resource need given
acquisitions the Company has made since its 2021 IRP (e.g., Chelan PUD hydro slice
contracts) and include those proposed changes in its 2023 Biennial CEIP Update.
Condition 35 Avista recognizes that not all CBIs will be relevant to resource selection (for example,
some CBIs pertain to program implementation). For its 2023 IRP Progress Report, and
future IRPs and progress reports, Avista should discuss each CBI and where the CBI is
not relevant to resource selection, explain why.
Condition 36 For its 2023 IRP Progress Report, Avista will:
a. At the September 28, 2022, Electric IRP TAC meeting, present draft supply side
resource cost assumptions, including DERs. The Company commits to revising said cost
assumptions if TAC stakeholder feedback warrants changes. Avista will update its 2023
Electric IRP Work Plan (UE-200301) to reflect the date of this TAC meeting.
b. Use the Qualifying Capacity Credit (QCC) for renewable and storage resources from
the Western Power Pool's Western Regional Adequacy Program (WRAP), if available, or
explain why the WRAP's QCCs are inappropriate for use.
c. Update its load forecast to include the baseline zero emission vehicle (ZEV) scenario
from its Transportation Electrification Plan.
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Appendix A
CEIP Conditions
Condition 37 In order to provide a means of recovery of prudently incurred costs associated with
implementing this CEIP and associated conditions, the Company will file a separate
accounting petition to address deferred accounting for such costs until they are reviewed
and deemed prudent for recovery or not by the Commission.
Condition 38 Avista must choose at least two of its current CBIs which it will track for at least five
subsets of Named Communities, at a granularity to be determined by agreement with
Staff, stakeholders, and the Company's Equity Advisory Group. Avista will incorporate
relevant updates in its 2023 Biennial CEIP update.
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'Ad VISTA
IRP TAC Process Change Ideas and Modeling Change Ideas
James Gall
Technical Advisory Committee Meeting No. 1
September 26, 2023

Appendix A
TAC Communication
Propose to use Microsoft Teams for primary TAC communication
• Advantages
— File sharing ease
— Open communication via chat function on files or questions to Avista or other TAC members
— Eliminates email traffic for passive TAC members
— TAC meeting recordings and chat messages are retained
• Avista will still post TAC meetings and slides on website
— Documents/files shared with the TAC will be on Teams
— Only "final" documents will be posted on website
• Avista will direct new interested TAC members to sign up to join the "Teams site"
• TAC meeting invites will come through Teams and email
• Electric and Natural Gas TAC members will have access to both "channels" on Teams

Appendix A
New IRP TAC Teams Site
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Appendix A
WUTC Notice on Electric IRP 's UTC
Washington Utilities
and Transportation
Commission
• Commission is discontinuing its practice of issuing acknowledgment letters for electric utility
I RPs in all cases.
• Under CETA, the CEIP must be "consistent with the utility's long-range integrated resource
plan" and "informed by the investor-owned utility's clean energy action plan," which is
developed as part of an electric IOU's IRP. Therefore, any issues that interested parties may
have related to an IRP can be litigated and decided by the Commission as part of a CEIP
proceeding.
• As part of the Commission's effort to reduce unnecessary administrative burden and
duplicative processes, we are discontinuing our practice of issuing acknowledgment letters
for electric IRPs in all cases.

Appendix A
Action Item Update
• Incorporate the results of the DER potential study • Continue to work with the Western Power Pool's WRAP
where appropriate for resource planning and load process to develop both Qualifying Capacity Credits (QCC)
forecasting. and Planning Reserve Margins (PRM) for use in resource
planning.
• Finalize the Variable Energy Resource (VER) study.
This study outlines the required reserves and cost of • Evaluate long-duration storage opportunities and
this energy type. Results of this study will be available technologies, including pumped hydro, iron-oxide,
for use in the 2025 IRP. hydrogen, ammonia storage, and any other promising
technology.
• Study alternative load forecasting methods, including
end use load forecast considering future customer • Determine if the Company can estimate energy efficiency
decisions on electrification. Avista expects this Action for Named Communities versus low-income.
Item will require the help of a third-party. Further,
studies shall continue the range in potential • Study transmission access required to access energy
outcomes. markets as surplus clean energy resources are developed.
• Investigate the potential use of PLEXOS for portfolio 0 Further discuss planning requirements for Washington's
optimization, transmission, and resource valuation in 2045 100% clean energy goals.
future IRPs. P=

Appendix A
Plexos Introduction
• PLEXOS is a production cost model Why did Avista bring in Plexos?
developed by Energy Exemplar — More sophisticated hydroelectric
• The model benefits from a mixed modeling capability than Aurora
integer-based design — Allows for proper valuation of energy
storage benefits and needs, along with
• Avista plans to use the technology reserve costs associated with VERB
for portfolio modeling in the 2025 due to mixed-integer logic
for resource valuation and market — Capable of modeling transmission
risk analysis system detail
— Potential PRiSM replacement- includes
capacity expansion function
— Potential use for combining power and
natural gas IRPs loin

Appendix A
Load Forecast Update
• Avista has brought on Applied Energy Group (AEG ) to conduct a
long-term forecast of customer loads (Natural Gas & Electric)
• End use load forecast technique to better understand how loads
will change due to electrification potentials
• Forecast will be consistent with DER potential study focusing on
on-site solar and vehicle electrification
• AEG will provide three scenarios (expected case, low, and high )
• Process should enhance demand response and energy efficiency
potential assessments

Appendix A
PRISM Update
• Avista plans to continue to use PRISM in the 2025 IRP
• Avista will test PLEXOS and compare results for potential
replacement in the 2027 IRP
— Why not now?
• Time to build/test models
• Energy efficiency modeling
• Speed
• Testing Natural Gas IRP in PRISM
— Co-optimize natural gas system and electric capacity expansion to
electrification choices are dynamic

Appendix A
Resiliency
• How should we include resiliency? Potential Metrics
— Feeder or customer level seems out of — Seasonal plant & unit (shaft risk)
scope for an IRP — Location fuel source
— Generation sources and delivery seems — Transmission path
plausible — Wildfire risk level areas
• Can resource diversification measure - Load diversity?
resiliency?
• Quantification can indicate risks and could Diversity Measurement Example
lead to different resource choices during 3,000 Generation Charictaristics
acquisition. 2,500 2,473
— Herfindahl — Hirschman Index o 2,000
v
— Measures whether or not a population is too Cn 1,500 1,165
heavily dependent on one component = 1,000
557 ■
• Any other resiliency ideas? 500
0
Generating Unit Facility Fuel Supply

'AI VISTA
PLEXOS Overview and Back Cast Analysis
Mike Hermanson, Senior Power Supply Analyst
Technical Advisory Committee Meeting No. 1
September 26, 2023

Appendix A
Power Supply Modeling in the IRP Process
• Analytical framework to determine the long-run economic and
operational performance of alternative resource portfolios
• Modeling is used to simulate the integration of new resource
alternatives within our existing resource mix, thereby informing the
selection of a preferred portfolio judged to be the most cost-effective
resource mix after considering :
— Risk
— Supply reliability
— Uncertainty
— Government energy resource policies
• Avista utilizes multiple models in the IRP Process:
— Aurora: Electric Price Forecast
— Plexos: Dispatch of resources to meet projected load demands
— PRiSM: Selection of new resources
2

Appendix A
Plexos
• Plexos is a widely used energy modeling software suite designed
for electricity market analysis and power system optimization . It is
used to make informed decisions about energy production ,
transmission , and distribution . Key aspects of the model include :
— Market Simulation: allows users to simulate and analyze electricity markets,
considering various factors such as supply, demand, pricing, and market rules.
This provides insight into market dynamics and energy trading optimization.
— Power System Optimization: optimizes power system operations including
generation scheduling, unit commitment and dispatch. Multiple objectives such
as minimizing cost, maximizing reliability, or reducing emissions can be set as
targets.

Appendix A
Plexos
— Integration of Renewable Energy: Plexos can incorporate renewable energy
sources like wind and solar, assisting planners to assess the impact of variable
generation on the power grid .
— Transmission Planning: It supports transmission system planning and
expansion studies allowing the inclusion of transmission upgrade costs
associated with potential resource additions.
— Hydro Modeling : Storage Hydro is modeled utilizing water inflow and reservoir
sizes. Operational aspects such as scheduled maintenance, forced outages,
minimum flows, maximum reservoir movement are all modeled . This is in
comparison to the monthly energy values utilized in Aurora.

Plexos Implementation of Avista System Appendix
— The Plexos I RP model is a 20-year simulation to meet native load and
contractual obligations with Avista owned generation , contracted
generation , and market purchases.
Avista owned & Market
Hourly Native Load contracted generation g Purchases/Sales
2500 - ) to Native load + contractual
zoo , , ,
obligationsM 0* vim =
iaoa
t generation + market
500 WWWWWWWNWWWWW law !E purchases and sales
1paml every hour
,o I, co Dl o cj N m V N o n co Q1 o H N m V 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 N N N N N N N N N N N N N N N N
Market Purchases are
N Generation considerations include:
• Regular scheduled maintenance and driven by Mid-C hourly price
We are currently working with a consultant on a load forced outages and any transmission
forecast. • Timing and quantity of hydro and constraints
Some considerations include: impact of climate change throughout
• Climate change impacts on load, the planning horizon
• Variability and uncertainty in EV load forecasts • Provision of ancillary
• Penetration of electrification efforts services/reserves
• VER production ,
• Fuel cost

BPA - Lancaster—CCCT Noxon Rapids
Cabinet Gorge
Kettle Falls Noxon
Douglas Biomass/CT I r
�I I
Northeast �I
Boulder Park Rathdrum
ILancaster
Stratford '
Chelan �� Spokane � CdA
Chelan IIIIIIII 1 /
Ifll�ll�li HotSpr s
Columbia01 ✓ \ ("� OA
Basin Hydro �, •, In II II II II Pine Creek
Long Lake I'll ll'I
\ Upper Falls Post Falls
Grant Larson 9-Mile Monroe
Little Falls
enewah
BPAT W Mi C
Palouse
Warden Rattlesnake Wind Thornton
NW
Wind
1
Clearwater
Othello
Clarkston Lewiston Hatwai BPAT-E Wind
Ben n
Adams Talbot Colstrip
Neilson
Solar Legend
Coyote Springs
Run of River
2 Imnaha Market Biomass
Saddle Mtn Hydro
W Load Wind Avista line
PACW IPC Center
I wanI 0 Other line
Coyote Springs 2-CCCT BPAT-S Storage Solar Interface*
Hydro
*An interface is a group • Service I J1 Combined �I Simple
COB of lines that is limited to
a total flow less than the Point I� Cycle CT Cycle CT
Plexos Representation of Transmission System & Generation sum of all individual
max line flows

Plexos Implementation of Avista System Appendix
© Object . Ir R0
®PLEXOS Home Window Visualizer Noxon Rapids 1 Themes
O •_w Q ® Cut g Paste- ti` V �� O AL C3 C -'
/r' a 2
®
New Or Connect Save Copy Excel XML Find Changes Carve Overview Property Column Execute Build Config Settings
Replace Out -_ - Size
File Clipboard Edit Fill Database Options
8 Avista_Base_Hydro Model(9.100 1104)_base_model 674_23 volume X
System Simulation / Q Noxon Rapids 1 Objects Memberships I Properties
System IR Template Category Template I Heat Input Fuels Start Fuels Head Storage Tail Storage Power Station Nodes T I Maintenances
Electric/r Eleic 6 Heat Input I Clark Fork River Hydro Noxon Cabinet AVA_Sys Avista
r Generators • IS Fuels Results
/ r Natural Gas Generators Hydro
/ r Clark Fork River 1;Start Fuels
O Cabinet Gorge 1 •IS Head Storage
Q Cabinet Gorge 2 Li 4 Noxon
1 IH,a , Record 1 A 1 1 MIN
d Cabinet Gorge 3 •,s Tail Storage Collection Parent Object Child Object Property Value Data File Units Band Date From Date To Timeslice Action Expre
a Cabinet Gorge 4 f Cabinet 1 Generators System Noxon Rapids 1 Units 1 - 1 =
O Naamn Rapids 1 raj Power Station Generators System Noxon Rapids 1 Max Capacity 108.4
O Noxon Rapids 2 / re Nodes Generators System Noxon Rapids 1 Min Stable Level 45.7 0 Rrginnal
Q Noxon Rapids 3 X AVA_Sys Generators System Noxon Rapids 1 Load Point 457 R,rw I ir, 5ra.m �•. r.,,.
Q Noxon Rapids 4 / 1i Companies Generators System Noxon Rapids 1 Load Point 90.3 uT k1*11A / In re— Y
Q Noxon Rapids 5 ay Avista Generators System Noxon Rapids 1 Load Point 1084 SeKdae iv to Genrnvs Gerwator Category'Clark Fork River'
1 •Spokane River IS Maintenances Generators System Noxon Rapids 1 Rating Factor 95 _�1/F Pi g I IJ�.NrbN G.
6erentars
/ r other ag Capacity Markets Generators System Noxon Rapids 1 Efficiency Base 105 0
■COA rak ai,er
1 0 Mid C 4 I Generators System Noxon Rapids l Efficiency Incr 157.3 1Da! —Y 2021 4"2021 1dy 2021 slptrm61r 2021 rvrrmher 7021
0 r Fuels Search P ,. r OCabwnt4vret
Generators System Noxon Rapids 1 Efficiency Incr 157.3
0 r Emissions / O Noxon Rapids 1 Generators 5 -'I v— I O,:tudw7c 2 550
System Noxon Rapids 1 Efficiency Incr 300.=
0 r Storages /❑� aGenerators Generators System Noxon Rapids (Units Out 1 34.RraF r OC,hmt GvV3 500
0 r waterways / ❑r' 0 Settings 22:1 1,12CG�1A1 -_O I Q C&-0", 450
Generators System Noxon Rapids 1 Outage Rating — -
- I ONo.an R,arerl r Power Stations ❑� Max Heat Rate Trenches Generator.C^nstraintz Noxon Rap' 1 Generation Reserves Generation Coefficient -0.01 - 400
0 r Physical Contracts - ❑W Formulate Non-convex Reserve.Generatom Frequency sponse Noxon Rapids Max Response a "'" '�"r.- �sA�L" I ON.-Rapd,1 1i
K350
Search P / ❑� Production Reserve.Generators Non Sp'nn g-Gen Noxon Rapids 1 Max Response IOC �1p�� _ p� v O Naod+Nlogs S
/ r Liss, ❑� Unit Rese—Generators Non Spin ng-load Noxon Rapids 1 Max Response IOC I '
• (mraav �QNOan Rrrd,, l• •
Action ❑� A Max Capacity Rese—Generators Regulati Noxon Rapids 1 Max Response 10C -.-erlion + 1 I`O NarmRae,s 1250 �� 1
Q Min Stable Level Reserve.Generators Regulat'n Down Noxon Rapids 1 Max Response IOC 1-19 ! K I
CS2 N Min ttahle Fartnr 1 --- I u■SpJxre Nv'r 200
❑� Reserve.Generators VERB Noxon Rapids 1 Max Response Factor 300 -` "rr ar00w r
4 I I J 11 cad- 150 I I
Lisp c t Filter,OR ,rrh P yap+ y,AN 1 I
0 Ismet IOU
1`11
Ready ceesrxr C. 5 I I n r F.a 50
q•.x rn as+au + C ,L.manage,
W.Rr e-,x S + C /p■wwiia M -sry202t Api I Ny 2021 Sep-w 2o2, rNr be,2021
System Components Properties of each component I�aphKoilcorolrn
an4a Mai + L 17V•reurves BN�RwVi!a..raa rw;i,wo,Rw�•ra.�m.tVw7�r a,s�v.+a..•mPAM I�N®rw/a.w....•1w
10TrlaslnnNn .rbwv.roe,s--pro,
wu Suub, I p P—ha0 INa0

Plexos Implementation of Avista System Appendix
— Modeling challenges
• Model has perfect foresight
• Difficult to capture the myriad of constraints on a hydro storage system.
— For example, management of a reservoir that is used for recreation and has residences on
much of the shoreline
• Balance between model complexity and runtimes
• Difficult to capture the dynamics of trades that happen at different time steps, for
example, day ahead, hour a head, EIM.
• How to integrate forecast error in modeling
— Model will almost always have lower production cost than actual .

Appendix A
2021 Backcast - Plexos vs Actual Dispatch
• To verify that our model represented our system operation and
dispatch we utilized 2021 inputs and compared the output of
Plexos to actual 2021 data . In the model we utilized :
— 2021 Hourly Load
— Hourly hydro inflows
— Hourly run-of-river generation
— Hourly Mid-C Electric Price
— Daily Gas Prices
— Hourly renewable generation
— Actual scheduled and forced outages
— Reserves, including FRR, Non-Spin , Reg up and down, and VERs

Appendix A
2021 Backcast Dispatch Comparison (aMW)
Facility Difference Production Cost Comparison
Noxon Rapids 179.8 178.5 -1.3 0.96% difference between mark to
market of generation subtracting fuel
Cabinet Gorge 113.8 112.4 -1.4 costs
Long Lake 54.6 54.4 -0.2
Little Falls 23.7 23.2 -0.5
Mid Columbia 135.7 138.9 3.1
Coyote Springs 2 175.2 172.2 -2.9
Lancaster 207.8 205.2 -2.6
Rathdrum 20 18.1 -1.9
Boulder Park 7.9 7.7 -0.2
Kettle Falls GS 37 37.1 0.1
Kettle Falls CT 0.4 0.5 0.1
Colstrip 173.7 174.1 0.4
TOTAL 1,130 1,122 -7

Appendix A
2021 Backcast Dispatch Comparison
Average Generation: Average Generation:
Plexos 178.5 aMW Plexos- 112.4 aMW
Actual 179.8 aMW Noxon 2021 Hourly Generation Comparison Actual-113.8 aMW Cabinet 2021 Hourly Generation Comparison
600 300
500 250
400 200
300 150
200 100
100 50
0 0
�r VCO I7 �� "NjNN n O � � ooNo L�O�ON IN-N
IN I c INI�N N N � N N N NMI I IM< � IrN� wVrMaoN oCON Iv � Ml l O�� I �� O � �l ao� � 1,41 v I I I I I IO l l l � l l l l I INN
I
--- NNNMMMMNrtItLW� (0(0CDrrrCCMCO0M0 — NNMMMVlzrvLU� MMMrrrODwODa,M0
-100 -50
—Plexos —Actual —Plexos —Actual

Appendix A
2021 Backcast Dispatch Comparison
Average Generation: Average Generation:
Plexos-54.4 aMW 2021 Long Lake Hourly Generation Comparison Plexos-23.7 aMW 2021 Little Falls Hourly Generation Comparison
Actual-54.6 aMW Actual-23.2 aMW
100 40
35
80
30
60 25
3 3
20
ao
is
20 l0
s
0
S OD IANO>r�NO(O(()NO(ON OCO Q70 f-��OD t Oca n7�n7�Ot�OIO cm Ce)0(0 0 f._(nN0
I I�N N I� N Iv N 1 I�N M I�N N I� N I� N(h I; N N I�V N I 1�N a1 I�N N I� 'co
I I IN I I I('� I I I� I I I(n I I I(D I I I� I I I Ion I I 10 1 1 10 0 I IIN I I I N oo ,D e -I a) n Ln Ln M ti m 'D a N o oo ID v � m n 0n M N oo wD M N M N a N o oo w a N O r u� m of r` ui
MMM V V (()(lI(D (O(O co ��f� CO CO CO W OO��OOO��� I I rl N I rl N rl N N rl N M rl N I rl N rl rl N I rl rl N r N N I' N M I.--� N
e-I e-I �I�4 N N NI N m MI MI M a al � LI� w � n nl^I^ 00
00 oo oo m mI m m � O 0 p .y ti .N- N N
-20 _5 ei ei ei ei a ei ei
-Plexos -Actual -Plexos -Actual

Appendix A
2021 Backcast Dispatch Comparison
Average Generation: Average Generation:
Plexos- 135.7 aMW 2021 Mid Columbia Hourly Generation Comparison Plexos-172.2 aMW 2021 Coyote Springs 2 Hourly Generation Comparison
Actual-138.9 aMW Actual-175.2 aMW
250
350
200 300
250
150
200
100 150
100
50
50
0 0
S CO(ONM LO O)CO(ON O(ON O(O CO01__V�00 V�O)(OM Oh V marl-V SOD V�W(ONO(O CO O(OM O 1-(ONO(O BCD In CO O COS�00 (ON CD 0(M—OIn MO r��O OMOM(O—M CO(M—f-�N MCO��Cq lONO r C—M(O
I I�N N I� N I� N I I�N CO I�N N I� N 1� N M I�N N I� N I I�N M I�N N I� N I I�N CO I�N N 1�N M I�N N I�N N 1� N I� N I I—N M I�N N 1�N N I� N I— N
N NININIM MIMIMIv V t't Nt(n LOILOILOI(0(DI(DI(0Ir rlrlrlrlOD OD OD OD rn�1M1010 O ololol�;I;I;I�NININI �I�I�IN NININIM MICO Cl) �I�I�ILO LO LO LO(o(0I(0ICDIr rlrlrlao ao OD 01) SIC',01 ol0l0l- zI;z;z NININI
—Plexos —Actual —Plexos —Actual

Appendix A
2021 Backcast Dispatch Comparison
Average Generation: Average Generation:
Plexos-207.8 aMW 2021 Lancaster Hourly Generation Comparison Plexos-18.1 aMW 2021 Rathdrum Hourly Generation Comparison
Actual-205.2 aMW Actual-20.0 aMW
180
300
160
250 140
200 120 —
� 100
150
� 80
100 60
40
50
20
0
70h NO LL) CO I�MO f�N OLL) ODOR OD V�f�M OtOM O(O NOS�f�"0�(O MO(O NON Na0��f� *,o MO(O Q
I INN I INN 1�NN I INN I��NM IvNN I ITNN I;�NM I��N I INN I��NM INN
I I IN N I I IM I 1 1a I I I� I I I 1� I I Inn I 1 10 I I 1 10 1 1 10 O I I I� I I I IN I I I 7 O M O I.a Cl)M CO M O CO N O(O CO O CO CO O CO CO O O Cl)O(O M O CO M O(O N O O N O(O M O(O N O t0 M O(O M O CO
--- NNN MMM 77a (O MM LO (O(O(O I._I�h OOMm OOO—�OOO������NNN 1 1�NN I�_N I I—NM I��N I��NM I��N I��NM I��N I INN INN I 1�NN INN
I I IN I I IM M I I Iv I I I(O I I I I(o I I I� I I I log I I 10 O I I 10 I I 1� I I IN I I I
-50 -20 NNN MMM (O(O(O(O w(O(O rr P`t` CO CO O 000 000 NNN
—Plexos —Actual —Actual —Plexos

2021 Backcast Reservoir Elevation Comparison Appendix
2021 Noxon Reservoir Elevation Comparison 2021 Little Falls Reservoir Elevation Comparison
2332.0 1362.0
2331.0
co 2330.0 1361.5
23216 AL
9.0 por
a�
w 2328.0 J121361.0
o W
Z 2327.0
I t 2326.0 N 1360.5
a�
2325.0
2324.0 1360.0
2323.0
2322.0
1359.5
^\4P ^�ti
-Plexos Elevation(estimated) -Actual Elev -Plexos Elevation(estimated) -Actual
2021 Cabinet Gorge Reservoir Elevation Comparison 2021 Long Lake Reservoir Elevation Comparison
2175.0 1540.00
2174.0
2173.0 1535.00 -
0 2172.0 c
a i 2171.0 > 1530.00
W �
2170.0 LL
Z o
2169.0 1525.00
2168.0
2167.0 1620.00
2166.0
2165.0
.� ^ ^ ^ .� 1515.00
yoti Doti Doti yoti yoti yoti tioti y oti yoti �yoti Iyo'�
-Plexos Elevation(estimated) -Actual -Actual -Plexos Elevation(estimated)

2021 Backcast Reservoir Elevation Comparison Appendix
2021 Grant PUD Avista Storage 2021 Douglas PUD Avista Storage
1200 900
800
1000
700
800 600
t
t 500
600 3i
2 400
400 300
200
200
100
0 0
ry� ry� ry� p p ry� 'p ry� �� ��
,y0 ,y0 ,y0 ,LO ,ti0 ,ti0 0 ry0 ,y0 �O �O 1
10 �O ,LO �O ry0 �O ,LO O O �O`1' ry0 �O ry0
-Grant Storage Plexos -Grant Storage Act -Douglas Storage Plexos -Douglas Storage Act
250 2021 Chelan PUD Avista Storage Comparison
zoo
150
100
50
0
oti� oti^ oti� oti^ oti^ oti^ O`t^ Ot^ oti^ oL^ oti� oti^
-Chelan Storage Plexos -Chelan Storage Act

Appendix
VISTA
�y
Available Resource Options
Lori Hermanson
Technical Advisory Committee Meeting No. 1
September 26, 2023

Appendix A
Turbine Resource Options
Peakers Baseload
• Simple Cycle Combustion Turbine Combined Cycle CT (CCCT)
(CT) — 312 MW (1 x1 w/DF)
— CT Frame
— 180 MW (2 units)
Fuels
• Reciprocating Engines • Natural gas
— 185 MW (10 units) • Renewable natural gas
• Hydrogen
• Ammonia
• Synthetic natural gas
-Natural gas turbines are modeled using a 30-year life with Avista ownership
-Will continue to evaluate non-natural gas fueled resources in Washington and all fuel types in Idaho
-Will continue to evaluate potential upgrade opportunities on existing facilities
2

Appendix A
Renewable Resource Options - Solar and Wind
All Purchase Power Agreement (PPA) Options
Solar Wind
• Residential (6 kW AC) — w/ and w/o battery
• Commercial (1 MW AC) — w/ and w/o
• Wind (100 MW)
battery • Montana wind (100 MW)
• Fixed PV Array (5 MW AC) — w/ and w/o • Offshore wind (100 MW)
battery — Share of a larger project
• Single Axis Tracking Array
— With and w/o 100 MW 4-hour lithium-ion
battery
— With 100 MW 2-hour lithium-ion battery
— With 50 MW 4-hour lithium-ion battery
3

Appendix A
Other "Clean " Resource Options
• Geothermal PPA (20 MW)
— Off-system
• Biomass (58 MW)
— i.e. Kettle Falls 3 or other
• Nuclear PPA ( 100 MW)
— Of-system share of a mid-size facility
• Fuel Cell (25 MW)
4

Appendix A
Storage Technologies
Lithium-Ion Other Storage Options
• Assumes: 86% round trip efficiency (RTE), 15- • Assumes Avista ownership
year operating life • 25 MW Vanadium Flow (70% RTE)
• Assumes Avista ownership — 4 hours (100 MWh)
• 5 MW Distribution Level • 25 MW Zinc Bromide Flow (67% RTE)
— 4 hours (20 MWh) — 4 hours (100 MWh)
— 8 hours (40 MWh) • 25 MW Liquid Air (65% RTE)
• 25 MW Transmission Level 8 hours (400 MWh)
— 4 hours (100 MWh) • 100 MW Iron Oxide (65% RTE)
— 8 hours (200 MWh) — 100 hours
— 16 hours (400 MWh) • 100 MW Pumped Hydro
— 24 hours (2,400 MWh)
• 100 MW Pumped Hydro
— 10 hours (1 ,000 MWh)
5

Appendix A
Resource Option Currently Being Researched
• Carbon capture and storage
• Fusion reaction (no real costs yet)
• Organic Solid Flow energy storage — proprietary nonflammable
mixture of solid and water-based electrolytes
• Molten salt heat storage (using existing steam turbines)
• New hydro
• Regional hydro PPAs
• Others?
6

Appendix
VISTA
�y
2023 IRP Work Plan
John Lyons, Ph.D.
Technical Advisory Committee Meeting No. 1
September 26, 2023

2025 IRP Work Plan Appendix
• IRP regulations require an IRP to be filed in Idaho by June 1 ,
2025 , and an IRP in Washington on January 1 , 2025.
• Work Plan shows process and timing of key IRP events
• Overview discussion
• TAC meetings and topics
• Document outline by chapter
• Timeline of major assumptions — market price assumptions and
forecasts, third party studies , study requests from TAC, etc.
z

2025 11 ' P Work Plan - Modeling Appendix
• PLEXOS will be used to model resource dispatch, resource option
valuation , and market risk analysis.
• PRiSM will be used for resource selection .
• Continue to use Aurora for electric market price forecasting , will evaluate
other options for the 2027 Progress Report/IRP.
• Applied Energy Group (AEG) will develop energy efficiency and demand
response potential studies, along-term energy and peak load forecast using
end use techniques, and a distribution energy resource (DER) potential
study
• Intend to use generic resource assumptions from a variety of sources based
on likely generation sites
3 gum

Tentative 2025 Electric IRP TAC Schedule Appendix
• TAC 1 (Tuesday, September 26, 2023): Washington CEIP Biannual Update; available
resource options discussion; PLEXOS overview and backcast analysis; TAC feedback on
changes to process methods and assumptions; and 2025 IRP Work Plan IRP Process
Review.
• TAC 2 (March 26, 2024): Natural gas market overview and price forecast; wholesale
electric price forecast, Variable Energy Resource Integration Study results; future climate
analysis update; and TAC scenarios feedback.
• TAC 3 (April 2024): Economic forecast and five-year load forecast; long run forecast
(AEG), Conservation Potential Assessment (AEG); Demand Response Potential
Assessment (AEG); and reviewed planned scenario analysis.
4

Tentative 2025 Electric IRP TAC Schedule Appendix
• TAC 4 (May 2024): IRP Generation Option Transmission Planning Studies; Distribution
System Planning within the IRP & DPAG update; transmission and distribution modeling in
the IRP; Load & Resource Balance and methodology; and new resource options costs and
assumptions.
• TAC 5 — Technical Modeling Workshop (June 2024): PLEXOS tour, PRiSM tour, and
New Resource Cost Model.
• TAC 6 (July 2024): Preferred Resource Strategy results, Washington Customer Benefit
Indicator Impacts, resiliency metrics, portfolio scenario analysis, market risk assessment,
and QF avoided cost.
• Virtual Public Meeting — Natural Gas & Electric IRPs (September 2024): recorded
presentation, daytime and evening comment and question sessions.
5

Appendix A
2025 Electric IRP Draft Outline
Executive Summary
1 . Introduction, Stakeholder Involvement, and Process Changes
2. Economic and Load Forecast
— Economic Conditions
— Avista Energy & Peak Load Forecasts
— Load Forecast Scenarios
3. Existing Supply Resources
— Avista Resources
— Contractual Resources and Obligations
— Customer Generation Overview
4. Long-Term Position
— Regional Capacity Requirements
— Energy Planning Requirements
— Reserves and Flexibility Assessment
6 Rpm

2025 Electric IRP Draft Outline Appendix
5. Distributed Energy Resource Options
— Energy efficiency potential
— Demand response potential
— Generating and energy storage resources options and potential
— Named Community Actions
— Distributed Energy Resources Study Conclusions
6. Supply-Side Resource Options
— New Resource Options
— Avista Plant Upgrade Opportunities
— Non-Energy Impacts
7. Transmission Planning & Distribution
— Overview of Avista's Transmission System
— Transmission Construction Costs and Integration
— Merchant Transmission Plan
— Overview of Avista's Distribution System
7

Appendix A
2025 Electric IRP Draft Outline
8. Market Analysis
— Wholesale Natural Gas Market Price Forecast
— Wholesale Electric Market Price Forecast
— Scenario Analysis
9. Preferred Resource Strategy
— Preferred Resource Strategy
— Market Exposure Analysis
— Avoided Costs
10. Portfolio Scenarios
— Portfolio Scenarios
— Market Scenario Impacts
8

Appendix A
2025 Electric IRP Draft Outline
11 . Washington Clean Energy Action Plan (CEAP)
— Decision Making Process
— Resource Need
— Resource Selection
— Customer Benefit Indicators
12. Action Plan
9

Appendix A
Major 2025 Timeline
Exhibit 1: Major 2025 Electric IRP Assumption Timeline
Task Target Date
Market Price Assumptions December 2023
CCA/Other GHG Pricing Assumptions
Natural gas price forecast
Regional resources and roads forecast
Electric price forecast March 2024
New Resource Options Cost&Availability March 2024
AEG Deliverables April 1, 2024
Final Energy &Peak Load Forecast
Energy Efficiency and Demand Response Potential Assessment
Locational Energy Efficiency and Demand Response Potential
Transmission & distribution studies complete April 2024
Due date for study requests from TAC members March 20, 2024
Determine portfolio &market future studies May 2024
Finalize resource selection model assumptions June 1, 2024
10

Appendix A
2025 Electric IRP Draft and Submission Dates
• Draft IRP will be available to the public on August 30, 2024, for comment
• Comments from TAC members due by November 15, 2024, or through
Washington's public comment timeline
• IRP team will be available for conference calls or email to address comments
with individual TAC members or with the entire group if needed
• IRP filed with Idaho and Washington Commissions on January 2, 2025

Appendix A
TAC 1 Meeting Notes, September 26, 2023
Attendees:
Diana Aguilar, Fortis BC; Ernesto Avelar, LIUNA; Shay Bauman, Washington Attorney
General's Office; Shawn Bonfield, Avista; Tamara Bradley, Avista; Annette Brandon,
Avista; Molly Brewer, UTC; Terrence Browne, Avista; Michael Brutocao, Avista; Logan
Callen, City of Spokane; Terri Carlock, IPUC; Katie Chamberlain, Renewable NW;
Thomas Dempsey, Myno Carbon; Joshua Dennis, UTC; Mike Dillon, Avista; Chris Drake,
Avista; Michael Eldred, IPUC; Ryan Finesilver, Avista; Grant Forsyth, Avista; Gall,
Avista; Annie Gannon, Avista; Amanda Ghering, Avista; John Gross, Avista; Leona Haley,
Avista; Tom Handy, Whitman County Commission; Lori Hermanson, Avista; Mike
Hermanson, Avista; Kevin Holland, Avista; Fred Heutte, NW Energy Coalition; Scott
Holstrom, LIUNA 238; Tina Jayaweera, NWPCC; Clint Kalich, Avista; Mike Louis, IPUC;
John Lyons, Avista; Jaime Majure, Avista; Ian McGetrick, Idaho Power; Kytson McNeil,
DNV; Heather Moline, UTC; Lindsey Moon, Avista; Tom Pardee, Avista; Nathan Sandvig;
Avangrid; Jesse Scharf, Fortis BC; Ryan Sherlock, Avangrid; Jaclynn Simmons, UTC;
Dean Spratt, Avista; Lisa Stites, Grant County PUD; Jason Talford, IPUC; Charlee
Thompson, NW Energy Coalition; Jack Tortorici, LIUNA; Jared Webley, Avista; Kirsten
Wilson, Washington Department of Energy Services; Rachel Wilson, Form Energy; Yao
Yin, IPUC.
Introductions, John Lyons
John Lyons: We do this for the recording and the plan is we post this after the meeting.
So, in case there's something you want to check in on again. We also use it for the
transcription, so, we're able to have some pretty good notes. James, you want to pull up
the first presentation.
James Gall: I will try. That's it.
John Lyons: The first one in the new rooms. Plus, you will notice, we did give a second
meeting invite here within the last week. That's because we've done a major shuffle on
our conference room numbers with the technology. It changed all the room numbers and
then resent things out. Hopefully we should be done with that. But if you've had any Avista
meetings previously scheduled from more than a week ago, you may see that happen
with the new rooms. I'll start away with the introductions, the first slide.
John Lyons: Meeting guidelines for the Technical Advisory Committee. IRP team, we
are back in the office and Avista is back to at least three days a week in the office. Some
people are four or five. We're in office Monday through Wednesday and also available by
email, phone and Teams. We'll talk about that later today. There's a lot more involved
with Teams, where you'll be able to interact with us, hopefully more. We'll be able to post

Appendix A
new data as it comes out. This is where we get our stakeholder feedback and we share
those responses. We'll share them at the TAC meeting, so if we had a question come up
that we have to go in and figure out what did we do last time, we'll be able to pull that to
share the next time. Some of them, though, we will be sharing through Teams and then
we also post all, and print all of those in the IRP appendix so they'll be there for posterity's
sake. It also does help all of us to make sure as we go through all these meetings that
we're picking up on everything that we've been that we talked said that we were going to
do the working data is going to be posted in Teams.
John Lyons: Last time it was we posted on the website. James will be talking about that
a little later today. It'll be posted on Teams so we can update it a little more quickly when
the data becomes finalized. It will still be posted out on the website as well, and then we
will send it out to the TAC. So, like the Work Plan that got sent out with this TAC meeting.
We are going to always offer the virtual IRP meetings on Teams, and we will offer in
person for the full day meetings. Internally, we'll be here in person, but the external ones,
the six plus hour meetings. Final TAC presentations, meeting notes and the recordings
will be posted to the IRP page just like we've done previously.
John Lyons: And some reminders on the virtual tech meeting asked that you mute your
mics unless you're speaking or asking a question. We do also try to watch for people as
we see it pops up that they've taken their mic off, will try to call on you and we've got folks
here from Avista watching that. If we don't get to you right away, it usually just means
we're trying to find a good breaking point. There is a raise hand function you can use, or
you can type questions in the chat box if it's one that is helpful for everyone, we'll just
answer those to everyone. Otherwise, we may just answer them right in the chat. We
asked you the respect, the pause. We've all gotten fairly good at working on these virtual
meetings, but it's still does help to give people time to get through the technology, unmute
things like that. Try not to speak over the presenter or a speaker, we know that's difficult,
but we all strive to do that. And if you can state your name before commenting for the
note taking software. Usually, it's pretty good about picking up who it is that's speaking if
they're up to a direct computer. When you're in a room or you're using another type of
microphone, sometimes that's a little helpful there. Just as a reminder, this is a public
advisory meeting and we do record all the presentations and comments for posterity's
sake. So, if you have something you really want in the IRP, that's a good way to be able
to do it. If you don't want it in the IRP, probably best not to.
John Lyons: On the IRP itself, this is required by both states we operate in. Idaho and
Washington. Every two years in Idaho and in Washington it's essentially every four years
we do a full IRP and then the intervening 2-year period we do a Progress Report which
looks very much like a full IRP. But since we're already doing it for Idaho, we do a full IRP.
There are just a few nuances we do for Washington. And in that case, a lot of that has to
do with the Clean Energy Transformation Act. As we've moved that direction, the IRP
informs the Clean Energy Action Plan and the CEIP looks at the resource strategy over
the next 20 years. If you've been with us for a while, you notice it was 20 plus years

Appendix A
because we were going at least through 2045 to coincide with CETA. Now we're into that
period where we're within 20 years, so, we're back to our normal timeline on that. We look
at current projected load and resource position. What resources we have in place. What
is going to be leaving us, like ending power contracts, things like that.
John Lyons: Looking at load growth and where load growth is occurring and what we're
going to need to meet that. We look at alternative load and customer forecasts because
we don't know the future exactly because if we did, we would not be talking to you on this
meeting, we'd be on a beach somewhere if we were perfect. We do have to make different
alternatives. We always start with an expected forecast and then we have high and low.
If there are other ones that are important, like for example, do we have a quicker uptake
of electrification for vehicles, housing, things like that. We develop resource strategies
under different future policies. Again, since we don't know what the future is going to
bring, we come up with different ideas of what it could be. We look at different generation
resource choices, do we have an all wind, all solar, mix of the two, different types of
storage technologies. We are looking for new resources that will be clean but that we can
turn on and off, it's hard to do that with the sun and the wind. But are there some other
resources like hydrogen of green ammonia, things like that we could look at. We include
energy efficiency and demand response, transmission and distribution integration. We do
now have a distribution planning group that you can participate in that we'll be talking
about throughout this TAC series. This all results in a set of avoided costs that will help
developers know what they be able to get if they submit us resources and just also
knowing what that's going to be for our general planning needs. We also run market
portfolio scenarios for when we have those uncertain future events. Those are the big
picture events that will fundamentally change the market that we're looking at.
John Lyons: As far as the TAC itself, this is the public process of the IRP. This is where
we get input on how we're going to study things, what we're going to study. If you have
things that are questions that you're really concerned about, and you would like to know
answers to. If you have a particular study in mind, let us know, or we can help you fashion
a study that we could do to come up with that data. We go through all of our assumptions
and results. And if you look in our past IRPs, we publish a tremendous amount of data so
that you can look through it and decide are we, you know using reasonable assumptions
or not, can we make them better? Better we do have a very wide range of participants,
so not everyone is going to be very, you know, totally adept at certain parts of it.
Annie Gannon: Yeah, we lost the sound, I think.
Kevin Holland: John muted himself.
Gannon, Annie: Oh, there it is.
John Lyons: Alright, it just automatically muted for some reason. You can hear me
again?
Chris Drake: Thank you.

Appendix A
Annie Gannon: Yes.
Charlee Thompson: We can hear you.
Chris Drake: Yep, we lost just the last 20 seconds.
John Lyons: OK, it just didn't like me, and I just had this life changing sentence that I
said. But no, this is about TAC members, and we have a wide variety of people in the
group and some of them are experts in one area versus another. Please ask away if you
have questions because, like we've all learned in in school over the years, if you have a
question, generally someone else has it too. So, please speak up and ask on that. It is an
open forum. We're always trying to balance the needs of getting through the slide decks.
If you just say have something where you agree with someone, do the thumbs up on the
chat box. That does help. We also are always looking for help with soliciting new TAC
members, and we have an arduous process to get on the TAC. You just send me an email
and ask or call. That's it. If you want to be on the TAC, you can be. We have some people
that participate for the whole series, and we have others that just come for the topics that
are very important to them.
John Lyons: We do welcome request for studies or different assumptions. We may have
a set of assumptions that we feel are appropriate for planning because we have to plan
to what we actually see out in the market. But if you've got other assumptions you'd want
us to take a look at as a scenario, you're welcome to do that and we'd happy to do that.
And again, we're available by phone or email for questions or comments in between
meetings. And I think James will talk about it later, but on the Teams, we may be able to
start doing some more discussions on that.
John Lyons: Our agenda today, after the introduction, Kelly will go through the CEIP
update and what's going on there. Then James will talk about the TAC process and some
of the proposals for different methods we're going to be using this TAC series. Mike will
give a PLEXOS overview. That's one of the major software that we use for the IRP that
is new for this IRP. He's going to show a back cast on that towards Aurora. Take a break.
Then Lori will discuss available resource options for different types of generation, demand
response. You will have to wait for and be excited about the different types of generation
like solar, wind, thermal plants, biomass, geothermal, things like that. And then I will finish
out the day with the Work Plan. We plan to end by noon. You'll see we have a mix of long
and short meetings going over this schedule.
CEIP Update, Kelly Denciel
Kelly Dengel: Good morning. Thanks. OK. But while James is putting that together, I'd
like to thank you for inviting me. This is my first opportunity to speak at a TAC meeting.
My name is Kelly Dengel. I'm a Project Manager in the Clean Energy Strategy Department
and it it's a relatively new group that has been formed to try to keep up with the good work
that this team does, also in energy efficiency and energy assistance and community

Appendix A
engagement, all of those groups are involved or environmental too. I see you over there
involved in how we pull off this Clean Energy Implementation Plan and today's
information. It's an opportunity to give you an update on our implementation plan and the
biennial. Can you go to the next slide?
James Gall: Yes.
Kelly Dengel: Today I'll share just the highlights of what's in the biennial. And you'll also
have an opportunity to review it and provide commentary before we make our final filing
with the Commission. You are likely all familiar with the Clean Energy Transformation Act,
which informed us creating a Clean Energy Implementation Plan. We made a Progress
Report earlier this year based on the 2022 compliance period and then the last item on
this slide is actually the biennial, which is required every two years. We'll file it November
1st and it's giving an update to all the specific items we mentioned in the CEIP or the
Clean Energy Implementation Plan.
James Gall: Alright, I guess this one is my slide. One of the crown jewels of the CEIP is
the transition to 100% clean energy by 2045 and we're trying to show progress over the
next four years. The first four years of the CEIP plan. For the first biennial, we are going
to be reporting on the targets that we set through negotiation in the CEIP process, which
is 40% clean energy compared to retail load in 2022, ramping up to 62'/2% by 2025. That's
shown in the green bars and in blue is the amount of clean energy that's allocated to
Washington customers prior to any sales to the wholesale market. In 2022, for example,
we generated 71.6% of clean energy or qualifying clean energy compared to retail load.
It might be worth noting that we did sell off the difference between the 71 .6% and the 40%
to third parties, at least the clean energy RECs component of that. We will continue to try
to optimize those REC sales to benefit our customers until we are at a point where we
need to retire all of the clean energy RECs for our customers. As we ramp up towards
2025, we are bringing on new resources which we talked about in the last TAC series
where we acquired contracts. Chelan PUD, the Columbia Basin Hydro contracts, the
Clearwater Wind, and the upgrade to Post Falls. We'll talk a little bit more about our
resource portfolio in a future TAC meeting, but we are in good shape to comply with the
ramp up requirements towards the 100% carbon neutral level by 2030. So that'll turn it
over to Kelly.
Kelly Dengel: I mentioned energy efficiency as a large contributor to our CEIP and they
have some specific items they've been working on. The first one there related to pilots for
demand response and those should be available for people to enroll and learn about in
Q2 of next year and it will be a two-year pilot for time of use and a peak time rebate. They
also made some really good strides with the Spokane Tribe in conducting energy audits
and their administration building, partnering with them to apply for grants, working on a
solar opportunity, and also weatherization, common energy efficiency activities. And then
the last bullet there, the Named Community Investment Fund is a specific action that I'll
talk about later.

Appendix A
Kelly Dengel: But how can that speak to how we can make some of these opportunities
that look less economic? Economic by funding them through this fund that we established
in the CEIP and put more specific interest and specific focus on folks in Named
Communities. Next, next we'll talk about the Customer Benefit Indicators. This is a large
portion of the CEIP and how it's measured for us, ensuring an equitable distribution of the
clean energy plan, and the benefits and potential burdens and call those non, what do we
call those James on energy impacts.
James Gall: Non-energy impacts.
Kelly Dengel: Thank you. We worked with the advisory group, specifically that Equity
Advisory Group to establish these CBIs, Customer Benefit Indicators. We have six benefit
equity areas. The graphics across the top and 14 CBIs which have resulted in 74
individual metrics underneath each of those CBIs. The CEIP will give a 2021 baseline
compared to a 2022 actual for each of these metrics and how we've performed in relation
to the CBI and when we go into our next CEIP / IRP plan. We'll be talking about the CBIs
and if there's changes, we'd like to make, or additions, we want to hear from folks. So
that's something into the future. The next one is about the main Community Investment
Fund, so this specifically made space for benefiting folks in Named Communities through
the establishment of this fund. And we have $5,000,000 set aside. You can see the five
different areas in which we intend to spend this money and that $2,000,000 for energy
efficiency that supplements to get over the economic hurdle for some of the energy
efficiency projects. And the remainder $3,000,000 is managed by our Community
Outreach and Development Engagement group here in Avista.
Kelly Dengel: Next, we recently put an application online. Open to government agencies,
nonprofits, and other community organizations to have access to the funds. This online
application has had exposure and communication with our Community Action Partners
and has been pretty popular. We launched this back in August and we've already had
more than 10 applications come through for funding and the intent is to review them and
get approval to award monies within 45 days of submission. When we go through this
review process, we had talked with the Equity Advisory Group about how they thought
these funds should be spent and what was a priority to them about projects. And so, this
ranking and you'll see that obviously they have some really important things that catch
two number ones or three, two number threes. How they think the money should be spent.
We look at all the projects through this ranking lens and try to award in line with what
they've prioritized. And you'll see the Spokane Tribe is the number one right there, and
many of the energy efficiency and audit improvements and the grant partnering is a
prioritized effort. So, we're filling that. And as other projects come through, we'll look at
this prioritization list as another way to determine funding and approval.
Kelly Dengel: And the next slide talks about what the requirements of the project at a
minimum should have. How does it serve a Named Community. I'm assuming that
everyone on this call understands what a Named Community is, or at least the concept.
And second, how does it fall into one of the equity areas? And then third, what is a

Appendix A
Customer Benefit Indicator that it can impact? And so those things are part of the
application process and there are folks that have been made available to help in this
application process. If you're unsure on how to fill it out or you unsure about how to find
out what your CBI is. Next slide. We have funded, or planned to fund, projects in these
areas and under energy efficiency. Of course, you'll see a lot of the Spokane tribe and
two big projects under distribution resiliency and improvements to the Martin Luther King
Junior Center here in Spokane. Through grant awarding with the Department of
Commerce we're able to secure funds to work on a solar and battery storage project in
the town of Malden. I don't believe there's a grant opportunity there, but trying to work on
a solar and ground source heat pump project. Malden is the town that had all fires not too
long ago. They're trying to reinforce and rebuild their town hall and this this will help them.
That's what we have to date. The biennial will provide updates for each one of these
projects and how much money was actually spent within 2022, through August of 2023,
what we planned for the rest of the year, and in the 2024.
Kelly Dengel: The next subject of the biennial is public participation. We were required
to file a public participation plan of this, partnered with a company called P3 or Public
Participation Partners. They worked with us last year and a little bit in the previous year
to come up with a plan of how to engage more customers and overcome the barriers that
may limit them from wanting to participate. You could think language is a barrier, or where
they're at might be a barrier, physically located. And so, we have updates.
Kelly Dengel: Next slide, James, we have updates based on what we said we would do
on our plan and that includes a multi-language strategy for our website and our mobile
app. We also want to make a way for customers to more easily engage with us. A lot of
times our conversations are one directional. We give you a message, but through the
CEIP process, in this public participation, we wanted to be more two-way. So, we're
talking about a newsletter and a public forum comment section that we can implement
some FAQs and obviously continue to get feedback from our advisory groups. These
updates to our websites and particularly the CETA page should be coming in the next
year and that is listed in the biannual as well.
Kelly Dengel: Finally, we had a bunch of conditions, 38 to be exact, that we were required
to accept during our CEIP approval process. Over the last year and a half, we've been
working to complete or start a plan for. The biennial will list each condition and then an
update as to what Avista is doing to comply and meet that condition and, spoiler alert, for
meeting them all. This is a great job and I think we'll have a nice story to tell. The last
slide talks about how you can respond and review this biennial document. The document
is available for posting. We're sending it out to all of our advisory groups, and I think
James has a plan to put it on their new IRP Teams site. You can direct your comments
or questions to me specifically and my email address is there. Please send them by
October 13t", and we'll include the comments, questions in some type of matrix with the
filing when it goes to the Commission on November 1 st. At the end of this slide deck is a
listing of all 38 conditions. If you're really interested in knowing what we had to do, you

Appendix A
can go read through those. That's my presentation for today and hopefully you're really
interested in reading this in the biennial and you have lots of comments for me. Are any
questions on the chat? No typed questions? OK. If there's any questions of anybody in
person, so hands up or pause this for a second, just in case something comes up. OK.
TAC Process and Methods Proposals, James Gall
James Gall: Well, thank you, Kelly. And I guess I am next, bear with me while I try to find
my presentation. And looks like you can see it now alright. Well, as we started a new TAC
process, we like to go over some of the changes we have in mind. Specifically, there's
some major changes in the modeling software we'll be using, others mean a couple of
process changes we'll cover. Also, we'll provide an update on the Action Items from the
last IRP.
James Gall: First off, I want to talk about the TAC communication process that we're
changing that John alluded to earlier with Microsoft Teams, which we've been using for
our meetings over the last couple of years. But we're going to create an actual team that
the TAC will be able to participate in. You'll be getting an invite, likely tomorrow, to access
the Teams site, so I think you can use it through the same software you're using today to
access this meeting, but there will be an actual Teams site that will allow you to see files
that we share with you. There'll be a chat function for you to communicate with us or other
TAC members that are all available in this. I'd say this really comes back to some
comments we had from TAC members that either didn't want to engage or wanted to
engage with other TAC members. This allows for each of you to engage at the level that
you would like. So, if you don't want to see what other TAC members are saying, you
don't need to go on the Team site. But if you want to communicate ideas that you have,
maybe articles you've seen, files that you want to share with us, it's an Ave to do that.
This will eliminate a lot of the email traffic for the passive TAC members. Like I mentioned,
you'll also be able to access all of our recordings and all the messages that are on the
Teams site are retained.
James Gall: We, like John mentioned earlier, will continue to post our TAC slides and
our meeting information on the website, including the agendas and the slides. We will not
be sharing on the website any draft documents like we've done in the past. We'll leave
those on the TAC Teams site and then once we file the IRP and final documents are
ready, we'll post those on the website as we do today. You should be getting an email
and next day to sign up for this new Teams site. You'll continue to get TAC invites through
email, but you'll also get one on the Teams site as well. And if you are also a natural gas
TAC member, we'll have a Teams site for the natural gas IRP as well that will be actually
in the same location on Teams. They are called channels that you'll be able to get to when
you open this up, you'll see on the bottom there's an Avista 2025 IRP. There's a general
section which you will see any generic comments or chat function, but then you'll have
electric and gas options, and you can see there's posts for people. This is where the files,

Appendix A
where you'll be getting files, and we'll see how this works. If it doesn't work, we'll try
something new, but one thing that's important is to try things, and if you fail, fail fast and
we can try something else. So, let's try this and see if it works, and if not, we'll try
something else.
James Gall: Another interesting thing that's happened, at least for Washington, we got a
notice from the UTC on the electric IRPs that the Commission will discontinue its practice
of acknowledging electric IRPs in all cases. The second bullet is a quote from that. Notice
we're under CETA, the CEIP must be consistent with the long-range utility's integrated
resource plan and informed by the investor utility's Clean Energy Action Plan, which is
developed in part of the IRP. Therefore, any issues that interested parties may have
related to the IRP can be litigated and decided by the Commission as part of the CEIP
process. How we see this, the CEIP, which is really a four year look at the Company's
future will be the area to comment publicly about IRPs. I think this 2023 IRP did have a
public process where there were comments to be filed. I'm not sure that will continue or
not, but we are, definitely interested in comments as we go through the process as we
have always been. I would say don't let this be a deterrent to comment in the IRP process
and it is better that we get any comments or concerns through this process before we get
to the CEIP, as the CEIP is definitely more focused on four years and sometimes they
have a shorter timeline to get that completed. So, continue to use the IRP process as a
as an avenue for advocating as you've done in the past. Idaho will continue to
acknowledge IRPs, as far as I know, and that process will remain unchanged. But in
Washington, there's a slight change.
James Gall: That's a quick update to different Action Items in our 2023 RP. I want to go
through each of these items just to give an update where we're at. The first one is related
to a distribution energy resource potential study and that is underway. We hired a
consultant, AEG, and they're responsible for determining how much available solar and
electric vehicles are on the system and where they are at on the system. And in addition,
they'll be looking, as they've always done in the past with energy efficiency and demand
response, at a spatial analysis of those potential options. For those of you that are
following the DPAG process of it, which is the Distribution Planning Advisory Group, that
will be the avenue for much of the work that's being done in this DER study. The plan is
that any learnings we get from that study, whether that's changes to our load forecasts
such as future EV or rooftop solar adoption that will be impacting our load forecast, and
then we can use potential resource locations for future generation sighting as well. More
to come on that, there will be a TAC meeting in the future to cover this topic. Once that
report is complete, the next item is a variable energy resource study. That process was
kicked off in the last IRP process and we are continuing to determine the required
reserves and the cost of variable energy resources. We hope that the study will be
complete for the 2025 IRP.
James Gall: The third bullet, which is alternative load forecasting methods. Again, we
were looking at end use forecasting as an alternative to our historic load forecasting

Appendix A
methodologies. We did also work with AEG. AEG who does our energy efficiency analysis
for us for the potential study does do an end use load forecast, it determines those energy
efficiency targets. We're going to be leveraging that work to help us do our long-term load
forecast. It's going to be five years out towards the future, so we'll continue to use our
existing methodologies for load forecasting for the first five years of the plan and then
transition to the end use model for the long-term forecast. And the reason for this is if
there are changes in customer use from potentially electrification, this is a better way to
forecast that energy use because you're taking into account the types of equipment
consuming that load. So more to come on that as well.
James Gall: The last bullet on the left is investigate PLEXOS, which we'll have a
presentation about that later today. So, I'll skip that one, and the next one is with the
Western Power Pool's WRAP program. I'd say this was very unique in its last IRP process
to use the WRAP's QCC methodology and we did not use their proposed planning reserve
margins for long term planning but I think that the idea here in this Action Item is to ensure
that we want to keep using their methodology and then how do we transition to using, or
should we be transitioning using the WRAP's planning reserve margins. There are two
concerns with using their planning reserve margins. One is they only go out in the future
for two or three years, and second, they have not done any long term QCC analysis. Our
PRM analysis determined resource adequacy beyond those first two years. There's been
an effort by the members to do a long-term study and that study would be determining
QCC values likely out in the 2040 time period or 2045 time period and what the required
PRMs would be out in that future and that would be used for planning in the IRP. If that
that process is successful, so likely there will be a topic at a future TAC meeting to cover
this as we learn more in that process.
James Gall: The next bullet is on long-term or long duration storage opportunities we
mentioned in the last TAC process: pumped hydro, iron oxide, hydrogen, ammonia
storage. We'll have a presentation by Lori this afternoon to seek input from you, the TAC
members, for the technologies we should be looking at. Are there technologies that we
shouldn't be looking at? Also, if there's anybody that has information on these
technologies, whether it's cost information, where we're at in the development process
that would be great for you to share with the group.
James Gall: Another topic related to Named Communities, like Kelly mentioned,
communities that are defined by the State of Washington as Highly Impacted or
Vulnerable Populations. The ask was to determine the amount of energy efficiency that
is in those areas. In our last IRP process, we did break out energy efficiency by low
income. We wanted to further look at that spatially and the Named Communities. That
process will be beginning shortly in determining whether or not that's something that we
can do with any accuracy.
James Gall: Next bullet was on transmission access. As some of you might recall,
Washington State legislature did pass a bill that requires IRPs to look at transmission.
We are going to be making some changes in our modeling process to account for that.

Appendix A
Actually, Mike will be going over that in the PLEXOS tool this afternoon. But we are also
concerned about surplus energy and that tool will help us determine what is that future
utilization of transmission to export excess renewable energies that we're going to be
acquiring to ensure that we can meet 100% by 2045. That tool will help us manage that
Action Item and then the last bullet will probably play out through the regulatory process.
But that is looking at, how do we define what 100% is when we're in 2045. Does that
mean that we should be planning our system as an electrical island? Does that mean that
we will be allowed to buy power from others? How do we ensure that it's clean in a
connected market? I don't think those will be answers we will have in the IRP, but it is an
issue that needs to be addressed regionally, or at least in the State of Washington,
because the implications of how you design rules for CETA will impact what our plan is.
I'm going to pause there. If there's any questions. I guess not, OK.
James Gall: Just a real brief introduction of PLEXOS. I don't want to steal. We have a
question [from unknown user in chat], I found when I set up an external facing Team site
for the project that DES Energy is doing that non-state individuals invited to the Teams
site could not access more of the site if they logged into the site via web browser rather
than the Teams app on the computer. So probably the same is true for yours. So, we'll
be looking into that. We hope it works. We're told it's going to work for us, so if we do run
into roadblocks, we won't have to revert back to the old method, which I said, fail fast is
OK, so hopefully we don't fail fast.
James Gall: Alright, so PLEXOS. Mike is going to cover a lot of PLEXOS later, but there's
a few things I wanted to throw out there as you think about this, before we get to Mike's
presentation. So, what is PLEXOS? It's a production cost model developed by Energy
Exemplar, and its benefit, or its technology that it uses, is a mixed integer-based design
which is very similar to what we use in our PRISM model, and we plan to use it for
resource evaluation and market risk analysis. And what this is, when we look at each of
the generating resource options, that Lori will be talking about later, is we need to
determine how they're going to be dispatched and how much market value they create.
Aurora does do a good job at this, looking at it from a market perspective, but as we
acquire more renewables and then look at energy storage, we need to look at this from a
portfolio basis and that's where PLEXOS really the strength in that tool. So, we think it's
going to do a little bit better job at valuing energy storage from that portfolio. Especially
with our reserve modeling. Of course, the future could create an RTO which would maybe
allow for other options to model this in the future. But for now, in a control area
environment, or balancing area environment. I think this technology is probably best
suited for studying these resources.
James Gall: The other major change that PLEXOS brings to us, compared to using
Aurora, is a more sophisticated hydro modeling technique. Aurora does a phenomenal
job of dispatching hydro from a regional perspective, but when you look at it from a
portfolio design, there's just constraints of the system that we can't model, and we think

Appendix A
PLEXOS is doing a much better job with that. We'll have some presentation by Michael.
We'll show that in a little bit.
James Gall: As I mentioned with transmission earlier, it's capable of modeling detailed
transmission. The last couple things on here is the future that we see with the tool. One
is can it replace PRISM? Or should we replace PRISM, I guess is maybe another
question, but it does have a capability of doing capacity expansion for both transmission
and generation. We'll be testing that in this IRP process, but will continue to use PRISM
for this IRP process. And then the last point is, it theoretically can do combined natural
gas and power modeling and that's something that we would definitely be curious at
looking into as well. There's definitely a future for expansion between IRPs, between
fuels, so there is potentially, but we are going to take this a little bit slow just to ensure
that we're comfortable with the results we're getting. And also, we are a small team of
folks and so it does take time to build these tools out and ensure that we're getting correct
results.
James Gall: Like I mentioned earlier on the load forecast update, we have an agreement
with Applied Energy Group, AEG, to do a long-term load forecast. We're actually doing
this for both natural gas and electric. The idea is to ensure that we understand the
implications of electrification and what we're looking at here is, if we have customers
switching between natural gas and electric, we wanted to ensure that we account for the
correct amount of BTU transfer between the two fuel types and then the efficiencies of
those options. So, AEG is in the process of conducting a load forecast for us. It's going to
be consistent with that. Our potential state, like I mentioned earlier, they will be producing
three scenarios for us, a high, a low and an expected case. And we'll be seeing, I think
the first iteration of that load forecast in the next two months. We'll update it again and
present it to the TAC in the spring. And then with that load forecast, they can use it to
determine our demand response potential and our energy efficiency potential
assessments.
James Gall: I think one of the challenges we had with, say for example demand
response, is what is the amount of your water heaters there will be in the future from a
electrification conversion for example. And this should say, streamline our process on the
customer opportunity side for what does load growth look like? What do resource options
look like from demand response and energy efficiency? We're excited about this change
and it should hopefully provide a better result.
James Gall: Another update on PRISM, like I mentioned earlier, we are looking at testing
PLEXOS to replace PRiSM for the next IRP in 2027. But we're going to wait on that. We
were a little bit concerned about, can PLEXOS do the level of detail for energy efficiency
that we do in PRISM. Can it run fast enough to run the scenarios that we need in this IRP
process? What is it going to take the build these portfolios out? We like PRiSM because
it's nimble, it's very transparent, but is it the best technology to help us on this path? That
is yet to be determined and one of the concerns I have with using PLEXOS to do portfolio
modeling is that transparency, where PRiSM is, we can post that on our website. You can

Appendix A
look at all the assumptions and PLEXOS requires you to buy a tool to look at those results.
That's something we'll be considering, and we would like input from the TAC as well
through this IRP process as we test it, and before we make a decision in the 2027 IRP. I
think it would be helpful to hear your comments on what technology might be best suited
for that next IRP.
James Gall: Another thing we are testing in PRISM is co-optimizing the natural gas
system and electric expansion. What I mean by this is instead of having a separate IRP
that looks at figuring out which resources are needed for the electric demand and the gas
demand, we bring that all in one tool and the model can choose what's the best way to
serve that demand. For example, if there is a heating demand, is it best suited to be
served by electric or natural gas from a least cost basis.
Lori Hermanson: Got a question James.
James Gall: All right, I'll pause there. Fred, go ahead.
Fred Heutte: Hey there everybody. Fred Heutte, Northwest Energy Coalition. Good
morning. Just a very quick comment on PLEXOS. I think you may very well know that
PacifiCorp has been using that for a couple years now. And I hope you've been chatting
with them about their experience. They had a lot of trouble. They did, in my personal
opinion, not do a long enough transition approach. They did some. It wasn't like they just
dived in. Throughout the early they were using system optimizer before that, not like they
just completely jumped. But I don't think that they did enough of the transition like you're
doing. It's very powerful. It's a beast. From what I understand, I've not seen a detailed run
through. You know how it operates, but where they did do that was system optimizer.
James Gall: All right.
Fred Heutte: Using PLEXOS as your primary model is the right way to do it, and
specifically on energy efficiency. I would concur about the potential there, where PLEXOS
may have some advantages. You could talk to the PAC IRP team, Randy Baker and
everybody there. They've done some very interesting things with PLEXOS too, and in
some ways kind of overkill how complicated they've gotten with their EE analysis, but it's
really robust. Hopefully you'll be able to figure this thing out and looking forward to how it
all looks as you go through that.
James Gall: Hey Fred, I asked about this transparency issue. Are you comfortable with
PLEXOS as a tool, is that transparent enough or would you like our transparency of
PRISM?
Fred Heutte: You know honestly, and I follow modeling pretty closely, but I can't say that
I'm a modeler or I know a lot about software, I'm not a practicing modeler. So, I think there
may be a participants, stakeholders, whatever in the IRP process who might be interested
in taking a look. Yes. You know, I think one of the really positive things about Avista's
approach to the IRP is you do make everything as available as possible. You know the
models, the data, et cetera. I think we have a tradeoff here. PLEXOS is a really big beast.

Appendix A
don't know what the licensing fees are, but you know they're pretty high. I think the key
thing will be to you know that as long as you provide the kind of transparency into your
methods and the outputs, the UTC staff and maybe some stakeholders that have really
serious modeling capabilities of their own might be interested in taking a look at some of
the results. But practically speaking, I think as long as we're sure that you're running
things as you say, and we have a good interest in looking at specific details, outputs
you're able to provide that. I don't really see a big problem.
James Gall: OK. Thanks, Fred. Any other comments before I continue on? Alright, I have
my last slide and I'm hoping this last slide will get some feedback. I'm going out on a limb
here and you might remember if you've been part of our TAC process, I think the last
meeting in our 2023 RFP process, we talked a lot about resiliency and how do we include
resiliency in IRPs is a challenge across the entire industry because most resiliency
aspects are at the feeder level. And I think that's appropriate. But IRPs are typically at the
generation level, somewhat transmission level and but there are things that are resiliency
based that we should be looking at. I think about this as a resource diversification and
John and I were spit balling a month ago about how do we deal with resiliency. And we
came up with a methodology, the quantify of diversification, some of those that are finance
nerds may have heard of the Herfindahl Hirschman Index. But we thought, is this a way
to measure resiliency? And you know, maybe this ends up as a Customer Benefit
Indicator, I don't know. But what I think we can do with this concept is look at
diversification, not just the fuel types, but fuel locations. It's just the generator locations.
James Gall: What I've done on the right is come up with three different methods I had
time for looking at diversification. One is the amount of generator units we have. The
second one is facilities. Noxon has five units, but it is 1 plant, so from a risk point of view
we've spread that risk of generation failure out across 5 units, which is great. But you're
still at one site, so if there was an event, whether it was some type of catastrophe or a
substation outage, you still have one facility, and you can lose the whole system. One
thing on the substation is what we've done there to prevent that risk is put two substations
there, that helps, but look at how spread out is our number of facilities, not just the number
of units and then another item we looked at is fuel supply. So where does our fuel come
from? What I mean by that is, like a natural gas plant, the fuel is coming from the GTN
pipeline for example, and then you compare that to hydro. We have the Clark Fork River
system; we have a Spokane River system and we have a Mid-Columbia River system
and then we have different watersheds. We looked at where is the fuel supply from for
our system. Where do those come from?
James Gall: The Herfindahl Hirschman Index looks at market share, or percentage of the
population, and it comes up with a measurement of competitiveness and the higher the
number that you come up with indicates less diversification of your resources. So, the
academics came up with, if you have a score that's less than 1 ,500, you're very
competitive and very diversified. For the two metrics we looked at, generating units and
facilities, we are very diversified. We're well under that 1,500 and if you're between 1,500

Appendix A
and 2,500, you're in a moderate diversification level. And then if you're over 2,500, you're
too concentrated in a particular area. On fuel supply, you see we're really close to that
2,500 and the question is from an IRP perspective and a generating perspective, should
we be looking at resources that have other fuel supplies. That might be something we
look at as an indicator of a resource choice for the next IRP. Should we keep the portfolio
under 2,500 for example, for the different metrics?
James Gall: These are three metrics I threw out there. There's other metrics we could
look at, such as transmission system, which path the resource is on. We could look at
wildfire risk areas, do we have plants that are in wildfire areas and trying to ensure they
are minimized or in different areas. Another one that we looked at is low diversity, and
that's not necessarily the generation side, but we could do this analysis on our loads and
maybe look at are their risks in different load types that are especially available now that
we're looking at end use load forecasting. But I'm just curious if what others have seen
on how do we deal with resiliency in IRPs, does this this seem appropriate? No, don't like
it, or something else? I'm just curious of any feedback you have and if you want to think
about it, it's OK you can email us later, but I'll pause. I see a hand go up. Heather, go
ahead.
Heather Moline (UTC): Hi. Heather Moline, UTC staff. This is interesting. I've never heard
of Herfindahl Hirschman. Thank you for that overview. Food for thought. Again, this is not
Staff's opinion or the Commission's opinion, but you just asked for feedback. So, I wanted
to put it out in the space. Maybe it does make more sense for resiliency to be quantified
and incorporated into something like the CEIP as opposed to IRP, because CEIP tends
to be a little more about local customer benefit and a little less about long range, large
resources. That's just one thought. I would like feedback on the second thought, slash
question, is to what degree have you all looked into the resources from the national labs
and Energy Trust of Oregon on resilience quantification? And incorporation into resource
considerations.
James Gall: Can you tell me a little bit more about that last statement about the national
labs?
Heather Moline (UTC): Yeah. The Lawrence Berkeley National Lab and Pacific
Northwest National Laboratory. This is one of the main questions that they've been doing
research on for the last three years is, you can't include zero as a benefit or cost of
resiliency because there is a benefit to resiliency. So, how do you put that into models?
And I haven't seen any studies in the last year, but there may be some. I just wondered if
that was research you all were doing.
James Gall: I guess we have not looked at those. We will. One thing that I see this related
to is, because you've talked about values and we tried to quantify non-energy impacts in
the last IRP and where I'm going with this is if the studies, if they're showing values for
different resources, you could put that value in our optimization tool. But we'll look into
that. I appreciate that. That's why we're doing so.

Appendix A
Anette Brandon: James, can I comment on this? This is Annette.
James Gall: Go ahead.
Anette Brandon: Hi, this is Annette Brandon, I'm in wholesale marketing and Heather, I
have actually been following that PNNL resiliency modeling how to value as part of our
equitable business planning initiative. James and I did look at it very briefly, although I'm
not sure I pointed out to him what exactly that meant, but I have been following that pretty
closely as we start to implement this overall project and so will be coordinating with that
as we go forward.
James Gall: Alright. Well, it's one at least we have one idea to look into. Are there any
other thoughts, comments.
Heather Moline (UTC): This is Heather again. That's great to know. And just so you folks
know, you are not the only people asking this question. So, as we become aware of more
things with the other companies, we'll be in touch.
James Gall: OK, appreciate it. The CEIP is definitely an avenue for, there'll be solutions
or ideas to solve resiliency there. There could be an avenue of how we define a Customer
Benefit Indicator for resiliency that will be in that process and maybe one of these HHIs
is one of those. I do see it as a place for generator level resiliency and the relation there
is I see what's going on and say, Texas, what was that four years ago? I can't remember,
but having facilities that are capable of running and in cold weather for example, but if this
is an area that's I'd say it's come up, but I'd say no one cracked that nut yet.
James Gall: I don't think we have either, but we're going to at least try to explore this,
and we'll look at the national labs work, and we'll continue maybe to look at this as an
option and maybe circle back with the TAC. But, if you have any ideas, let us know
afterward or throw them in the chat.
James Gall: Alright, so what's next on the agenda is it a break. Can't remember, I don't
know. Let's check here. PLEXOS is next. Then we'll go to break. Unless we need a break
now. But we're supposed to take a break at 10:45, so we do have time. I'll bring up the
PLEXOS slide deck and if you can, we can do that. Bear with us one second as we
transition. Alright, I think it's there and Mike's ready to go, OK.
PLEXOS Overview and Back Cast Analysis, Mike Hermanson
Mike Hermanson: My name is Mike Hermanson. I'm a Senior Power Supply Analyst here
at Avista and I'm going to be talking about how we are integrating PLEXOS into that IRP,
analytical modeling for the 2025 IRP and also the testing that we've done to determine
how well we are able to represent our system within PLEXOS. Just a little background
here. Power supply modeling is integral to the IRP process. It's the analytical framework
to determine the long run economic and operational performance of alternative resource
portfolios. So, as you go into the future, what different resources solve your different

Appendix A
various constraints in the most economic fashion. Our existing system, and potential
additions to the systems, are subject to many constraints and uncertainties. For example,
the timing of hydro generation, gas, power price movements, government regulations,
and analytical models provide the framework to put all of those very complex pieces
together that don't always move in the same way and then it allows us to assess the
impacts these variables have on our system.
Mike Hermanson: And then, as we go into the future potential additions to meet the load
obligations that we see coming in 2045 for the 2023 IRP. We used Aurora forecast electric
prices, and over the planning horizon. We also used Aurora to dispatch the resources to
meet load. That dispatch was then used in the Avista developed PRiSM model to select
new resources to meet the projected load. For the 2025 IRP, we are taking a different
approach. We're developing an electric price forecast in Aurora and then we will be using
PLEXOS for dispatch and that dispatch will be used in PRISM to determine the resource
selection, but concurrently with using PRISM. We plan to be testing the resource selection
functionality with PLEXOS.
Mike Hermanson: Just a little bit of background on PLEXOS. It's from Energy Exemplar,
who also makes Aurora. It's a widely used model for electric market analysis, power
system optimization. It provides market simulation. It can analyze and simulate electricity
markets considering various factors such as supply and demand, pricing market rules.
This provides insight into the market dynamics and in adding energy trading optimization,
which is a very important component of this considering different resource options going
into the future. PLEXOS also provides for power system optimization. There's a multitude
of constraints that you can put in there such as outages, maintenance, market prices,
hydro variability, emissions targets. Hydro variability is an important one for our system.
Being able to test different variability, and actually the variability more at a more granular
time step than we were able to do in Aurora, allows for integration of renewable energy
and looking at the impacts of these variable generation on the power grid and how that
drives our need for extra reserves.
Mike Hermanson: PLEXOS also has robust transmission planning. It's forced
transmission planning, expansion studies, allowing the inclusion of transmission upgrade
costs associated with potential resource additions. Certain additions of resources such
as solar are only going to make sense in certain areas, but do you actually have the
transmission there to deliver that to the grid and to actually be utilized in the near term.
Mike Hermanson: Hydro modeling is where we see the biggest change over dispatch in
Aurora. PLEXOS models hydro as water coming into a reservoir and then running through
generators. It really represents how it is physically used, the physical movement of water
and the maintenance of reservoirs. This is in contrast to how it was utilized in Aurora,
where it's a bucket of megawatts and you can put some constraints on it. But it really does
not mimic how we operate our hydro system, the flexibility that's inherent in it and also
the operational constraints that are inherent.

Appendix A
Mike Hermanson: This slide just shows the general schematic how the model operates.
On the left you can see we provided an hourly native load to be met by Avista, owned
and contracted generation, market purchases and sales. The hourly load is generated
outside of PLEXOS and as James mentioned, for the 2025 IRP we have contracted with
AEG to assist us in developing an end use load forecast. That end use load forecast is
also outside of PLEXOS will be able to do a lot more scenario analysis, especially as it
relates to electrification and EV penetration as you go out into the future. All of the
estimates of a government program in place or contemplated, are those going to be
coming fruition and if they do, what kind of impact are they going to have on our load?
That'll happen outside of PLEXOS.
Mike Hermanson: The next section is the Avista owned and contracted generation. The
generation is optimized economically against the electric price forecast. You're trying to
get the least cost energy, but there's many constraints that are inherent in these
generating resources. PLEXOS allows for regularly scheduled maintenance and forced
outages can be done in a statistical manner. The timing and quantity of hydro, including
changes over the planning horizon we can bring to play, we do have for example, our
hydro forecast bringing in climate change and the shift of water to earlier in the year as
opposed to the current or what we've seen in the more recent past where we would get
water in June and July. Now we're predicting seeing more in February, March, earlier
melts. Let us know snowpack, so we have to bring that into the PLEXOS modeling. We
also have in this this middle bucket here we're looking at and have the provision of
ancillary services. The variable nature of wind and solar resources, and then we could
also look at the impact of fuel costs on running our natural gas resources and in the future,
looking at all alternate fuels such as ammonia and hydrogen.
Mike Hermanson: The next section that I look at when we're breaking apart PLEXOS is
the market purchases and sales. All of the costs and constraints of our system are
balanced against the markets that are available to us, such as the Mid C, which is the
primary market that we are integrated with. But we also have some others in the northeast
part of our system and COB, the model optimizes and solves at an hourly time step on
the native load and then any contractual obligations, sales that were done, and these are
met by generation and market purchases and sales every hour. It's a very robust system
that you can bring in any multitude of constraints that are affecting your system. The
granularity doesn't solve it. Actually, you can get much more granularity solving that at
the five-minute time step. We have done some testing at the five-minute time step to look
at EIM. Those all of course take quite a bit longer, but it is possible.
Mike Hermanson: This slide shows how our transmission system is represented in
PLEXOS and it's a little busy, so just bear with me. Each of the light bulbs on this graphic
represents a load center, and each of the green dollar sign icons represents a market
where we can either sell or purchase power at, and then each of our generation sources
is connected at the appropriate service point. Each of these lines is assigned a maximum
flow that can occur on that line, and also power that goes over Avista owned lines which

Appendix A
are shown in blue. I don't know if you can see the difference between the blue, kind of
looks black, but the ones shown in blue do not incur a wheeling charge, while the power
that moves over the yellow lines do incur a wheeling charge, which is dependent on the
owner of the line. All of that is input into the PLEXOS system and then it makes decisions
on which ways to move power to load centers based on the most economic pathway. This
is an upgrade I would say from our previous IRP where we had a much more simplified
representation of our transmission system and it's in reaction to the addition by the
legislature into the IRP rules. I guess it's not by the legislature, but by the UTC to add into
evaluating transmission constraints into your IRP considerations.
Lori Hermanson: We have a question from Yao. Do the cost of market purchases and
revenue of market sales include wheeling costs and revenues?
Mike Hermanson: Yes. Essentially that'll be a hurdle rate to buy from the market if you're
having to use transmission, so it'll be netted out.
Question from Room: How does the model build losses?
Mike Hermanson: If you got that, you're asking how does the model deal with losses,
you can actually put losses, line losses into each one of the lines. We haven't done that
just yet. We have right now the sophistication of the line representation has a three-stage
maximum flow of megawatts can go across the line depending on the season, because
it's temperature dependent. But we could also introduce line losses if we choose.
James Gall: But one thing to note, online losses is when we look at load or native load,
you'll see that in any of the data files we provide and how our accounting system works
is that load includes the distribution and transmission losses on our system. It does not
include third party system losses, so I think where we might end up, like Mike said, is we
could put in the transmission losses on the lines that are not Avista's, but on the ones that
are shown in blue or black, we'd likely not include those because they're embedded in
our load forecast.
Mike Hermanson: This slide shows the PLEXOS interface. Just to see that real life
software, the system that we use is built from components that are shown on the left pane.
If you look at the main screen, we have the left pane, and it has all the system
components. You have all the different generators, lines, markets and then you move into
the middle pane, and you can see that all of these components are then connected and
connected in different ways. Fuel is connected to a generator, is connected to a line, and
then we can design properties to all of those, and then the bolt section of that first window
is all of the properties that you add into each of these components, and it varies by the
different generator you have. For example, natural gas generators have a lot of
information about heat rate, whereas the reservoir components have a lot of information
about hydro flow, how large the reservoir is, what min and max levels can occur in that
reservoir, what are the ramp rates for example. And then PLEXOS has a pretty robust
system to display results.

Appendix A
Mike Hermanson: This is just an example of the generation over a year at Noxon Rapids,
one of our hydro facilities. You can look at all sorts of different resolutions. It's very
integrated with Excel. If you're an Excel user, like most people are, you can export these
results very easily to Excel and then do analysis on that also.
Mike Hermanson: I don't think I need to tell anybody on this call that representing these
energy systems is very complex and representing energy production, market exchanges
and transmission in a model has many challenges. With these complex models, it's
always a balance between how much complexity is introduced versus runtime for the
model. Currently, our 20-year run takes between six and seven hours to do one iteration
of it. We plan to run the model with stochastic inputs to capture the uncertainty in our
model inputs we would be using. Selection of water years is different than just the one
prediction to see what the sensitivity our system has for different water years. In 2021, 1
believe we ran 500 model runs to capture this stochastic nature and capture the
uncertainty in all of these. Then 2023, we're at 300 model runs at six to seven hours a
model run, and 300 runs gets quite lengthy, but there's different approaches to reduce
the model runtime to kind of reel that in. We also use multiple machines and so we believe
it's a doable challenge, but it will be a challenge. Looks like we had a question there.
Heather, if you still had one.
Heather Moline (UTC): No, I was doing that math in my head, 6 to 7 hours times 500.
You answered the question. Thanks.
James Gall: We do have 25 machines to spread that around, so it won't be that long of
a math problem, but it'll be a long math problem.
Mike Hermanson: Another challenge with a model. We have perfect foresight. For
example, electric prices are projected for the entire planning horizon. That is different than
what we obviously have in the real world. Another challenge is this system has significant
hydro resources with storage components. It's difficult to capture the myriad of
constraints. We have licensed constraints, but sometimes the system is constrained by
uncertainty or by other considerations on reservoirs, especially reservoirs that have
recreation, they have homes that are built on the reservoir. That is capturing how perfect
foresight is going to dispatch a hydro reservoir versus how it is dispatched in real life is a
challenge and that's one of the things we've been working on quite a bit this last six
months. It's difficult to capture the dynamics of trades that happen at different time steps.
For the most part, we have power ahead trading that's happening at the market. So,
they're looking at what generation we have available, the price of that generation, and
then checking that against the market. Now we have day ahead, hour ahead and even
EIM trading that is difficult to capture.
Mike Hermanson: Integrating forecast error into modeling, that's another challenge.
We're operating our system with a forecast of what's going to occur. What's the forecast
of the load? What's the forecast of the water? How much reservoir? You need to have for
that, the runoff, when's the runoff going to happen. When we just input the flows for the

Appendix A
whole year, you can go in and solve, and it knows what's coming. That makes it a
challenge to integrate and try and mimic how we would dispatch our system with imperfect
information versus how PLEXOS dispatches our system with perfect foresight. As a result
of all those challenges, the model will always have a lower production cost than actual.
It'll be able to be more efficient than we would be able to just run our system. Our
production cost is obviously always higher and so trying to get a sense of what that
magnitude is really, the effort is to look and see what we can quantify what that forecast,
and uncertainty, adds to the production cost to deliver energy.
Mike Hermanson: We started with PLEXOS back in January and our first approach was
to see how close we could get PLEXOS to dispatch against an actual year where we had
actual data. This is going to verify how we built our model. We built the model with the
inputs to all of our hydro units, all of our generation, natural gas generation, and
everything. And we used 2021 data including the hourly load, hydro inflows, run of river
generation, the Mid C price, daily gas prices, the renewable generation actually
scheduled, forced outages, and the reserves that we hold including the frequency
response reserve, non-spin regulation up and down, and the reserves we hold for very
little energy resources for when solar.
James Gall: We've got a question.
Lori Hermanson: Yao's question was, isn't all the input data actual data in 2021 .
Mike Hermanson: Yes, all of this data was actual data from 2021 and then we used that
data with the system that we constructed. We constructed the generators, the
transmission, and built the model, and then put 2021 data into it. And then the question
is, how close can you get? Now we have the actual dispatch, and we're going to have the
model dispatch, and how close can you actually get? Hopefully, if you're getting close,
that means you constructed those components of your system correctly and are
accurately representing them.
Mike Hermanson: This shows the actual 2021 generation, then the generation from the
PLEXOS run, and then the difference. The units shown are the ones that can be
dispatched and they're not close, not include the must run facilities. So, when we get solar
generation, we just take that generation and you run that generation. It's not dispatched.
That might be dispatched if you had a battery, and similarly our run of river projects, we
just took the actual generation and put that into the model. So, what you're looking at are
ones where choices could be made about when generation could occur, and also choices
to be made or not. But outside influences could happen, such as hydro coming in
differently or payments to be happening, forced outages.
Mike Hermanson: What we found out was the total actual generation was 1,130 average
megawatts, while the model generation was 1,122 with relative percent difference 0.18%.
It dispatched on an annual basis very closely and we also conducted an evaluation of the
mark to market production costs, subtracting fuel costs and found that there was a 0.96%
difference between what PLEXOS system cost would have been versus the dispatch

Appendix A
generation. If we have the actual dispatch, did a mark to market, and then we looked at
our actual total expenditures and we've found the difference between 2.96%. As
mentioned in the previous slide, the model production cost was less than the actual
production cost.
Mike Hermanson: The next series of slides show the hourly dispatch for selected
generators. Blue shows the actual generation and orange shows the model generation.
Noxon Rapids is shown on the left and Cabinet Gorge is shown on the right. There are
differences between the model and the actual, but generally follow the same pattern.
Since the model has perfect foresight for water supply and market prices, it's more likely
to move to the maximum generation and then back off to minimum generation then the
projects are actually operated. They just don't necessarily operate that way where you
have a lot of power to measure reactions to it. Prices and the model production cost was
less and the actual revenue from the actual generation was slightly greater than the model
generation, I should say had more revenue than the actual generation, but it was fairly
close. As you can see, the difference between the two just on average generation of
PLEXOS being 178.5 average megawatts versus an actual generation of 179.8 and the
things we were checking on was how we have our generators set up in PLEXOS. How is
that water actually taken and turned into energy? Do we have all those parameters set
up correctly? This is a check on that.
Mike Hermanson: As you can see, over on the right-hand side is the Cabinet hourly
generation. You can see over on the September, October months, there were units out.
We're able to take those units out in both instances and be able to capture that again.
You still see a little bit more opportunistic movement in backing on and off generation in
the model. But we did some adjustments to our ramping rates to try and address that.
Now, we'll see that when we look at the reservoir.
Mike Hermanson: The next two graphs show Long Lake and Little Falls. An interesting
piece here is that the PLEXOS generation in the spring is again using knowledge of water,
prices, and is moving from maximum to minimum on occasion when the actual operation,
is not doing that and that's to some degree you don't know when the water is going to
come off and have them fill a reservoir. PLEXOS did because it had the whole year in
front of it. Operators are making decisions about when to keep the reservoir full and not
full. And you'll also see that dip there in February and March, and that's the annual
drawdown in Long Lake and that really lowers the head. Once you lowered the head, you
lowered the amount of generating capacity from each of the units. We're able to build that
into the system. Again, these look very similar, Little Falls has a very small reservoir and
in essence is run as a run of river at Long Lake. But again, the annual amounts are very
close, and we are able to get the shapes we feel to be very representative of the actual.
Mike Hermanson: The next series of graphs show the total generation facilities from
Chelan, Douglas, and Grant PUD. That's the Mid-Columbia hourly generation
comparison. Again, it's able to follow the general patterns that occurred at those facilities.
We have a contracted portion of generation at each one of these facilities and we have

Appendix A
the ability to dispatch the plants within constraints that are provided by the PUD. The
graph on the right is for Coyote Springs 2, which is a natural gas combined cycle facility.
The actual values move, in the blue. They move more than the model values and that is
because generation is dependent on temperature and so you have daily temperature
movements in an effort to get more model efficiency and be able to keep the model
running as quickly as possible, we ended up using monthly values and it's a very good
approximation.
Mike Hermanson: This next one shows Lancaster. It's a contracted combined cycle
facility, similar to Coyote Springs 2, and the actual value shows more variance than the
model. Rathdrum is on the right-hand side and it's a simple cycle peaking facility. It has
the largest percent difference between the model and actual values, and that is just due
to the different ways that the model was able to address some of the peaking mode that
came in, and so it didn't have to rely as much on this peaking facility to meet below.
Mike Hermanson: These four charts show the reservoir storage level throughout 2021
for each of the storage projects. On the left is that reservoir elevation, the forebay
elevation, and across the horizontal axis is the months. You can see in the Noxon graph.
You can see one of the changes that we made to. To kind of back off, PLEXOS' inclination
to jerk the reservoir around, so to speak, which just operationally does not happen. We
limited the hourly ramp rate and so that tightened up the reservoir movement as you can
see in the springtime months. We were moving that around quite a bit more in actual
operations, but to match the dispatch. We constrain the hourly ramping and that tightened
that up a little bit.
Mike Hermanson: Looking at Cabinet Gorge, the orange is the model value. You can
see how it likes to move hitting those hours where the market values are high. It's still
within the range of what we actually see, but the reservoir does not move around quite
as much as PLEXOS would like to do it. Or does do it in Cabinet over many iterations of
trying different ways of time, tying the dispatch of these hydro units, this combination of
using this hourly ramp rate at the reservoir at Noxon ended up providing the best match.
Mike Hermanson: If you look at the graph on the right-hand side. Those are for Long
Lake and Little Falls. The bottom shows Long Lake and there's a drawdown that happens
in springtime months, and then a significant increase, and then it runs within a fairly
narrow band of reservoir heights. It's not doing big reservoir moves to meet price and
that's a constraint that was put in to match the actuals. I guess this whole effort was really
to get hydro to be close to the way we operate it, so that the rest of our system can
balance against that and get a much more accurate picture of what the dispatch looks
like and the production cost.
Mike Hermanson: You're probably wondering on Little Falls. Little Falls operates within
a really tight band. You can see that PLEXOS is operating it within quarter of the foot.
Those are in half foot increments and that graph in actuality operates slightly different
with a little more volatility, but not much more. And also, halfway through the year before

Appendix A
my elevation data, something happened with it in 2021. So, it only had a half year's worth
of data.
Mike Hermanson: These last slide shows the model value for model versus actual values
for the Mid-C reservoirs. And as I said, this isn't the sum total of how the Mid-C reservoirs
are acting. This is how the portion that Avista controls is moving, it's not moving in total
unison, but the magnitude and the variance. This is fairly similar. We're able to match the
timing and the actual output for this Mid-C system fairly well. When we came to that end
of all of these exercises, we came to the conclusion because PLEXOS we were just trying
to test it out and figure out how well is this going to work for our system? We've been
using Aurora for a long time, and I think we came to the conclusion that we can flex.
Those can be used for the dispatch and match with and incorporate all of the constraints
that we want. There's still more that we want to build it into it, and so our next steps are
that. Building this into our IRP modeling.
Mike Hermanson: This is just looking at one year, whereas we'll be building out the full
20-year IRP and doing adding additional resources and doing that iterative process of
looking at what we can generate out of PLEXOS versus what we can generate out of
PRiSM and going through that process. But I'm not sure if there's any other questions as
a lot of information all at once.
Lori Hermanson: There's no unanswered questions in the chat. There were several
people that gave us additional information on resiliency, which we will follow up on.
James Gall: Alright, well, there's no questions for Mike. I appreciate the presentation. A
lot of work has gone into PLEXOS and like I said, we see a bright future for it and the
IRPs to come. We are little under 1/2 hour ahead of schedule, which is great, which
means we can take a break. I think we could probably get back and finish early, so let's
take a break until 10:30. Does that work for everybody? And then we'll get started on the
available resource options with Lori at 10:30 and then finish up with the Work Plan and
then adjourn, hopefully by 11 :30, we can get done early, so we'll go on mute and see you
back here at 10:30.
Available Resource Options Discussion, Lori Hermanson
John Lyons: Well, welcome back everyone. Hopefully you got a chance to get up and
stretch a little bit as we get towards the end of our first TAC meeting. Lori is going to be
up first and talk about generation resource options and then after that, I'll finish up with
the Work Plan.
James Gall: We're thinking we'll probably be out about 1/2 an hour early today and before
Lori gets started, this is an area where we like to get TAC feedback, so don't be shy. Use
the chat. Lori will be monitoring the chat as she's to presenting and they go away. Lori.

Appendix A
Lori Hermanson: Good morning. I'm Lori Hermanson and I'm going to cover the resource
options that we included in the last IRP for review. We would like your input as to whether
or not you think that we should maybe not include ones that we did include, or maybe
we've missed some. We'll talk about that as we go through, but that's basically where
we're looking for feedback. If you want to go to the next slide, I'll start with the natural gas
turbine options. We tried to model one of every different category, peakers and base load,
and then the types of peakers. For peckers, we modeled a simple cycle combustion
turbine frame type engine. The model is 2 units totaling 180 megawatts for the
reciprocating engines. We modeled 10 units totaling 185 megawatts for baseload
engines. We modeled a combined cycle combustion turbine 1x1 with duct fire, and that
totals about 312 megawatts for these combinations. For these types of turbines, we also
looked at different fuel types and not just natural gas — renewable natural gas, hydrogen
in the form of ammonia, and synthetic natural gas. For these natural gas turbines, we
considered them as Avista owned resources that would have a 30-year average measure
life based on the policies that we're seeing in Washington and Idaho. We're going to
continue to look at non-natural gas fueled options for Washington. But in Idaho will
continue to look at all fuel types, and then we'll also continue to model and evaluate, or
evaluate and model, potential upgrades of our existing facilities. Next slide please.
Lori Hermanson: We looked at renewable resources such as wind and solar. On the
solar resources, we looked at varying sizes, applications, and storage options. We looked
at a residential 6 kW unit as our resource option as well as a commercial one MW option.
We looked at a 5 MW resource that was a fixed array. All of those, we modeled them with
and without battery options. We also looked at single array or single access tracking
arrays of varying sizes from 50 to 100 megawatts and varying sizes of storage duration.
The ones that have lesser storage, those are used for integration purposes. If it's a longer
duration storage, the model would pick them because they're needed for load shaping.
For wind options, we looked at 100 MW options for all of them starting with on-system
and off-system wind with the difference between those being the cost of transmission.
Off-system, we looked at Montana wind because that was of interest for our stakeholders.
We also looked at offshore wind, which was 100 megawatts of a larger share project of
about 1,000 megawatts. For all of these, they are proxy sizes and Pacific Northwest
locations. What the model does is it would look at these minimum sizes of say for wind at
100 megawatts, but it might end up selecting up to 400 or something at whatever makes
sense based on the needs of our system. Again, we put them in as a minimum size and
then it picks accordingly based on those minimum increments. So next slide please.
Lori Hermanson: We looked at other clean resource options such as geothermal. This
would be a PPA of about 20 megawatts and it's an off-system resource because there's
none right here in our service territory, so it would incur or include transmission costs. We
looked at biomass, a generic biomass resource option, an example of that would be an
upgrade or an additional unit at Kettle Falls or something else in the area. Something
around that size of 58 megawatts. We also modeled a nuclear PPA as an option, it was

Appendix A
100 MW option, which is just a share of a larger off system resource and that's a mid-
sized nuclear facility. And we also looked at a 25 MW fuel cell. Next slide.
Lori Hermanson: For storage technologies, we looked at more sizing and storage
duration combinations and types of storage technologies than we had in the past IRP.
Lithium ion, being one of the larger categories. We assumed a round trip efficiency of
86% of 15-year average operating life for those resources. We assume that we're the
owner of these resources. We modeled various sizes of distribution and transmission
level ranging from 5 megawatts to 25 megawatts. And again, the storage duration varied
anywhere from 4 hours to 16 hours. We looked at other storage options such as vanadium
flow, zinc bromide, liquid air, and iron oxide. I believe of all of those, the only one that was
selected was iron oxide. Something that we're considering, and we'd like feedback on
this, is maybe not modeling all of those, maybe just modeling iron oxide and lithium ion.
Those were the ones that were selected this last time, but again, based on feedback from
the groups. Also, based on reading and research in the industry, the lithium ion and iron
oxide seem to be moving ahead, whereas those others don't see as much progress. We
also modeled a few different pump hydro options, and these are again varying durations
from 10 hours to 24 hours and increments in between. It would be basically a share of a
larger project anywhere from 1 ,000 to 2,400 MW hours.
Lori Hermanson: Next slide, some additional things that were continuing to research that
you're all probably hearing about these in the industry as well. Carbon capture and
storage. This is where you capture the CO2 from generating facilities and then store them
into underground geological formations. The only thing with this is there aren't really any
of these geological formations in our service territory. We continue to follow the literature
on those. There's been a lot of information out there on fusion reaction. That's where they
have a nuclear reaction that creates a lot of heat or energy problem with this one. There
aren't really any real costs out there. We haven't come across cost associated with that
type of project. There are other battery options like organic, solid, flow, energy storage
that's a proprietary non-flammable mixture of solid and water-based electrolytes. That's
using renewable energy to heat carbon or graphite blocks too really high levels about
2,200 degrees Fahrenheit stored within insulated containers and then using that heat on
demand as it's needed. I believe we've modeled some. We've included this in some of
our demand response modeling done by AEG. As far as the molten salt heat storage,
that's another one where you can use concentrated solar to direct it to a centralized
receiver and raise the temperature really high to heat the salt medium and again, dispatch
that as the heat is needed through a heat exchanger to produce steam. But there aren't
really any steam turbines in our in our service territory where that could be applied.
Lori Hermanson: Those are some of the things that we've continued to follow and are
researching. We'd love to hear information or feedback on other options that you might
be aware of. As far as new hydro, we're always looking at possible expansions within our
service territory such as our own units like Long Lake or Cabinet Gorge adding an
additional unit at Post Falls. We recently obtained a contract with Columbia Basin Hydro

Appendix A
and there might be some discussion about extending their irrigation canals. But then
there's some consideration as to whether or not that would apply for CETA as new hydro
or not. And then we also continue to evaluate new hydro like in the last RFP. We acquired
additional slices of Chelan, and we continue to look at those. We have a Douglas [PUD]
contract that expires in 2028, so the potential of expanding or extending something like
or other things that might become available through BPA. That's everything in a nutshell.
What was modeled and some potential considerations of things that we may model less
of, for example on the storage or potential new technologies that are out there. We'd
basically like to open this up for discussion with the group and see if there's any additional
information you'd like to see more of, or less of, or new technologies that you're interested
in that you think we should be modeling.
James Gall: If you need more time, don't be shy to email us afterward or enter something
into the chat. What we're trying to do is, we have a limited amount of time to research
technologies. What we're seeing in RFPs, we followed the Power Council, but we want to
make sure we're not missing something that's in development now. I'd say that the one
technology on here that we mentioned in passing is nuclear. There's been a lot of talk
about small modular nuclear. I think we've taken the approach on that is to just keep it as
a nuclear PPA option. That could be small modular. It could be something else. I'd say
it's the one technology not talked about here but is definitely worth evaluating. These are
going to be challenges that we have to face because the CETA goal of 2045 to be 100%
renewable or clean energy requires technology sources that are not common today. We
have to figure out long duration storage. Hydrogen-based fuels is what we found in the
last IRP, along with iron oxide storage, was a potential pathway. But, as you do IRPs
every two years and we need to evaluate if there are other pathways, because the IRPs
before the 2023 did not even contemplate either of those technologies. Hoping that you
know something comes around, but if you see something that's on the horizon, you see
a journal article, just feel free to send it to us. We do want to ensure that whatever
technologies we put in the IRP are commercially feasible. They don't necessarily have to
be in development today and viable off the shelf, but they have to be something that's
feasible and likely to be available in the time horizon. Fusion, for example, is maybe one
of those resources, maybe it will, but it's not quite there yet as a proven technology. So
that would be the one, for example, that we might not want to include. That's why we do
IRPs every two years, and it might be available.
John Lyons: We also can add discussions on the new technology even if they're
basically so far out of the realm of costs that they don't get modeled. We can still include
them in the IRP as a discussion. We can start seeing where those would fit in and maybe
even do some tipping point analysis to decide where that technology would have to be.
We've done that in the past with nuclear where the thought was, we would not model it
because it was too expensive, but we modeled how much lower the cost would need to
get before we could implement it. That might be a good way to look at some of the new
technologies. Also, we have opted not to as some other utilities model, we want to use a

Appendix A
resource that looks like this, but they haven't identified it, and we've opted to stick with
resources that are known and identifiable.
James Gall: Alright, I still don't see any comments, so I think we'll leave that one there
for future discussion and we'll plan with these set of resources. We'll develop costs and
other assumptions and there was a spreadsheet that you may recall from the last TAC
process that went through our assumptions for each resource and a forecast of those
costs. We'll work to update that spreadsheet with these resources and share that with the
TAC when it's available. As Lori mentioned, there were a couple of resources that we
were thinking about removing on energy storage. I'll go back to those real quick. They
were not selected in the plans, and I wouldn't say development is stopped on these, but
we're not seeing a lot of uptake in those resources in the energy space. But I just wanted
to know if there's any objections to removing those. We're not going to yet, but just wanted
to make an opportunity to voice any concerns about removing anything from the list,
before we do that.
John Lyons: We've seen a real decrease in the number of the flow batteries that are
showing up around the country, being bid in, and actually being done. Yao has a question,
why did the model not select the storage?
James Gall: So, the ones that are in red, it's really a cost in round trip efficiency. There
are you know, two trade-offs of storage. Either you are going to have a low round trip
efficiency, you got to be very low cost. And if you're going to have a high range efficiency,
there's likely a higher cost. And in these cases, there was better technologies for the cost
or the efficiency for these not to be picked, I definitely think we need to keep following
them. With moving to PLEXOS, there is a limited amount of studies we can do and I don't
want to burden that model on the first time around with technologies that are probably not
going to show up.
John Lyons: The big issue we've seen with the flow batteries and the liquid air is the
constantly heavy pumps running. So, you have this this parasitic load that's going on all
the time, whereas a lithium-ion battery, you don't think about. If you've got a power tool
that you charge the battery up last summer and then you pop it in this next year, and it
works just fine. On a flow battery, you would be out of power in not that long of a period
of time because they are always running.
James Gall: OK, so let's switch to the Work Plan and then we'll wrap things up. Thank
you, Lori. Bear with me one second while I find it. There it is.
John Lyons: You're building suspense. You know the excitement of the Work Plan. They
just excited that we're getting close to finishing right now. We're being efficient alright.
TAC meeting efficiency, that could be an Action Item.
James Gall: All right, John. Alright.

Appendix A
Work Plan, John Lyons
John Lyons: So, on the Work Plan, you would have seen that sent out with the draft
slides. Go to the next one here. The Work Plan, as we talked about earlier, we do an IRP
every two years — full IRP in Washington every four and a Progress Report in between.
The Work Plan shows what the process is going to be and the major milestones, those
key events that are going to be done. It starts with an overview discussion. This is going
to look very similar to past Work Plans. There's the TAC meetings and the major topics
on the meetings. We try to stick to those, but if we have new topics that people would like
to discuss or new information that comes to light, we will put those in there. We have a
document outline by chapter and then the timeline of major assumption. Big assumptions
would be market price assumptions, gas and electric price forecast. Third party studies
missing a "y" there. And a study request from the TAC, anything that comes up there and
next slide.
John Lyons: PLEXOS, as we already talked about, it's going to be used to model
resource dispatch, resource option valuation and market risk evaluation or analysis.
PRiSM is still going to be used for resource selection. That's something we talked about
earlier, considering a change in the future. But for this IRP, Aurora will still be used in this
IRP for electric market price forecasting, and we will be evaluating other options for the
2027 Progress Report. Idaho IRP, as we discussed earlier, AEG is going to develop the
energy efficiency and demand response potential studies. They're going to develop a
long-term energy and peak load forecast using end use techniques, and then they'll also
be doing a distribution energy resource potential study. That would show types, locations,
give us some more data on that. And then we intend to use generic resources functions
from several different sources. As we just talked about, is based on likely generation
sources, so size even though when it actually goes out to an RFP, the sizes maybe slightly
different based on the technologies each company has a, they're all reasonably close to
each other, but they'll be some slight differences.
John Lyons: We just had our first TAC meeting and the next one's going to be March
26t" in 2024. We'll get the gas and electric price overviews, wholesale electric price
forecast, the variable energy resource integration study results. We started talking about
those more last IRP cycle and we've done more work on that future climate analysis
update and TAC scenarios feedback. We'll have some studies set, that we think you
would like to see done, or that we're planning on doing, and then we'll get some input
from all of you that you would like to include. These later dates, we haven't nailed down
a date yet. We're just checking to see that month wise that works for people and then
we'll see which of the timing works. We had a question from Yao.
Lori Hermanson: Yeah, she says, Aurora's market price forecasting depends on
dispatch resources. If the dispatch is done in PLEXOS, how can the market price forecast
correspond to the resource dispatches?

Appendix A
James Gall: great question. Aurora will continue to do a resource dispatch of the Western
region. So, we'll do an expansion capacity study for the region. It just will not be an Avista
focus. We'll end up with a regional price forecast for different locations and then feed that
price forecast into PLEXOS. I guess the assumption we're making here is the resources
that we choose, if they differ, then what the original forecast is by Aurora, that they're not
going to impact the regional marketplace and basically what that means is we are a price
taker. Because Avista is relatively small, the things that we do are not going to have a
major shift in the western market. So, you could definitely argue a small disconnect there.
But we think it's pretty minimal to Avista's process just because of our size. And because
brought up a price forecast, or you brought that up Yao, we are looking at using PLEXOS
for market price forecasting in the future in a similar way that Aurora does. That is a
functionality that it can do. If that proves out plausible in the future, we could do a price
forecast and a resource forecast at the same time. I'm fearful that the length of time that
it would take to solve maybe a challenge, but long term we are looking at options to use
external forecasts for prices for the wholesale market, but we've not made any decisions
there. I think there was another question.
Lori Hermanson: Yeah. She asked about if PLEXOS doesn't look at regions, only Avista,
and they do have a similar regional database like Avista. Like Aurora does, we currently
don't have it purchased, the database, and we're doing kind of a closed system model of
just our own system. But that's something that we would consider in the future.
James Gall: Alright, thanks. Go ahead, jump in John.
John Lyons: OK. TAC 3 in April 2024, again we will be coming up with the actual dates
on those. Also, if there is any input from the TAC of days of the week you would like us
to focus on or to avoid. We generally want to not have TAC meetings on Mondays or
Fridays, so we try to focus on Tuesday, Wednesday, Thursday. Then we look at the Idaho
and Washington Commission calendars to see when they have major dockets on or open
meetings. In April, we will be captivated with Grant's economic forecast and five-year load
forecast. That is always a fun one. OK. Maybe just for me as an economist, but we do get
good feedback on that long run forecast. The rest of this meeting will be AEG focused
and all the studies they've done. That'll be that fundamentals-based forecast that we
talked about earlier that they're doing. We'll have the Conservation Potential Assessment
that will be split for Idaho and Washington that they've been running for us for several
years. There will be a demand response potential assessment and then we'll review the
plan's scenario analyses.
John Lyons: The Fourth TAC meeting will be in May of 2024. We will look at the IRP
generation options, transmission planning studies and what those costs and what those
are going to entail. Distribution system planning within the IRP and the DPAG update that
we talked about earlier, trying to integrate our two processes, transmission distribution
modeling in the IRP, the L&R balance and methodology to show what loads were serving,
what resources we have going out over the next 20 years and then new resource option
cost and assumptions. That's where we'll be seeing the big nasty spreadsheet that is the

Appendix A
backup for what Lori just talked about showing all the different cost and the nuances of
that data, sizes, how much we can get in a year, how long it takes to get it online,
environmental considerations, all of that.
John Lyons: The fifth TAC meeting in June of 2024, that is going to be one that is very
heavily modeling focused. Maybe if modeling's not your thing, that would probably be a
good one to skip. If you want to get into it though, that is always a fun one. We'll have
tours of PLEXOS, PRISM and the new resource cost model. Anything else you wanted to
add on that one, James, that'll be nerd fest. It's a lot of fun.
John Lyons: July of 2024, we've got our Preferred Resource Strategy results. That's all
that work being done finally results in the mix of resources, types, sizes, timing over the
next two decades. We'll do the Washington Customer Benefit Indicator impacts resiliency
metrics. Finalizing what we kind of teed up a bit earlier today, portfolio scenario analysis,
market risk assessments and the qualifying facility avoided cost for PURPA projects, and
then we'll wrap up this 2025 IRP with the virtual public meeting. It'll be joint natural gas
and electric. There will be recorded presentations about each IRP side, and a daytime
and an evening period for comments and questions where it will be broken out, very
similar to what we've seen in the past.
John Lyons: As far as the draft outlined, this is what the chapters will look like. A couple
little changes, we've moved some things around, but similar overview. There'll be a short
executive summary, introduction, stakeholder involvement, process changes, that's an
important one, especially following along to see what's changed one IRP to the next. Then
we get into the economic and load forecast, the regional economic conditions, the energy
and peak load forecast and the different load forecasts and scenarios. Third chapter is
what resources we already have in line, our own resources, contractual resources and
obligations, and customer generation, so behind the meter type of things. The fourth
chapter is the long-term position, regional capacity requirements, energy planning
requirements, reserves and flexibility assessment.
John Lyons: Fifth chapter, we get into distributed energy resource options. We'll have
energy efficiency potential, demand response potential, energy storage resource options
and the potential for those options for named communities and DER Study conclusions.
John Lyons: Sixth chapter is going to be Supply Side Resource Options, discussion of
the different options that Lori had brought up and the characteristics of those plant
upgrade opportunities both for our thermal and our hydroelectric facilities. We will also
have a discussion of those non-energy impacts that we talked about briefly earlier today.
John Lyons: Seventh chapter, Transmission Planning and Distribution. It's an overview
of our transmission system, what the construction cost and integration is going to be for
those, merchant transmission plan, and an overview of our distribution system. That's one
area we've been expanding over time, is bringing more of the distribution system into the
IRP and the DPAG information.

Appendix A
John Lyons: Eighth chapter, Market Analysis. Wholesale gas and electric price forecast
and the scenario analysis. Ninth chapter, critical chapter in the IRP, the results, the
Preferred Resource Strategy, the market exposure analysis, and the avoided cost.
John Lyons: Tenth chapter, this chapter will be portfolio scenarios and market scenario
impacts and then we'll do the Washington Clean Energy Action Plan. That's the decision-
making process involved with that resource needs, resource selection, and those
Customer Benefit Indicators. This is one that will just be everything for CETA, basically,
and then we wrap up with the Action Plan where we look at, as James talked about earlier
today, what we've been doing on some of those Action Items. We'll do a thorough
overview of where we ended up with the ones from last time and what either is ongoing
or came up and we ran out of time, or it's an up-and-coming event or issue that we want
to address.
John Lyons: And then the major timeline. December is the goal to have the market price
assumptions. Natural gas price forecast and electric price forecast will be in March of
2024. New resource option cost and availability, also in March the deliverables from AEG,
all of those studies that they're doing for us, final energy and peak load forecast, efficiency
and demand response assessments for potential, the locational energy efficiency and
demand response potential.
John Lyons: Sometime a little later in April, transmission and distribution study
completion. March 20th, the due date for study requests from TAC members. The earlier
you can get those requests to us, the more we're able to accommodate them, that's the
date we know we can get to them if we get them by then. If there's things that come up a
little later, we might have some room to stretch some of that. But that might be an issue
where if we can't, it ends up being as an Action Item. The earlier you can get those to us,
the better. May of 2024 will be determining the portfolio and market future studies. June
1st would be finalizing resource selection and model assumptions and you'll notice in this
Work Plan. We didn't go into all the details of when things would be written, we will be
again sharing those. The plan is to do that through Teams if that works, if not, we'll either
do something else, or revert back to how we've been sharing them through the website.
James Gall: John, one thing I didn't see on here is when we will be filing the document
and when the draft will out.
John Lyons: I wanted to leave a surprise for everyone. No, I didn't. I forgot to put that on
there. We will be filing January 1st. You'll notice, this is a little condensed from the last
one. For those of you that weren't with us last time, we had an extension for Idaho
because we were waiting for the results of a renewable RFP and we had some significant
amounts of resources that came online and we didn't want to put out a plan and then
immediately have to change that plan because all these new resources. We had an
extension of Lancaster, Columbia Basin Hydro, Clearwater Wind and we had the Myno
project at Kettle Falls. There were some major changes that were going on there. I'm
trying to remember, January 1st, 2025 will be the date. That also coincides with a CETA

Appendix A
rule in Washington that changed our dates. We used to have them due in August, but it's
always going to be January 1 st now and is it October or is it earlier for our draft?
James Gall: I think it is October 1st
John Lyons: I will update that final slide.
James Gall: Alright, any thoughts on the Work Plan? John and I have been doing these
since 2005 like he mentioned earlier, we've kind of followed the same procedures as
we've done in the past. Are there any topics on the TAC meetings that maybe you'd like
to see, that you didn't see? That's something you can always email us about later if you
don't have anything on top of your mind right now. We are going to be finalizing the Work
Plan and filling it with the Washington Commission, I believe on the 1 st of October. So, if
you have any comments on the Work Plan, please try to send those to us as soon as you
can and we'll try to include those in the final filing. We can always revise the Work Plan
as we go through time, but it will be filed on the 1 st, or if that's not, that's on the weekend.
John Lyons: Yeah. It will actually be in by the end of this week. We'll be getting this
wrapped up.
James Gall: Any last comments or thoughts before we wrap up the day?
John Lyons: Alright. Well, thank you for participating in the Technical Advisory
Committee meeting. We look forward to working with you for the 2025 IRP. And again,
we're always available for questions, comments, all things you just want to chat about for
resource planning, we really look forward to doing that.
James Gall: And be on the lookout for your Teams invite very soon, so hopefully it'll work
alright.
John Lyons: Thank you. Have a good rest of your day and enjoy getting 50 minutes
back.
Meeting Chat:
[9/26/23 8:59 AM] Charlee Thompson: Looking forward to reading the update!
[9/26/23 9:12 AM] Wilson, Kirsten G. (DES): Gall, James I found when I set up an
external facing Teams site for a project that DES Energy is doing, that non state
individuals invited to the Teams site could access more of the site if they logged into the
site via a web browser rather than the Teams App on the computer. Probably the same
is true for yours.
[9/26/23 9:32 AM] Brandon, Annette: James, can I comment on this?
[9/26/23 9:33 AM] Moline, Heather (UTC): thanks, annette!
like 1

Appendix A
[9/26/23 9:40 AM] Tina Jayaweera (NWPCC) (Guest)
FYI, The RTF sponsored a study last year on how to quan5ify resiliency value of
EE. Details can be found here: https://rtf.nwcouncil.org/other/energy-efficiency-
resilience-valuation-methodology-study
[9/26/23 9:42 AM] Moline, Heather (UTC): even more on resilience: pretty simply,
OPUC is using presence of solar/storage in low/moderate-income areas with minimal
infrastructure and/or high energy burden as a 'proxy' metric for resilience
[9/26/23 9:43 AM] Moline, Heather (UTC): 2023 OPUC Equity Metrics - Energy Trust of
Oregon
2023 OPUC Equity Metrics - Energy Trust of Oregon
[9/26/23 9:45 AM] Hermanson, Lori: Thanks everyone for the additional info on
resiliency. We'll continue to research these and more and incorporate as it makes
sense.
[9/26/23 9:48 AM] Yao Yin: do costs of market purchases and revenues of market sales
include wheeling costs and revenues?
[9/26/23 9:49 AM] Hermanson, Lori: Yes
[9/26/23 10:00 AM] Yao Yin: Are all the input data actual data in 2021?
[9/26/23 10:19 AM] Gall, James: we are on break and be back at 10:30
[9/26/23 10:47 AM] Yao Yin: Why did the model NOT select those storage?
[9/26/23 10:53 AM] Yao Yin: AURORA's market price forecasting depends on dispatch
of resources. If the dispatch is done in PLEXOs, how can the market price forecast
correspond the resource dispatches?
[9/26/23 10:55 AM] Yao Yin: PLEXOS doesn't look at regions, only avista?
[9/26/23 10:55 AM] Yao Yin: thanks!
[9/26/23 11:08 AM] Charlee Thompson: Thank you!
[9/26/23 11:08 AM] Dennis, Joshua (UTC): Thank you

Appendix A
1l
2025 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 2 Agenda
Tuesday, January 30, 2024
Virtual Meeting
Topic Time Staff
Introductions 8:30 John Lyons
How Avista Includes Equity Principles 8:40 Annette Brandon
Customer Benefit Indicators 9:30 Annette Brandon
Break 10:30
How Avista Practices Equity Outcomes 10:45 Tamara Bradley
Equity Planning in the IRP 11 :30 James Gall
Adjourn 12:00
Microsoft Teams meeting
Join on your computer, mobile app or room device
Click here to join the meeting
Meeting ID: 283 204 777 218
Passcode: SpuoP
Download Teams I Join on the web
Or call in (audio only)
[phone]„651652858# United States, Spokane
Phone Conference ID: 651 652 858#
Find a local number I Reset PIN
Learn More I Meeting options

���r r/ISTA
2025 IRP TAC 2 Introductions
John Lyons, Ph.D.
Technical Advisory Committee Meeting No. 2
January 30, 2024

Appendix A
Meeting Guidelip'Oft 'aft' 'r
• IRP team is in office Monday - Wednesday and also available
by email , phone and Teams for questions and comments
• Stakeholder feedback responses shared with TAC at meetings,
in Teams and in Appendix
• Working IRP data posted to Teams
• Virtual IRP meetings on Teams, in person available for full day
meetings
• Final TAC presentations, meeting notes and recordings posted
on IRP page
z

Appendix A
Virtual TAC Meeting Reminders
• Please mute mics unless speaking or asking a question
• Raise hand or use the chat box for questions or comments
• Respect the pause
• Please try not to speak over the presenter or a speaker
• Please state your name before commenting for the note taker
• This is a public advisory meeting — presentations and comments will be
documented and recorded
3

Appendix A
Integrated Resource Planning
The Integrated Resource Plan (IRP):
• Required by Idaho and Washington* every other year
— Washington now requires IRP every four years and update at two years
• Guides resource strategy over the next twenty years
• Current and projected load & resource position
• Develop alternative load/customer forecasts
• Resource strategies under different future policies
— Generation resource choices
— Energy efficiency / demand response
— Transmission and distribution integration
— Avoided costs
• Market and portfolio scenarios for uncertain future events and
issues
4

Appendix A
Technical Advisory Committee
• The public process piece of the IRP — input on what to study, how
to study, and review of assumptions and results
• Wide range of participants involved in all or parts of the process
— Ask questions
— Always looking for help with soliciting new TAC members
• Open forum while balancing need to get through topics
• Welcome requests for studies or different assumptions.
• Available by email or phone for questions or comments between
meetings
5

Appendix A
Todav's Agenda - Equity Focus
8:30 Introductions, John Lyons
8:40 How Avista Includes Equity Principles, Annette Brandon
9:30 Customer Benefit Indicators, Annette Brandon
10:30 Break
10:45 How Avista Practices Equity Outcomes, Tamara Bradley
11 :30 Equity Planning in the IRP, James Gall
12:00 Adjourn
6

Equiq"n i i era ions
Annette Brandon
Technical Advisory Committee Meeting No. 2
January 30, 2024

�u �ISTA
Overview of Equity

Appendix A
Dictionary Definition
equity [i ty [ ek-wi-tee ] SHOW IPA
a
i
See synonyms for equity on Thesaurus.com N% mole
e
noun,plural eq•ui•ties. rr►
1. the quality of being fair or --�
impartial; fairness; impartiality: the equity of
Solomon.
2. something that is fair and just: The concepts and o 0
principles of health equities and inequities are \� a
important to society as a whole. flip
3. the policy or practice of accounting for the
differences in each individual's starting point when VIE R
pursuing goal or achievement, and working 3
p g a g g to
remove barriers to equal opportunity, as by providing
support based on the unique needs of individual
students or employees.: Compare equality (def. 1).
�uVISTA

Appendix A
Equityat
Focused on fair opportunities and access to resources which contribute to fair, equitable outcome
Fairness
• A "fair process" is defined as focus on EQUITY VS EQUALITY
ensuring no group of people share
disproportional burden associated with
policies, decisions or actions
Foundation: Meaningful participation oth have similar
origins revolving
. .
• awareness and opportunity to around
and evenness.
participate
. . . ...
• has the ability to influence decisions Societal
system term.
. .
• Is considered in the decision-making : •
process
• outreach efforts seek out and facilitate
involvement of those potentially
affected.
°iwrsra

Evolution of E Appendix A
Equitably sharing the benefits and burdens involved in the production and consumption of
energy services and Fairness in how people and communities are treated in energy decision-
making
Environmental Justice 1970-1980
Participation in environmental Decision Making
Recognizes disporportional impacts
Advocates for right to clean environment
Climate Justice 1990-2000s
Climate change (i.e., fossil fuel) impacts
Emphasizes solutions do not perpetuate or worsen
social or economic inequities
Energy Justice 2010
Reinforces need for voices in decisions
Emphasizes need for affordable and clean energy
Focus on inclusive in decision making
Today — Focus on Just Transition to
Clean Energy
5 �ii I STA

Transition to Clean Energy
Appendix A
Inclusive Process Transparent,
understandable
V
• V MEANINGFUL PARTICIPATION MEANINGFUL PARTICIPATION
uf 4;1 i u OL
• V
MEANINGFUL PARTICIPATION • •
V • MEANINGFUL PARTICIPATION � •
i ♦ V V
Clean Energy for Some V V
Diverse Perspectives
Clean Energy for All
Avista is Committed to a Clean Energy Future for all of our Customers
6 °i�ir�sra

Appendix A
Balancing Multiple Objectives
/III _
�►►i�/ISTA � �
Federal Justice4l) -, Providence
NERC
0 Spokane .� 19NAPNORTH AMERICAN ELECTRIC �
RELIABILITY -- - Regional �II�
Clean Air4ency NEK N(3OR5 8r tOUA SiD£
•
Clean Energy P•_ LIBRARYLIC
Transformation Act
uTc „*1�
Washington Utilities
and Transportation 2
Commission
WECC E
Climate Commitment Act DEPARTMENT OF ECOLOGY
DEPARTMENT OF State ofWashin ton
ECOLOGY �> g
State of Washington Avista Serves Approximately
480,000 WA Customers Kettle Falls
Electric .
•Seattle
Natural Gas WASHINGTON
Spo
•
. �Mnv�'� iackson pray
r_e •Othello
Electric and Natural Gas Natural Gas Storage
Pullman
•evenson Goldendale Clarksto
Federal Energy Regulatory •
Commission
7 Energy Advisory Group (EAG) ,aliiVISTA"

Appendix A
�uvISTA
Regulatory Requirements

Appendix A
Washington State Equity Requirements
Clean Energy Implementation Plan 2019
Focus on "just transition"
■ Strong Public Participation \ PIT
Customer Benefit Indicators }^.
Avista General Rate Case Conditions 2021
Capital Planning must consider and implement energy
use tice and its core tenets."
Recognition, Procedural, Distributive, Restorative -
Climate Commitment Act 2022
■ Environmental Justice Council
Washington State �
■ Invest in those communities most impacted by OFFICE OF Eo,.uITYI-- 7climate change
9 �HI STA

Clean Energy Implementation Plan Requirements Appendix A
• Avista will apply Non-Energy Impacts (NEIs)
and Customer Benefit Indicators (CBIs) to
all resource and program selections in
determining its Washington resource strategy
• Avista agrees to engage and consult with its
applicable advisory groups (IRP Technical
Advisory Committee (TAC) and Energy
Efficiency Advisory Group (EEAG)) regarding
_ .. an appropriate methodology for including NEIs
and CBIs in its resource selection.
• Avista will consult with its EAG after the
development of this methodology to ensure
the methodology does not result in
, inequitable results
10 �iiVISTA

Appendix A
Non -Energy Impact
• Contribution of investments that goes beyond the Particint Benefits
energy and demand costs • '
O & M Savings Employee Productivity
• Increase
Impacts (either positive or negative) can come in
the form of economic, social, environmental, Health Benefits Property Value Increase
and/or personal ways. Comfort Increase Benefits to Low Income
Customers
Societal
Public Health Economic Development Peak Load Reduction Less Debt Write Off
Improved Air Quality Increased Employment
Transmission and Lower Collection Costs
Water quality and quantity Energy Security Distribution Savings
Benefits to Low Income Reduced arrearages Fewer customer calls
families
11 �ii I STA

G PW* Appendix A
quirements :
eneral Rate Case
Energy Justice Core Tenets
"The processes or procedures Avista considers for all capital planning should consider and implement energy justice
and its core tenets. The core tenets of energy justice are: recognition, procedural, distribution, restorative.
Customers, communities, employees
• Identify: Who and where do inequities a�d��tergenerationa/
• • - exist?
Recognition JustAwareness, understanding, recognition
• Barrier considerations
" Evaluate Identify
Quantitative Underrepresentedmetricsand qualitative people and
Meaningful Participation �
Distributional, placesff
$ P roced u ra I,
• Due Process / Collaborative � Recognition, D
Process
Fair equitable and inclusive involvement Cosmopolitan, c
Procedural CO-develop nhance
and Restorative 4
• Targeted, intentional education and � Justice a
solutions capabilities
outreach
r
Distribution of benefits, burdens
Performance
Evaluation of alternatives RPspO^sibility,Due PtOceSS
Program design and resource selection
Distribution, Restorative
Accountability

BalancingRequirements — While KeepingCustomerA3tA
the Center 'All
Federal Justice40 Aipa-iffmSTAff Or Providence
Spokane �I I� 19NAP�
NERCRegional
Clean AirApn�y NEi NAJRS J F SIDE
NORTH AMERICAN ELECTRIC
RELIABILITY Copp ORATION
•
6 ow SPOKANE
LIBRARYPUBLIC
Clean Energy
Transformation Act
U Tc
Washington Utilities VIF W E C C
and Transportation
Commission
Climate Commitment Act DEPARTMENT OF
_ �Ammod ECOLOGY
DEPARTMENT OF {
ECOLOGY � State of Washington
State of Washington Avista Serves Approximately
�'
480,000 WA Customers KettleFalla ,_ =
Electric ,
•Seanle
s
Natural Gas . WASHINGTON
oiyn,•
P,a ,Othello
Jackson Prairie Pullman
Electric and Natural Gas . NaWrai Gas Storage
Federal Energy Regulatory
•evenson Goldendale Clarkstont
Commission
13 �iiVISTA"

Resource and Y
Program lifec cle Evaluation Appendix A
"No action is equity neutral . . . .each action either corrects or perpetuates inequities"
Meaningful Participation
Identify • • Prioritize
Execute
Evaluate - - •
Integrated Resource
Pled 9
Financial & Risk Total Company Power Purchase Agreement
Transmission, System & Operational Needs Capacity, Energy Self-Build
Distribution Planning
Equity Cost Effectiveness Program Deployment
Energy Efficiency Cost Effectiveness
System vs. State Project Delivery
Customer Requested Impact to Process or
Performance Metrics A,,,_ _
�ifVISTA

Au �ISTA
Integrated Resource Plans
Process and Performance Metrics

Appendix A
Process and Performance Metrics
Performance
• Who has provided 0• How will my project • How did we do?
impact? produce results? • How can we
• Have we intentionally • Are there measure?
solicited input? O alternatives? • Are there patterns?
• Can I use feedback? • Am I making data-
Have I made driven decisions?
modifications to meet • Predict change or
barriers? trend?
16 Equity Advisory Group �ii I STA

Appendix A
� Newman LakE
Focus Areas
Mead
Country H
JUSTICE 40
T
Who and Where we are focusing our � POLICY PRIORITIES
ow�r a
Count Decrease energy burden
equity efforts: in disadvantaged
tis Orchards communities(DACs)
O
Decrease environmental
exposure and burdens
for DACs
Highly Impacted Communities pokan
N
S okane Liberty La Increase parity in clean
p energy technology access
and adoption in DACs
Increase accesst
Vulnerable Populations capital
i
low-cost ca ital n
DACs
• Sensitivities: physiological impacts Justice40:Spokane County, Increase clean energy
Washington tract 53063000400 X enterprise creation and
contracting in DACs
• Socioeconomic: housing, Population:3,844
Increase clean energy jobs,
transportation, food and health care G�' Zoom to job pipeline,and job training
for individuals from DACs
access, language barriers This tract is identified as disadvantaged. It has 4
categories that meet the criteria. Increase energy
resiliency in DACs
Energy
Healthenergy Disadvantaged Populations democracy in DACs
Housing
Legacy pollution
There are 33 disadvantaged tracts in Spokane County and 306
disadvantaged tracts in Washington.
7 �uVISTA

Appendix A
Data Driven Consideration
Directly related to policy goals and the public interest
readily available
Focused onequitable outcomes
Clearly defined, articulated, and understandable
Based on dependable, pertinent, available data
Allows for comparison or trending '
Transparent _
.S
Correlated with utility's actions; able to forecast -
Updated regularly
Accurately reported regular reporting
18 Equity Advisory Group �uVISTA"

Appendix A
CEIP Customer Benefit Indicators
Fee, OOOP
�► DO ,
o
o
� O� o0 0
Affordability Energy Security Access to Environmental Community Public Health
& Resilience Clean Energy Development
Participation in Energy Availability Methods/Modes of OutdoorAir Quality Named Community Employee Diversity
Company Programs Outreach & Clean Energy
Households with Communication
Energy Generation Greenhouse Gas Supplier Diversity
High Energy Location Emissions Investments in
Burden Transportation Named
Residential Arrears Electrification Communities Indoor Air Quality
& Disconnects
19
�ii I STA

Appendix A
Customer Benefit Indicators in IRP
�— Energy Burden Existing Customer Benefit Indicators:
Clean Energy) • 11 of the 31 CBIs are modeled with forecasted
Distributed Energy values for each metric over the 20-year planning
Resources horizon
Development/Energy
'- e—e
• PRS does not consider CBIs in objective function
Resilience and Security)Planning Margin (Energy
Criteria:
Generation Location Categorized in accordance with benefit areas:
(Energy Resilience - • affordability, development/resilience, security &
*ko/ resilience, environmental & public health,
environmental
Air Emissions
(Environm- Baselines are established and readily available
Data is quantifiable
EmissionsGreenhouse Gas
- Metrics are granular enough to be meaningful
(Environmental)
20

Appendix A
How Metrics are Developed
O�LBenefits Barriers Metrics L I - I 'IL
AA r AA kL A rr A
• Evaluation of • Factors which limit • How do these • Where will we
benefits from participation or benefits correlate utilize metrics?
energy or energy access: with energy
system: • Clean Energy Plans
• Physical Sensitives • Accountability: • Capital Investments
• Social • Socioeconomic Process & • Resource Planning
• Economic • Geographic Performance • Federal and State
• Environment proximity Metrics Grants

Understand Goal : Appendix
All customers, regardless of circumstance, have access to the energy they need for basic
needs as well as social, economic and environmental needs.
r'
r
-t
Energy Social Economic Environmental
Physical delivery Inclusive and Job creation, Public health,
of power accessible economic growth, indoor and outdoor
processes reliable supply, air quality, and
Basic Needs and affordability sustainability
22 �ii I STA

Appendix
Burdens . • Barriers
Affordabilit
Unemployment• or • - - • •
Awareness• of • • ,
• Housing Conditions• HOLA HELLO HEJ
Income • . OI BONJOUR HALLO ��AQ
• Economic impactson • workers
5e'e aee _ 48d •a• 8i4 eee
444 eea:a: '::: -44 aee::Ea_a-= 4d4 eeea
Access .... eee...::,,,, ;... •ee.•.,,•• .w. eua°.
' ,� euezi•� :: eReasseee8 eeea
aee _ gce eye 959 59
• easily accessible • , ll customers due to - aila ///--- i8a -e/e.•. age -a
y eels a^/Beadd eee fiEefi eee afi/ aae fib
eae -=eee eee eee aee
financing or other accountability structures
• - i3i e
Geographic
sss ss,: eae aefi
• _ae eae eeeaaa eae saes/
de3 eBe fi'eaaaeed eee fia6ii
Renters
• • • not
eee eee
•
Mobile homes • able to use technologyetc.
"e 444 e•a aae 464 eee
'e/ GGG ..•sae
Reliabilit
• Aging infrastructure
Limited• investment in grid updates
Lack of - • • . of • •

Appendix A
Performance and Process Metrics
V � � Performance (Lagging)
Security • How will we measure?
Affordable Resiliency Accessible • Are customers impacted as intended?
• Accountability measurements or
patterns
Economic ; Social, ; Process Metrics (Leading)
SustainableCommunity Environmental
• How will we produce desired results?
Development Benefits • Useful to predict trends
• Mid-Cycle Adjustments
Meaningful ,
Participation Sustainable
24 �iiVISTA

Appendix A
�uvISTA
Supplemental

Appendix A
Customers with an Energy Burden
60,000
50,000
L 40,000
a�
E
0 30,000
V 20,000
1 IMP i Ra R q 0
10,000
0
1 41ILL IL - I ILL] - 1
+0 CO 1� 00 0 CD � N M � LO W r- .,., M v � N M I �
N N N N N M M M M M M M M M M � 11 le 11 � 14
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
26 �ii I STA

Appendix A
Percent of Customers with an Energy Burden
25.0%
20.0%
10.0%
5.0%
0.0%
Re M CG I` CO M O N M Re LO O ti 00 M O r N M qq LO
N N N N N N M M M M M M M M M M qq qqT qqT qqT
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
27 ,aliiVISTA"

Appendix A
Average Excess Energy Burden
$2,500
$2,000
$1,500
I-
$1,000
$500
$0 lillm I 11LLL
,I* w to I` CO (D O N M 1q* w w I` 00 0 O N M it w
N N N N N N M M M M M M M M M M R;t 14* Iq Iq Iq Re
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
Average excess burden per household
Inflation adjusted excess burden per household (2024 $)
28 �ii I STA

Appendix A
Total MWh of DERs in Named Communities
35,000
actual ; forecast
30,000
25,000
20,000
t •
15,000 _
10,000
5,000 :
0 11
- -
�O f- w M O r N 4e 0 W 1` W M O M 4e 0 W 1` W M O N M le LO
r r r N N N N N N N N N M M M M M M M M M M l 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
N N N N N N N N N N N N N N N N N N N N N N N N N N N N N
29 �iiHI STA

Total MWh CapabilityStorageof DER in Named Appendix
Communities
8.0
actual forecast
7.0
6.0 ,
5.0 y
t '
4.0
3.0
2.0
1 .0
0.0
W 1` 00 0) O T- N 11 LO W 1` 00 M O � N M LOW 1` 00 M O � N M qq LO
T" T" � r N N N N N N N N N M M M M M M M M M M g 41 V 41 41 41
O O O O O 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
30 �ii I STA

Appendix A
Annual Named Community Investment vs . Benefits
$50
$45 vAnnual Utility Benefits
$40 Annual NEI Benefits
$35 —Annual Investment
$30
c $25
O
$20
$15
$10
$5
$0
M I* N CC 1` 00 0) O r N M It Lf) (D 1` 00 M O r N M Iq
N N N N N N N M M M M M M M M M M I V 11 le
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
31 �ii I STA

Appendix A
Planning Margin
50%
actual :forecast
45% ■Winter ■Summer
40%
IL
35% -
0 30%
Q 25°io
_ - -
V p 20% - -
i J
IL 15%
v 10%
0 5%
N
0% CO 1- 00 Cn O N qT 10 CO ti CO O O r N M q LO CO 1` 00 O O N M 11 M
r r r N N N N N N N N N M M M M M M M M M M 'IT R* it Iq Iq IV
O O O O O 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
32 �ii I STA

Generation in Washington State or DirectlyConnect6d'
to Avista Transmission
actual • forecast
100% :
°
o O r ° M
T 80% ° °0000
(� o o O O O o °
d o M N 00 00 c o \ o
c ° O O ° °0 00 O O O ° o
■ O o 0
J 0�0 O 00 0000 ■ °0 °0 O Ln o
■ ti ti � o
p 60% °00
~ o °
■ CMM o
C • O CO O
• to
L 40%
G�
a
20%
0%
CO 1` 00
r r r r N N N N N 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 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
Ow
33 'AuVISTA

Appendix A
Washington Air Emissions
5
4 S02
3
c
O
~ 2
C)
5 1. 1 4 60
1 \/ r
0.2 0.2 0.1 0.1 0.1 0.1 0.1 0.1 0.2 0.2 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 - - - 50 �/ O c
O O o 0 0 0 0 o O o 0 0 0 0 0 0 0 0
CO n 00 O O r N I-T O CO n 00 O O r NM V O CO I- 00 T O r N M t O �`•
r r r r N N N N N N N N N M M M M M M M M M M I* le IqI* I le (/�
CD CD CD CD CD CD CD CD CD CD CD CD CD CD CD CD CD CD CD CD CD CD O CD40 r v
N N N N N 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 O
v 30 Cl)
L M
y+ Cl)
500
CDr� ao
20 r N N N N N
O
L 6 1 -
N O y N N
10
400 /` n r n C9 O f0 f0 C9 CO M N M N O <D
r r r r r r
= 0
O 300 t0 h O O O N O t0 O to O N M O t0 O to O N M O
C) O O O O O O O O O O O Cl O O O O O O O O O O O O O O Cl O O
•L _ N N N N N N N N N N N N N N N N N N N N N N N N N N N N N
y 200 -
2 - -
100
0
O � 00 Ol O r N � O CO 1� OO CA O r N M � O CO f� 00 Cn O N 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
N N N N N N N N N N N N N N N N N N N N N N N N N N N N N
34 �ii I STA

Appendix A
Greenhouse Gas Emissions (Washington Share)
2.5
actual. forecast
■Direct Emissions ■Net Emissions
cn
c 2.0
0 - •
1 .5
Cn
c
0
1.0
L
C�
G
0.5 - - -
_ o
■
W I- w M O V- N Iq O w f` W M O r N M 41T W W I` W M O N M 11 W
T T N N N N N 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 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
35 �ii I STA

Appendix A
Eastern Washington Greenhouse Gas Emissions
12.0 actual: forecast
10.0
8.0 •
t�
t—6.0 •
v ,
04.0
•0 2.0
■ ■ ■ ■ ■O ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ ■
O O O O O O O O O O O O O O O O O O O O O O O O O O O O O ,
■Agriculture ■Transportation Residential & Commerical Fuels ;
■Waste Management ■Electric Power Serving Idaho Electric Power Serving Washington
■Large Sources
36 �uVISTA

IFIrw
How Avista Practices Equitable Outcomes
Technical Advisory Committee Meeting No. 2
January 30, 2024

Appendix A
Evolution of Utility Industry
mk*,
Affordable
1880 1920 2020 FV
0 0 0
1900 1990

Appendix A '
PpPPPPP,
Equity AdvisoryGroup
-=-
_ 7
• Est. in Spring of 2021
Significant input on our CEIP
i
• Ongoing monthly sessions -
. V
• 11 /38 CEIP Conditions ` '
• Oversee 500k of the Named
Communities Investment Fund s
4
�iiVISTA

Appendix A
Additional Advisory Groups
• Energy Assistance Advisory Group (EAAG)
• Energy Efficiency Advisory Group (EEAG)
• Distribution Planning Advisory Group (D-PAG)
Equity
%.,
4 C043VISTA

Appendix A
CEIP Public Participation Strategy
11 Phase I
Project Planning
• The Plan outlines barriers to (August4-September 16,2022)
iblic Engagement Plan
M�, N. « Phase II
participation in programs and services, Assessment of Current Practices
(August 8-September 30,2022)
strategies for reducing those barriers,
� Phase III
and tools for increasing participation . Survey mberr5ferences-November11,2022)
L Phase IV
Public Participation Plan Development
Filed May 1 , 2023 7 r,o�omko�,� )n"'
You'll be asked about your experiences with Avista in the past and how you'd like to be communicated with in the
future.All questions are voluntary,and the entire survey should take about 3 minutes to complete.
• Utility Language Strategy Request translations or paper copies of the survey by emailing info pppconsultin .net or calling(919)706-5449.
O Queremos saber c6mo involucrarle a usted y a otros clientes de Avista de
manera mas equitativa en futuros programas a iniciativas.
O Mw crpevmtca saitrn ommia.mtmte cnoco&i ssatLMoaeiicrsaa c sautt n,gyp Tmnt
rmsearam H Avista s 6t�musx nporpaN01ax a mm mrarmax.
�} 41-1&IAI*.'c -kA 2,i-p-,6 y Avista:. wi
WWTV&P f a7i 1JAMELPYttAvistaVrFlO'beff 1R 5x1 Md�1it J1#CNBb1l
ill HW STA

Appendix A
Other Initiatives
a.4 M A,
Capital Planning Federal/State Grants Supplier/Employee Diversity
6 A043V/STA

Appendix A
CEIP Customer Benefit Indicators
00
o �
a o�
Affordability Energy Security Access to Environmental Community Public Health
& Resilience Clean Energy Development
Participation in Energy Availability Methods/Modes of Outdoor Air Quality Named Community Employee Diversity
Company Programs Outreach & Clean Energy
Households with Communication
Energy Generation Greenhouse Gas Supplier Diversity
High Energy Location Emissions Investments in
Burden Transportation Named
Residential Arrears Electrification Communities Indoor Air Quality
& Disconnects
7
A043VISTA

Appendix
Affordability Initiative
How Bill Assistance is Increasing Customer Affordability & Promoting Equity
Kelsey Solberg, Manager

Appendix A
Alignment to CEIP
Customer Benefit Indicators
0000,
rA $$ p o
MUU
nCO3
Affordability Energy Security & Access to Environmental Community Public Health
Resilience Clean Energy Development
Participation in Energy Availability Methods/Modes of Outdoor Air Quality Named Community Employee Diversity
Company Outreach & Clean Energy
Programs Communication
Energy Generation Greenhouse Gas Supplier Diversity
Households with Location Emissions Investments in
High Energy Transportation Named
Burden Electrification Communities Indoor Air Quality
Residential
Arrears &
Disconnects
9 A043V/STA

Appendix
What is Bill Assistance & Affordability
Bill assistance aims Energy Burden is High energy burden=
to reduce the ener the percentage of >6%
gy household income
burden of limited- that oes towards Severe energy
income households g burden= > 10%
energy co0
sts
Most forms of bill
assistance are
Result: Increased aimed at reducin
400
Affordability! g
energy burden to
<6%

Increase Affordability
Appendix A
Bill Assistance at Avista : Goals & Purpose
Address Past-Due Balances
Provide Support During Hardships
Educate on Energy Conservation

Appendix A
Washington Lowmincome Rate Assistance Program ( LIRAP)
i gla .
Eligibility Zero to greater of 200% FPL or 80% AMI
Bill Discount
Affordability
Discount Tier 1: Discount Tier 2: Discount Tier 3: Discount Tier 4: Discount Tier 5:
Zero to 5% FPL 6 to 50% FPL 51 to 100% FPL 101 to 150% FPL 151%, Greater of
Arrearage Forgiveness Arrearage Management Program
Past-Due Zero to 50% FPL 51% FPL to the Greater of
Hardship Emergency Share
Customers experiencin hardship or ener emer enc
Energy Conservation Education (ConEd)
Conservation Distribution of energy-saving items for homeowners and renters, paired with customer education, to reduce energy use

Appendix
Increasing Affordability
Introducing My EnergyDiscount
�f
Discounts are based on self- Jointly administered between Nearly 18,000 customers who
declared monthly or annual Avista and agencies means received income-qualifying
income more avenues for access assistance were auto-enrolled
in October 2023
Participants remain eligible for 6% of enrolled customers will
No paperwork or income other helpful programs through be randomly selected to verify
verificAVtion required their local agencies, as well as their income through their CAA
other energy assistance
13 Discount percentages are designed to reduce customers' energy burden to <6% C0431FIVESTA

Appendix A
Addressing Past-Due Balances
Washington Customer Arrears
29 , 170 customers with past due
balances totaling $ 6 . 3M
Average Past- Due Balance : $216
14 Washington customers as of December 31, 2023 C043VISTA

Appendix
Addressing Past=Due Balances
Avista's LIRAP arrearage assistance is comprised of two unique programs
Each program has distinct eligibility criteria and benefit amounts, and are intended to provide
relief for income-qualified, residential customers who have unmanageable so ue b alances
(arrears) on their bills.
Arrearage Forgiveness Arrearage Management
Program (AFP) Program (AMP)
Avista works closely with community action agencies to ensure the customer has access to the
benefit when they need it most.

Appendix A
Program Enrollment Snapshot
My Energy Discount:
28,044 Active Participants
Arrearage Forgiveness Program :
351 Recipients (Oct-Dec 2023)
Arrearage Management Program :
662 Active Participants
16 Data provided as of 12/31/23 �uii/ISTA

Appendix A
2023 Saturation Rate
Customers
Number of Eligible
Percentage 24%
Receiving Assistan
•
) 15%
3-year Average
Saturation Rate equals the percentage of estimated eligible customers who are receiving any form of bill assistance. Data is reviewed and
17 updated quarterly. Beginning in 2023 the Washington estimated eligible of 129,266 was calculated using Avista's 2022 Performance-Based A043VISTA
Ratemakinq data.

Removing barriers Discount percentages Multi-lingual Increased readability
with self-attestation of designed to resources on the of Avista website,
household income specifically address web, through customer letters,
and size differential income customer service, and promotional
tiers in outreach materials materials, etc.

Appendix A
Named Communities Investment Fund
Kristine Meyer, Avista Foundation Executive Director
19 Ana Matthews, Sr. Energy Efficiency Program Manager

Appendix A
Ile
Avista's Named Communities
Specific Target and Actions for ensuring that all customers are
benefiting from the transition to clean energy the equitable
distribution of energy and nonenergy benefits and reduction of
burdens to Vulnerable Populations and Highly Impacted
Communities (Named Communities)
t Foll-
Vulnerable Populations a ' Coeur
Highly Impacted Communities ke k
142 census tracts in Avista's service territory vloses Lake Ll
■ 36 Health Disparities
it
• 12 Socioeconomic or sensitive populations indicators
-I,
,A0431V STA

Appendix A
Named Communities Investment Fund
■ Specific Action dedicated to the Supplement Energy
equitable distribution of energy Efficiency Distribution Resiliency
and non-energy benefits and
reduction in burdens to Named
Communities
Incentives & Grants Outreach &
for customers or third Engagement
■ Funding is limited to 1 % or parties
approximately $5.0 million of
electric revenues, annually
Projects,Other
Programs or
21 A043VISTA

The cleanest energy
is the energy that is
Energy Efficiency NCIF endix A
never used.
1 ' , or up to
Supplement and support energy efficiency efforts targeted to Named Communities
Community Identified Multifamily Building Health & Safety for
Projects Split Incentive Manufactured & Mobile
Homes
Named Community Community & Small
Single Family Business Energy
Weatherization Efficiency
Chapter •-

Appendix A
Equity in Practice : Outreach & Engagement
Multiple avenues to learn about and apply for NCIF
(JIM sss
Online Applications Existing Community Informational Sessions Enhancement to
Relationships virtual and in-person company programs and
projects
,A0431FIV sra

Appendix A
NCIF Process
Advisory Support/Guidance
Confer with assembled advisory groups For entities that have a clean
for equity, energy efficiency and energy idea and need support for
assistance, etc. for guidance in program developing their concept to
design and implementation. fruition.
Engage customers through public
participation.
Outputs + Results
Programs and projects that are
Community & Business designed to ensure equitable
Application process open to
transformation for all customers,
interested parties to submit with committed focus for those
proposals for funding residing in Named Communities
Resource "Braiding"
Consider and leverage all funding
and other resources available (at
Existing Relationships/Channels the time of application).
Internal and external interested
individuals and/or parties make
proposals through established
channels or connections
,A043VISTA

Factors for NCIF Consideration : Equity Assured Appendix A
Equity Customer Benefit Implementation Plan 7 Equity Advisory GroupV Indicators Specific Actions Initiatives
■ Affordability (1) Participation in Company ■ Community Identified Project Energy Efficiency in Named
Programs Communities
■ Access to Clean Energy (2) Number of households with a ' Multifamily Building Split (1) Improved awareness and
High Energy Burden >6% Incentive energy efficiency for Spokane
■ Community Development 9 gY ( ) Tribe, multi-family and
(3) Availability of Methods/Modes ■ Health & Safety for manufactured homes
■ Energy Security of Outreach and manufactured and mobile home
Communication (2) Increased Tree Canopy
■ Environmental ■ Single Family Weatherization(4) Transportation Electrification (3)Increased access to products
■ Public Health (5) Named Community Clean ■ Community Energy Assistance and appliances
Energy (4) Increased awareness and
(6) Investments in Named ■ Small Business Energy engagement in EE programs
Equity lens requires Communities Assistance (5) Matching funds for EE grant
unique consideration for (7) Energy Availability applications
each proposed project (g) Energy Generation Location (6) Improved EE for those without
(9) Outdoor Air Quality stable housing
(10) Greenhouse Gas Emissions
(11) Employee Diversity
(12) Supplier Diversity
(13) Indoor Air Quality
25 A043FIV STA

Appendix A
2023 Commitments & Funding : Equity Outcomes
Energy Efficiency -( , 40�
# Q0
Spokane Tribe reservation energy
audits
Lincoln County Fairgrounds lighting Affordability Energy Security Access to Environmental Community Public Health
& Resilience Clean Energy Development
Malden homes weatherization
Participation in Energy Availability Methods/Modes of Outdoor Air Quality Named Community Employee Diversity
KW Ener gy Duct Sealing for Company Programs Outreach& Clean Energy
Households with Energy Generation Communication Greenhouse Gas Supplier Diversity
manufactured and mobile home in High Energy Location Emissions Investments in
Burden Transportation Named
Stevens, Ferry and Pend Oreille Residential Arrears Electrification Communities Indoor Air Quality
counties &Disconnects
Walnut Corners affordable housing
PTAC (AC & Heating units) replacement Community & Resilience " •
SNAP Pine Villa affordable housing Martin Luther King Community Center Online application
Phase 1 renovation (windows, solar assessment
insulation and doors) Martin Luther Kin Community Center
Medical equipment and air conditioning g y
the.Supper Club new refrigerator and for customers with power dependency HVAC retro-commissioning report,
freezer pilot lighting, and windows
Health & Safety for Manufactured City of Spokane Parks & Recreation Kettle Falls Community Chest facility
Homes for two neighborhoods in Tree Plotter software subscription renovation
Spokane County
,A4,3V/STA

Appendix A
Thank

���r r/ISTA
Equity Planning in the 2023 IRP
James Gall
Technical Advisory Committee Meeting No. 2
January 30, 2024

Appendix A
Eauity Related Items included in 2023 IRP Modeling
• Energy Efficiency
• Named Community Investment Fund (NCIF)
• Customer Benefit Indicators (CBIs)
• Resource Non-Energy Impacts ( NEls)
• Social Cost of Greenhouse Gas
• Maximum Customer Benefit Scenario
z

Appendix A
Energy Ef ONE
• Split energy efficiency measures between "low-income" and non-low income
• Low-income includes higher NEI values where applicable
• Low-income measures can use a different cost value
• 2025 IRP will explore using named community potential rather then low-
income
How impacts the plan:
Selects greater amounts of
energy efficiency to serve future
energy demand
3

Appendix A
Named Community Investment Fund ( NCIF I
• Model must select $2 million (+) of the least cost, non-cost-effective energy
efficiency per year
— Increases energy efficiency targets
— Shows possible future programs
• Model must "spend" $400,000 per year on incremental Distributed Energy
Resources (DERs), including community solar
— Demonstrates ways to increase DER in named communities
— Impacts CBI metrics
How impacts the plan:
1 ) Quantifies the lowest cost, non-cost-
effective low-income energy efficiency
projects given the budget.
2) Selects generation/energy storage
4
given the budget

Appendix A
Non-Energy Impacts
• Quantification of indirect and social impacts of resource decisions
not included in resource costs
• DNV conducted the study for the 2023 IRP for resource selection
if quantitative values are known or estimated
• DNV qualitatively identified costs for other impacts
How impacts the plan:
1 ) Energy Efficiency and Resource are
on an even playing field for selection
2) Sets priority for CBIs using
quantifiable measures
5

IRP Resource Selection
Public Health Income & Health
Economic Develop. (income) all are able • be
PM2.5, S02, NOx less missed days of work quantified due to lackdata or
difficultly in . data.
nergy Efficiency NEI
Safet Health -
y •
Direct and indirect Related to avoided costs such as - Avista is not planning a Phase
fatalities per GWh medical SupplyResource
Environment Property Value
p y
Land use, water use, Noise, visual air/temperature
wildfire risk
Economic Energy Burden
Jobs, earnings, output, Reduction in costs related to utility
bill
value add added
ant_

Appendix A
Resource Acquisition ' quity Considerations
• Resources are required to go through rigorous public process to be permitted
• RFP Resource selection includes
— NEls in economic analysis
— Resources are selected based on scoring matrix including
• Customer Energy Impact (cost): 40%
• Risk Management (construction/solvency): 20%
• Price Risk (change in price): 5%
• Electric Factors (deliverability and technology risks): 20%
• Environmental (permitting risk & air quality): 10%
• Qualitative Non-Energy Impacts: 5%
— Community involvement, Named Community impacts, location, local labor force, supplier
and owner diversity
7

Appendix A
Maximum Customer Benefit Scenario
• Required in Washington IRP rules
• 2023 IRP included the following assumptions
— In-state/connected renewables requirement (i.e. no Montana wind)
— No ammonia/power to gas CTs (fuel cell allowed)
— Lowering of excess energy burden required via community solar
— No nuclear energy
• What do you like about the assumptions?
• What would you change?
a

Appendix A
2025 Electric IRP, TAC 2 Meeting Notes, January 30, 2024
In-Person Participants:
Dan Blazquez, Avista; Annette Brandon, Avista; Michael Brutocao, Avista; James Gall,
Avista; Lori Hermanson, Avista; Mike Hermanson, Avista; Clint Kalich, Avista; John
Lyons, Avista; Tom Pardee, Avista; and Darrell Soyars, Avista
Online Participants:
Diana Aguilar, Fortis BC; Sofya Atitsogbe, WUTC; Ernesto Avelar; Tamara Bradley,
Avista; Kate Brouns, Renewable Northwest; Terrence Browne, Avista; Logan Callen, City
of Spokane; Katie Chamberlain, Renewable Northwest; Nathan Critchfield, Puget Sound
Energy; Kelly Dengel, Avista; Joshua Dennis, WUTC; Mike Dillon, Avista; Chris Drake,
Avista; Ryan Finesilver, Avista; Grant Forsyth, Avista; Annie Gannon, Avista; Konstantine
Geranios, WUTC; Amanda Ghering, Avista; David Hawkins; Scott Holstrom, LIUNA;
Alexandra Karpoff, Puget Sound Energy; Mike Louis, IPUC; Ana Matthews, Avista; James
McDougall, Avista; Ian McGetrick, Idaho Power; Kristine Meyer, Avista; Heather Moline,
WUTC; Richard Newton, Northwest LECET; Kaitry Olson, Puget Sound Energy; Meghan
Pinch, Avista; Melanie Rose, Avista; Amanda Silvestri, BPA; Kelsey Solberg, Avista;
Dean Spratt, Avista; Marissa Steketee, Sapere Consulting; Lisa Stites, Grant County
PUD; Jason Talford, IPUC; Andrea Talty, Puget Sound Energy; Charlee Thompson, NW
Energy Coalition; Tyler Tobin, Puget Sound Energy; Brian Tyson, Puget Sound Energy;
Kirsten, Wilson, Washington State Department of Enterprise Services; Rachel Wilson.
Introductions, John Lyons
John Lyons: We are still doing the virtual meetings on Teams always. In-person is
available, especially for the longer meetings. Shorter ones we realize that's tough to come
in for, but for the all-day meetings, it's still an option for in-person. We post the final TAC
presentations, meeting notes and recordings on the IRP page.
John Lyons: Couple of reminders. Please remember to mute your mics unless you're
speaking or asking questions. You can use the raise hand function in Teams or type
something in the chat box for questions or comments. We ask that you respect the pause
because sometimes it does take a little bit for people to unmute their phones, things like
that. Trying not speak over the presenter and speaker. We're all really good at this now,
the longer we've been doing these online meetings. We do ask that you state your name
before commenting, and that's for the meeting notes software. If you're hooked up
directly, your name is set up on it, it'll automatically put it on. But like in this room, it just
says it's in this room, so that makes it a little more difficult.
John Lyons: This is a public advisory meeting. Just a reminder that presentations and
comments are going to be documented and recorded. The IRP plan, remember IRPs are
required by Idaho and Washington every other year. Washington now requires an IRP

Appendix A
every four years, and then there's a Progress Report at two years, most of the same
things. Plus, we're already doing a full IRP for Idaho. The IRP guides our resource
strategy over the next two decades. It starts with the current projected load and resource
position. Also looks at some alternative forecasts. We have an expected forecast and set
of alternatives. If we had some major changes like electrification happened sooner or you
had some new policy that changed the market. We also look at resource strategies under
those different future policies. They look at different generation resource choices, different
aspects for energy efficiency, demand response. You're seeing a lot more transmission
and distribution planning integration. If you're interested in that, there is a Distribution
Planning Advisory Group that's similar to the TAC that is now meeting. And then it all
ends up in a set of avoided costs that are used. So, if someone wants to bid into, say they
had a PURPA project they would like to bid in to sell something to Avista, that's where
that number comes from. And then we also do a series of market and portfolio scenarios
where those uncertain future issues that we're either not sure which direction they're
going or it's important enough that if we had a big change, we would want to see if that
changes our strategy going forward.
John Lyons: This is the public side of thing. It is a real wide range of participants. If
you've got a question, please ask. Because not everyone's going to be an expert in every
area, and chances are if you've got a question someone else does too. So please go
ahead and raise those. We are also always looking for help with getting new TAC
members, so if there's someone that's interested in joining, you don't have to participate
for the whole time, you can just participate for a part of it. It is an open forum, we're always
trying to balance how much discussion we can get versus getting through the program
that we have. If you've got different study assumptions, we do ask for those. The earlier
you get them to us, the better chance we have to get those completed on time. If we can't
complete them during this cycle, those can become Action Items for the next cycle. As
we said before, we're always available by email or phone for questions or comments. If
you want to set up a meeting with us between the TAC meetings, we're happy to do that
as well.
John Lyons: For today's agenda, this is an equity focused meeting. If you remember our
last meeting, I think it was the first TAC in September, I think it was 26t" somewhere about
there. We didn't have this meeting in here. Our next one was going to be, I believe in
March, but we were asked by the Washington Commission as we've been talking about
equity throughout the IRP, to have one specifically focused on equity issues. As a
reminder, this is something that's in Washington law to have an equity focus on things.
That's what we're going to be talking about today after the introduction and that's going
to be about how Avista includes equity principles and then getting into those Customer
Benefit Indicators, the way we measure some of these equity areas, we'll take a short
break, then Tamara will get into how Avista practices equity outcomes. That's a wider
view, not just the IRP of what's going on at Avista for that. James will wrap up with how
we're rolling equity planning into the IRP because we started doing this the last IRP and
it's still a fairly new topic for us to work on. Do we have any questions before we move on

Appendix A
to the next presentation? You're all quiet in the room here. Do we have anything there on
the chat, James?
James Gall: It didn't sound like it yet.
How Avista Includes Equity Principles, Annette Brandon
James Gall: OK, alright, when I get that presentation loaded up and I don't know if it's
showing there. I need to introduce Annette Brandon.
Annette Brandon: Well, I'll introduce myself anyway. Hi, my name's Annette Brandon
and I am in the Energy Supply Department with several of the folks in the room here today
— James and Lori and John and others. I primarily am in the Wholesale Marketing area.
However, I'm on a special project to help to incorporate equity into our overall utility
operations, beginning with the focus in capital planning. However, it's a nice offshoot of
what we have done previously in our Clean Energy Implementation Plan [CEIP] that we
started to in the last in the last IRP. Thanks for having me back here today. It's a good
start for the process that we're working on right now. You'll notice that some of these
slides have been updated. As we went through the final updating there was unfortunately,
and embarrassingly for me, there were several typos in there. We cleared those all up
before we showed these to you today. I just want to make sure that you know that's not
typically how I do things like that. So, here's the final. We can move on.
Annette Brandon: A good place to start is an overview of what equity is. I thought instead
of having any subjective what we think it is, or other definitions that are being used in
different contexts, I thought we would just level set by saying this is what the actual
dictionary definition is. Equity is the quality of being fair or impartial. What does that
mean? Even so, if we take that one step further rather than just taking it as a standalone
basis. If we put it into actual operations, if I can draw your attention down to #3, it's the
pull, your practice of accounting for the differences in individual starting points when
pursuing a goal or achievement and working to remove the barriers to equal opportunity
by providing support based on unique needs of individual students or employees. For
Avista, that would mean considering what circumstances may be limiting customer's
access or opportunity to receive the benefits of the energy system, which would be safe,
reliable, affordable, etcetera. A good example of this is this new graphic that that I found.
It's been redeveloped and I put the copyright on there. It's small, but this was redesigned
by another company and what it is representing is in years past everything was focused
on equality, so everything was the same meaning. If you were little and you had to jump
off a tall curb, or you had or you were in a wheelchair, or you could not see you still had
that curb you had to deal with when crossing the street. But as time passed, and as equity
became more and more important, you can see that now those sidewalks have been
modified. Now we can hear when we want to cross, we can hear how long we have to
cross. It's been modified so you can easily roll down it and little people don't have to jump.
Now they can walk down. I really like that. I think that has to speak to it a little bit better

Appendix A
than some of the other illustrations that have been used in commonplace. The shoe
example I'll get to a little bit later, but it really surrounds itself around the distribution of
assets. In our case, the distribution of energy across our system, but I'll get to that in the
next slide.
Annette Brandon: So, what is? What does that mean? What does that mean to us here
at Avista? Because fair can also be a subjective term. I looked that one up. Also, if we're
stuck with the dictionary.com, it's free from bias, dishonesty, or injustice, which would
mean, taking off of our previous example, that an individual's circumstance no longer
predicts their outcome, which means a fair process. The process itself must be fair and
must be based on meaningful participation. And I took the time to focus on meaningful
participation here because meaningful participation is not check the box participation. I
will keep saying that over and over because I think there's an effort out there to have
public participation, public participation, public participation, but public participation just
for the sake of it does not help us and does not help you. Meaningful participation means,
and this is a truncated definition,just so it would go on the slide. But this is the Department
of Energy. How they are defining it in their Justice 40 initiative when they are taking those
investments and ensuring that disadvantaged communities are receiving the benefits of
investments for their climate change efforts. It starts with awareness and opportunity for
2% to participate. Then, with that participation, the input we received has the ability to
influence our decisions. And then, that is actually considered in our decision making and
purposeful outreach efforts, which seek out and facilitate involvement of those potentially
affected that goes very well back with the awareness and opportunity to participate. But I
think this is really foundational to equity and back to my check the box example it it's
difficult because the utility industry is so very complex. It is still very complex that we could
be perfect in every single thing that we do. Perfect in checking every box in what this
means and likely still not have full representation as desired, I guess by our regulators.
Annette Brandon: What I would like to see is a way for us to work together to first and
foremost try to identify what does matter to our customers. We know affordability matters
to our customers and we know holding Avista accountable to what we say is important to
our customers. But do customers really want to be involved in, like a technical meeting
such as this? Do they want to be right down in the weeds? Maybe. And if so, that's great.
And if they have the ability to, that's great. But what about those who want to but don't
have the ability? Or time, not just ability. That's where we have to work together outside
of just Avista. We have to work with our Community agencies. We have to work with our
Public Counsel unit. It really takes a village because it might be that somebody else can
understand what we're doing and understand what the customer is seeking and act as
that conduit. And so, that is really important as we're trying to navigate this, what does
equity mean and how can we ensure that everything that we're doing is built on this
meaningful participation? All right, next slide here.
Annette Brandon: This slide I took the time to show the evolution from environmental
justice to where we are today for the just transition. That's because I think it's important

Appendix A
to understand that this is not really new. It's just the terminology is new and the
requirements are new. The evolution of energy justice started with the environmental
justice movement in the in the 1970s and it was around the time of the civil rights
movement as well. It had a focus on discrimination and environmental pollution that those
were very much related or tied together, where everyone has the right to a clean
environment regardless of their social, economic status or characteristics. It was one of
the first times where there was recognition and acknowledgement that certain
characteristics did result in disproportional environmental impacts back then, and it was
the first time where there was strong advocacy for a right. The right to a clean
environment. From there, it expanded into climate justice, kept all those still foundational
thoughts but pulled into the climate justice age where that expanded the look into climate
change impacts. That's the first time where we started hearing about fossil fuel impacts.
And it also emphasized a need to identify solutions that did not perpetuate or worsen
already existing inequities. In environmental equities, we already started to acknowledge
and understand what those are and then climate justice is taking one step further and
saying, OK, now that you know what they are, now try to make it so that that doesn't keep
happening, then spend it on the energy justice. The terminology energy justice started in
the 2010s, which is quite a while ago from now.
Annette Brandon: And we just recently started hearing about it. But the reason for that
is that energy justice really started more in economic circles or legal circles. And it
reinforces the need for voices and decisions and emphasize the need for affordable and
clean energy. And again, reemphasize the focus on inclusivity and decision making. All
of them build on each other. They're not distinct from each other, and energy justice has
been in a lot of our regulation, but today, with the focus on the transition to clean energy,
this is where now we're to the point where now we're being required.
Annette Brandon: The technical definition of energy justice is equitably sharing the
benefits and burdens involved in the production and consumption of energy. So that's our
generation. I think that as our generation, transmission and distribution of our energy,
how can we ensure that our processes, not just our delivery, but our process is
considering what customers need and what their unique characteristics are. And that is
what tips on that second piece of that paragraph and fairness in how people's and
community's, people's fairness, and how people and communities are treated in energy
decision making. OK, next slide.
Annette Brandon: That brings us, as I said in that last line to what the transition to clean
energy means. Alright, so the transition to clean energy, it's in the spotlight everywhere.
It's in the spotlight, not just for Washington staff, but nationally and lots of companies are
talking about how they're committed to be green by 2030, 2040, 2050. You hear a lot of
companies, so it's very much a focus on transition to clean energy and it's a just transition.
Just transition means it takes equity just a little bit further and says not only do I want to
make sure that I'm allocating resources in a manner that all have access to clean energy,
but I want to seek to address the cause of those inequities. Why aren't they? Is there

Appendix A
something that we can do as the utility to get there? We do believe that all individuals
have the right to fair and clean up clean energy, but we have to balance a lot of things
when we say right, it's kind of a squishy word, if you will, because yes, we believe that,
but we have lots of constraints. We have to work with them, and lots of things to balance,
but the ultimate goal is we want all customers to have the energy they need, not only for
their basic needs, but beyond that, to economic development, to health outcomes, to a
healthier environment, to all of those things that having safe, reliable, clean energy,
energy and can deal.
Annette Brandon: OK, so I think I covered everything I had in my notes. This is what I
just touched on a minute ago about balancing multiple in multiple objectives. I really
wanted to spend just a little bit of time focusing on this, because I think that it goes without
saying, but we need to say it out loud. There are several objectives that we're balancing
in this IRP process as well as in our planning process, distribution planning, system
planning, transmission planning.
Annette Brandon: We are not a standalone island utility. We interconnect with lots of
different utilities and providers and distribution centers, and we're regulated by all kinds
of four-letter acronyms, NERC, FERC, WECC. And then we have federal justice 40
initiative requirements, not so much requirements, but considerations rather the Clean
Energy Transformation Act requirements and considerations. The Department of Ecology
has departments or has considerations and requirements, so all of that we're trying to
balance with the needs that we've identified from all the different people and areas that
are on the right-hand side of the screen. That is all individual needs, but also clean air,
Public Library, Department of Ecology. Also, a lot of these pictures represent people that
are on our Equity Advisory Group, and we'll talk about that later in the presentation. But
it is very much a balancing act, and our goal is that we want all customers to have access
to this clean energy. Clean, reliable, safe, not even just limited to clean energy but limited
to our energy portfolio.
Annette Brandon: All of the resources that go into the IRP analysis, we want to have
processes that consider, and evaluate the appropriateness of those selections. It cannot
go without saying, however, that we are an electric provider or an electric utility in this
context, because this is electric IRP, we're also natural gas, but we're not a social agency.
While it's very important that we understand those root causes, and we genuinely care
about our customers, and want to ensure that we consider unique circumstances when
we're planning. Sometimes the answer's going to be well, NERC says we're going to do
this, and so we're going to do it.
Annette Brandon: It's important for me to point that out, because that does not mean
that we're not being equitable or that we're not including equity. That just means that one
piece of the whole process, the life cycle of an investment, that just means in that one
decision point we're going to say we're not an island, we need to make sure that our
neighbors are also reliable. And so, we are not going to put a transmission line, make a
decision to put a transmission line in this neighborhood versus that neighborhood

Appendix A
because we want to make sure that we're not having unintended consequences 15 years
down the road. When I say 50 years down the road, my husband says no, more like 50
years down the road. Where now we've got the inverse going on and now the other one
is not as reliable. So, we want to make sure that we're long-term planning. We're thinking
about sustainability. We're thinking about everyone having reliability to the best of our
ability. That's really important that we're balancing those objectives and the place for that
comes into play, then that equity lens comes into play multiple places down the line and
even up the line. I've got a slide that will walk through where that is.
Annette Brandon: Maybe before we move on, this was foundation setting as to what
equity is, how we're viewing it, how we're balancing multiple priorities? Are there any
questions or comments? Heather has a hand up. Hi, Heather.
Heather Moline (UTC): Hi. Thank you for that. This is Heather Moline with Utilities and
Transportation Commission Staff. I'm just going to share in the chat some of what's in law
that's connected to what Annette was saying and what's in orders issued by the
Commission regarding what Annette was saying. I just want folks to know that what
Annette was saying, she didn't just go and Google it. This stuff is required by Washington
statute, and it's required by what the Commissioners have ordered regarding their utilities.
The first thing that I'm sharing is this link to the final order from the Cascade general rate
case. (UTC Case Docket Document Sets I UTC (wa.gov) see 08/23/2022 filing, Final
Order 09 (four types of energy justice), as well as RCW 43.06D.020: Office established—
Purpose. (wa.gov) and RCW 19.405.010: Find ings—Intent-2019 c 288. (wa.gov))
Cascade is a gas utility. It's not an electric utility, but the Commission said, here are four
types of energy justice that we expect all utilities that we regulate to be considering. And
it was based on RCW 43.06D, which I also linked to in the chat, which is the definition of
equity from the Washington State Office of Equity, a new state office. That was created
three years ago, I think. The order that I shared comes from this definition and statute of
equity that I shared. The last thing that I shared is this link to statute that probably all of
us have heard of by now. The Clean Energy Transformation Act, CETA, 194-05-010,
which is the very first place in law that the term equitable distribution is used. As we all
try to figure out what this means and share resources that interpret what's there, I just
wanted to make sure folks had access to this. What's in law and what's in Commission
order about equity? Thanks.
Annette Brandon: Heather, your timing could not be more perfect because that is exactly
what my next slide is on. Thank you for that. That couldn't be timed more perfectly,
because here's the Washington State equity requirements, and Heather has been so kind
to add the links into the chat now. If you would like to click those links, it will take you to
the actual RCW and the WAC. As Heather just noted, the Clean Energy Implementation
Plan, my words were it was focused on a just transition, that is the first time that the words
equitable distribution is used and in my thought I just transmit transition is equitable
distribution. It was equitable distribution of benefits and burdens. And then particular

Appendix A
areas that the Commission wanted us to focus our time on and when we get to the
Customer Benefit Indicator, we'll make sure that we talk about those.
Annette Brandon: That was the place where the term equitable was used. There was a
strong public participation focus and there was also a strong Customer Benefit Indicator
focus, and what those Customer Benefit Indicators are that we're going to talk about are,
what I'm going to call process and performance metrics now. In that language back then,
they did not use the word equity, but that's exactly what it was. That's exactly what we
were doing.
Annette Brandon: Public participation is very similar to procedural equity and Customer
Benefit Indicators can be the accountability portion of distributed or restorative, but this
was this was the first place. While this does say Clean Energy Implementation Plan, that
begins with the Clean Energy Action Plan, so really it should be Clean Energy Action Plan
starts and then results in the Clean Energy Implementation Plan. Where we are today is
talking about the IRP which will help to inform the Clean Energy Action Plan. In addition,
in our general rate case conditions, we had I think in 2022, actually I think I have the
wrong date there. Capital planning must consider and implement energy justice and its
core tenants, and these are the core tenants. Thankfully, Heather just put the link in the
chat and although that references the Cascade order, it is the same terminology that is in
our order.
Annette Brandon: The Commission is being very intentional to ensure that we are all
using the same definitions. I think early on, in the company we were saying internally we
need to figure out how Avista is going to define equity. Now the Commission has defined
it for us. This is exactly how they are defining it for us and by stepping through each of
these four components, we will have justified or attempted to justify if that's the right
terminology. We've shown that we've made good faith efforts to ensure that we have a
fair, inclusive process that is proactively planning for equitable outcomes. I included the
Climate Commitment Act on here. I put it in blue because it is related, but it's not directly
related on the electric side. The primary avenue for reaching those disadvantaged,
Named Community, frontline. They're using different terminology, and I don't recall which
one they are using. The Environmental Justice Council from Washington State, they are
helping to say this is where and in what communities we should invest in that are having
disproportional environmental burdens. This is so the investments are for them primarily.
Annette Brandon: However, Avista does have a portion of that we need to make sure
that we are considering low-income customers, which often are located in Named
Communities. If we are going to distribute our portion, but our portion of the Climate
Commitment Act, we need to ensure that we're doing that in a manner that's also dictated
by law. Next slide.
Annette Brandon: This slide is actually recycled from last year's Integrated Resource
Plan meeting where we were discussing with the TAC how we might include certain
components in our resource selection in our IRP, this is a condition that we agreed to,

Appendix A
and this is the basis for what we are setting the stage for today to do again. The
requirements are that Avista will apply non-energy impacts and Customer Benefit
Indicators to resource and program selections. Further, we agreed to consult and engage
with all our equity or applicable advisory groups to include both NEI and CBI. And
throughout this whole process, once we've developed a methodology, we want to ensure
that our equity advisory group is comfortable with that. While this was part of the Clean
Energy Implementation Plan, it's also part of our capital planning requirement that we
talked about from the general rate case requirements. Also, we need to make sure that
the Equity Advisory Group is comfortable with whatever we decide in that process as well.
OK, so next slide.
Annette Brandon: What exactly is a non-energy impact? I took this off of a slide that's
from one of the primary industry experts that address non-energy impacts. They can be
broken out into participant benefits, utility benefits, and societal benefits. And to
summarize them all in bullet points, it's the contribution of the investment that goes
beyond the energy and the demand costs. Some of those impacts, and they can be
positive or negative, can come in the form of economic, social, environmental and or
personal ways. What does that mean? Some of the good examples that I've uncovered
have been. First off, energy is foundational to economic growth. There is a correlation,
I've not personally studied it, but this is what I've read, there is a correlation between high
energy use and high economic growth. Again, I can't prove that, but that's what I read,
and it seems it seems intuitive. Also, when you think of public health, I struggled with that
one for a long time because I wasn't entirely sure how that fit in, except for environment.
If you have healthy environment then you have healthy people but think about the fact
that because we have safe, reliable power, think of all the technological advancements
we have now. All of the life-saving equipment we have and all of our hospitals, we were
able to develop and use daily to keep people alive for a lot longer and to have more
successful surgeries and a healthier community. That was a direct relation too.
Annette Brandon: Also, some of the ideas to think about is, personal ways could be
maybe education, let's say tech, access to online classes during the pandemic. If we
hadn't had energy that allowed us to use our devices, to charge our devices, there could
have been a lot of lost class time and maybe people would have had to put their whole
entire year of college, or year or two or whatever, on hold. So, the primary challenge with
these non-energy impacts is how do we measure them? How do we compare them? How
do we use them as a basis for a proactive decision? Since we're here today for integrated
resource planning, how do we consider this for something that's 20 years down the road?
That's the challenge. That's what we need to think about. Next slide.
Annette Brandon: This is a very busy slide, and I have to say in these next couple of
slides this is my first attempt at these and these most likely will change as it goes through
all the leadership and all of the advisory groups here at Avista. But this is this is how it
seems most intuitive to me, and I've been looking at this for a long time so I'm learning.
I'm starting to almost speak slang already, since I've been saying this so much as it goes

Appendix A
through the company will make sure that we clarify this a little bit better. The terminology
recognition, procedural distribution, restorative I am not going to ask employees to use
that terminology. We do need to use that terminology when we're writing and when we're
justifying to the Commission and we do need to make sure that we don't lose sight of what
it means, that we don't lose sight of how they relate together, because otherwise we're
trying to put the genie back in the bottle. Now, what did we mean by that? We need to
make sure we don't wind up in that place, so I would like to categorize this as people
process and performance.
Annette Brandon: We are going to ensure that we have an equitable process, an
equitable business planning process and integrated resource planning process, or just
basically equitable business planning at the company that's focused on people. That's
our recognition justice. I am saying this is not just customer communities, but it's all of us
customers, communities, employees. It's identifying who and where the inequities exist,
and honestly. First, it's recognizing, identifying and acknowledging that perhaps policies
and procedures that we have, that we have chosen, or that are because of regulation,
have resulted in unintended consequences, which may have resulted in unaffordable
energy for some versus others or a host of other of other factors, and it really also is
focused on barrier considerations. And when I say barrier, I mean what are those
individual circumstances?
Annette Brandon: The second piece is process, which is meaningful participation. I think
I fully covered that earlier. I won't go over that again. Foundational performance then,
that's the distribution of the benefits and burdens and the reason I'm calling it performance
is because this is where the metrics will fit in that we're about to talk about. This is where
we're going to hold ourselves accountable, because if we can't measure how we're doing,
how do we really know how we're doing? We need to make sure that we can say this is
how we're doing now. There's a difference between a performance metric and a tracking
metric, and there might be times where we need to track something. We just need to track
it because we don't know, so we need to look for a trend rather than actual end result and
that that's something that we need to consider as we go through it. At what point might it
be a trend? At what point might it be a performance and at what point might a trend
become a performance that could that could happen? Also, you might track it for several
years and then have it be a performance. OK, next slide.
Anette Brandon: The reason why I bring this slide up again is I wanted to make sure that
I did not leave out that we are very cognizant of the fact that we are also a multi jurisdiction
utility and we have customers in both Idaho and Washington. There are different
legislative and regulatory mandates and requirements going on in different states. I think
this is where I just wanted to really reinforce that we are aware of that, and James can
speak to this better than I can. But in in our modeling and in our resource selection, we
are very much considering that and understand the impacts to Idaho. Considering things
that potentially their regulators do not want to have considered in resource selection, and
I say that cautiously because if everything just about least cost versus societal cost. It

Appendix A
could be that cost isn't the determining factor. If it's equity and everything we do, and if
we're considering equity, it might be that one point, that decision point, is not where it's
layered on, it could be down the road in implementation. The next slide will go into that,
but that's why I showed this again just to acknowledge that we understand that and we're
planning for that.
Annette Brandon: Next slide and I even changed it yesterday. For a different reason,
and I think I like the way it was yesterday better than today, but nevertheless, since this
was in the slide deck, this is today's visual. This is the resource and program Iifecycle that
I've been talking about throughout this presentation. It really starts with identifying,
evaluate and where we're at today. We're trying to identify and evaluate, so that's not only
integrated resource planning, but also transmission planning, energy efficiency planning
or customer requested. I added that on there because sometimes we have to allocate
resources because we have the obligation to serve.
Annette Brandon: From there as a company, we prioritize by transmission and
distribution. By several functional business groups that we have across the company and
what our goal is, is to have some of those prioritization metrics include an equity metric
right alongside cost effectiveness. Equity is very related obviously down there to the
impact of process or performance metrics. But the point is that on a functional business
unit team, equity will begin even as early as integrated resource planning. We have to
talk about how to include it in functional business unit, it will have to happen there. On the
selection, that's where we have a Capital Planning Group. The Capital Planning Group
will even pull it up one step farther to ensure that as a company we truly are working
towards a just transition of clean energy for all. I keep saying clean energy, but it's not
limited to clean energy, really equitable access and opportunity to receive the benefits of
the energy system.
Annette Brandon: Finally, once that's all done and we go to execute it, that doesn't mean
that our consideration on equity is over. This is where I think there's going to be a lot of
equity metrics we can put in, those equity metrics that might not have anything to do with
cost. It might have to do with do we know if the customer is on this block where we're
going to be doing work. Do we know what language they speak and have we informed
them? Have we informed them in their language and have we informed them prior than
the day before? And when we're translating, we're doing it with cultural competency or
literal translation, because there is a difference. It might be those projects, making sure
that we are focusing in on when we choose our suppliers. Are we making sure that we
have supplier diversity efforts going on? Are we working collaboratively across internal
departments? This is a work in process. We're not going to get it right. I'm not trying to
say that any of us have it figured out, we don't have it figured out to be quite honest.
Nobody really has it figured out.
Annette Brandon: There's several industry experts out there that are actively working on
it. There is a group, Synapse Energy, which is Tim Wolfe. He has contracted with the US
Department of Energy to come up with some recommendations for benefit cost analysis,

Appendix A
but that's more for distribution planning. There are some ideas that he has there. Pacific
Northwest National Laboratories has some ideas that they're working on also. Lots of
things that are being considered out there, but it's just very complicated and again it's
going to take a village not just in getting participation, but in insuring that we have the
right mix and at what point. Heather, on the line, that's helpful. Because at what point
does it need to be comparable between the utilities? Or does it? That's some of the
challenges that we're that we're facing in this arena.
Annette Brandon: I think that's my last slide. I think I'm running on time right.
James Gall: That's OK because you're next.
Annette Brandon: OK, well, so they go to break here?
Jams Gall: No break here. We'll break after this presentation, but if you need a drink of
water, that's OK.
Customer Benefit Indicators, Annette Brandon
Annette Brandon: OK, next slide. That leads me into how we are going to measure how
we're doing. On this process and performance metrics, I am going to call them process
and performance metrics because I think it makes more sense than Customer Benefit
Indicator. But you know that hasn't been better yet either. Maybe we'll still use the
terminology, but for me process and performance metrics helps me to distinguish
between leading and lagging indicators. A leading indicator might be — have we
intentionally solicited input by a number of times that we've gone out and asked, number
of ways that we've gone out and asked, number of translations, do I know what the
barriers are? Have I taken that step? Have I measured where those areas are?
Annette Brandon: Some of these leading indicators are going to be very difficult in the
IRP process because when you're planning 20 years out into the future, I don't know how
you're going to know how many times you go out and solicit input. Now, that's not to say
that there's not a way. There's just not a way that I could think of or not a way that I could
find in any research that I've done in the process portion. Proactively anticipating how
your project's going to produce the results. The results anticipated was the word there.
Anticipated results and then are alternatives that you need to know if there's inequities.
Do I know that there's inequities? Does one area of town have more reliable energy than
another? We have defined that on a map and I've got a slide on that, a few down, but we
have defined all that and we have some individuals who've done outstanding work in
helping us identify why those areas exist.
Annette Brandon: But one of the main things in these metrics is, am I making data driven
decisions? What we want to do is attempt to take out subjectivity. We want to make sure
that one person that's operating this in one area of the company versus another area of
the company, we want to ensure that we all are working from the same playbook and that

Appendix A
we're all reaching customers in the manner that means the most to them and in the areas
that mean the most to them. And honestly, that's whether it's Washington or Idaho. We
really want to reach those customers who previously we have not met their needs and
that's a benefit regardless of what state you're in. And is it something that we can predict
the change or can we trend it? And then once we've done that, how do we know how we
did and how can we measure that? And are there patterns, that goes back to is it not a
tracking metric or is it performance tracking?
Annette Brandon: This next area is who and where we're focusing our efforts. When I
just talked about those maps, really a key factor will be the development of this portion of
the map. This is not something that Avista can do on its own. We need help from a very
broad, diverse group of people. We of course have the help of our Equity Advisory Group
and that is very instrumental in us ensuring that we understand what our vulnerable
populations are.
Annette Brandon: But let's see if I can be more organized on this slide. The focus is
really the terminology: Highly Impacted Community, Vulnerable Population,
Disadvantaged Population, Highly Impacted Communities. I pulled this out of the actual
designation definition in the WAC, community designated by the Department of Health,
based on the cumulative impact analysis required by RCW 19.405.140, or community
located in census tracts that are fully or partially in Indian land. That's highly impacted.
Scripted for us here out of this stuff. Now, what we have done is taken that definition,
applied it to the map and let's say done, I should say in the process of doing, is we should
be able to click into one of those census tracts and know why it's considered highly
impacted. Is it considered highly impacted because of environmental exposure or
proximity to Superfund sites, for instance? Or, those kinds of issues, it should tell us why,
and so that will be very instrumental in when you're trying to make a decision. If I know
why they're considered highly impacted, then I might consider an alternative differently.
Annette Brandon: Vulnerable populations is a little more subjective. It is based on
sensitivities, those are physiological impacts, that would be something physically that
impacts your ability or makes your climate or environmental impact worse. So, if I have
asthma and then pollution is going to make me feel even worse than it's going to make
James feel, who doesn't have asthma, for instance. And then, those socioeconomic
conditions also: housing, transportation, food, healthcare, access, language barriers.
Those are also on the map. You should be able to go in there and see what are on those
maps. Then, disadvantaged populations, that's a term from Justice 40. It is very small
over there in the Justice 40 policy priorities. It was too much for me to put down all of what
they used as the basis, so I just put down what their priorities are, but they're very similar.
They cross over into the same characteristics as vulnerable, but I did put an example of
a census tract, when you open it up it will say OK, this is disadvantaged. These are the
reasons why energy, health, housing, legacy pollution, and then if you scroll down, which
the box right now is on our mapping, we're working on making it bigger so that you can
easily scroll down. It has each of those, not mapped, but in a column chart. So you can

Appendix A
see legacy pollution is the reason. So then as you're evaluating your process or your
capital plan or whatever your project is. You can say OK, so if pollution is the primary
driver, is my project going to impact that? Yes or no.
Annette Brandon: Again, we don't have this figured out, but we know that this is how
we're going to at least define it and we're working towards other things not just defined by
Department of Energy or defined by the Department of Health. Are there other things that
are unique to Avista's service territory? Likely there are some. There are some areas of
town that that we know about that don't make sense to other people. So, when we say
Peaceful Valley, we know what that means, but a lot of other, I don't want to use the term
stakeholder anymore, interested parties won't intuitively understand what that means. So,
we need to make sure that we're being very clear and understandable when we're
describing things both internally and externally. And again, this process is giving us the
opportunity to challenge our assumptions and challenge our shorthand, if you will, to
make sure that anyone can pick up our planning guide and know what Peaceful Valley
means, where it is and what the circumstances are in that area of town.
Annette Brandon: All right, let's try everything else. Back to data. This is where you really
want to remove the subjectivity. This list that I pulled was actually from a list that was
provided by Washington Staff in Puget Sound's Clean Energy Implementation Plan. I liked
it because I thought that it gave us some considerations of things that we should look at
when we're considering Customer Benefit Indicators or process performance metrics. It
is directly related to policy goals in the public interest policy goals in this context, was the
Clean Energy Implementation Plan. Here in this context, what we would use for the
integrated resource plan. Is it related to clean energy? Yes, but also all of the other
operational parameters that are required in the WAC for integrated resource planning
which is resource adequacy. Resiliency, if those are the same, I don't know. I'm not going
to try to pretend like I'm an IRP expert, but there's pages of requirements on the IRP. Is
the data readily available? Is it focused on an equitable outcome? Is it clearly defined,
articulated, understandable? That's the same thing I was saying on the previous slide on
does everyone know what it means? We can't just say Peaceful Valley. Does it allow for
comparison or trending?
Annette Brandon: The other reason why we're here today is because correlating all of
these factors with the utilities actions and are we able to forecast that is the challenge.
That is the challenge because we can say we understand that energy burden, both sides
of an energy burden, is your income and your expenses well. As a utility, we can sort of
impact the cost. And when I say sort of, I mean we are regulated, and we do have
requirements that we have to follow in the way that we do our rates. Now we're working
collaboratively with the Commission, and the Commission is working towards their
recognition of justice to make our restorative justice. To make sure that all of the utilities
in Washington State, that we're considering how we might address policies like
performance-based rate making. That's just one example of ways that the Commission is
considering equity and how they may make changes to regulation, but that is so it is in

Appendix A
our control but not really in our control. But then you might say, well, OK, the other side
is income and related to income is education. You might say education is outside of our
sphere of control. But is it? Because this is where we have to be very open as a company,
and as all of you on the phone, open to considering, even if we're not directly involved in
that, we're not educators. Is there an index or indirect link and could we measure it? What
mean by this is there's several professions in our, many is a better word, I think in the
utility industry. There's accountants and there's engineers and there's professionals, but
there's lots of traits, lots and lots of trades, and trades are excellent jobs. As a matter of
fact, in high demand and we need all those trades. Could we impact income by looking
at that math and identifying the areas of town where there's low high school graduation
rates, could we have education sessions in those areas that promoted trades? Maybe?
Would it make a difference? At least we could track it. I don't know the answer, but the
purpose here is that it's asking us to think outside the box to help, not solve. Equity is not
something to be solved. Equity is something to be considered. Could we do that for
instance?
Annette Brandon: And then also it's as we learned through the last CEIP, it also has to
be something that can be accurately reported regularly. Is it updated? We found that we
found some information on asthma that we thought would have been a great source and
I know that this went on later and Tamara can speak to this probably later. But when I
was involved in the CEIP, we thought about asthma, but the data that we could find was
dated. That's an example of the data out there. But does it help?
Annette Brandon: These are the Customer Benefit Indicators that we landed on in the
CEIP. Now I do have to check my notes on this one. OK, so these are what we landed on
in the CEIP and honestly, we did a pretty good job because when you think about those
energy tenets. Those four energy tenets, which now I'm going to call people, process
performance, there's also some corresponding principles. The principles aren't as widely
distributed as the tenets are, but a lot of those principles are in these areas: affordability,
access, security, resiliency, environmental. They're calling it something slightly different
in those, and I think there's eight of them. They're calling it slightly different, but in the
end, you could probably roll them all up under these same areas, but in the CEIP this is
where we focused. Under each of these individual equity areas, there are individual
indicators, and underneath the indicators are multiple ways that we're measuring, and I
don't know how many we're up to. Do you know Dan? How many indicators?
Dan Blazquez: 38 indicators.
Annette Brandon: And then I can't remember, I think it's 38 indicators. I don't know.
Anyway, our data people have been very, very busy making sure. It's not quite as simple
as it seems on this slide. So, last year what we did was we went through every single one
of these and all of the metrics to determine which ones could be used in resource planning
and what we came up with is on the next slide.

Appendix A
Annette Brandon: OK, the ones that we came up with on this slide, so we thought we
could consider energy burden. That's affordability and access to clean energy, distributed
energy resources. That's community development and energy resilience, planning
margin, energy resilience and security, generation location. That's resilience and security,
air emissions, environment, public health, and greenhouse gas emissions. That's
environmental. In total we came up with 11 of the 31 that we could model and use as
predictive over the 20-year, but the Preferred Resource Strategy does not consider CBIs
in the objective function. I'll let James explain that as soon as I get to the criteria. The
criteria was categorized in accordance with those benefit areas that we just talked about
and baselines were established, readily available, we could quantify and the metrics are
granular enough to be meaningful.
James Gall: Yeah, I just wanted to touch quickly on what do we you know. What do we
do with the CBIs in the IRP, and we do track them and there's going to be some slides
later that are in the complementary slides that are the different CBIs that we're tracking,
both history and forecast to the plan. But what we mean by not an objective function is
when the model is running and deciding which resources to meet. These specific metrics
are not, there's no goal to change them. We're just tracking them to see where they're at.
We have other metrics such as non-energy impacts that will move the model to choose
different resources that will actually impact the CBIs, but these are not actually goals of
the model to meet, but some of these have constraints. For example, our modeling has
to have a minimum planning margin, which is one of the energy security metrics. So,
different criteria for each of these metrics. But one thing we do want to get out of today,
is if there's metrics that you want to see in the IRP, whether or not they're one of the 31
CBIs that we've been publishing in our last the CEIP. Or if there's something new that you
may have, please bring that up today or email us later as well. So that it will keep going
unless there's questions. OK.
Annette Brandon: What's the next line? OK, so this is how we envision developing these
metrics. Not only do we like to develop these metrics here with the IRP, but we're walking
through this process right now with our Equity Advisory Group because what happened
in our Clean Energy Implementation Plan on the first go round is that, as many of you are
aware, it was a very quick turnaround. Because it was such a quick turnaround, we utilized
a lot of existing data, existing data that was readily available and met all those criteria.
But we wanted to make sure that we fully vetted all the other great ideas that the Equity
Advisory Group had. So, we spent time after that, going through every condition,
characteristic that they outlined, and walking through what does that mean. I use that
Peaceful Valley example because that was one of the metrics that we left on our list for
consideration. But then later we came back and said, well, what does that mean? Let's
walk it through and say can it be mapped. Do we know what the root causes are in that
area? Is it something that we can have a metric on? Does it apply to a resource? We
asked all those questions as we walked through, but still it felt like it needed a reset. It
needed a reset because we have new people on the EAG, we have potentially new
resources that could be evaluated. We just wanted to make sure that we level set and

Appendix A
talk a little bit more about some of the basics. We started with what exactly are the benefits
from the energy system? Because that's what they just keep saying. That benefits the
energy system. What does that even mean? What's a social benefit of the energy system
and what's an economic benefit and what's in environmental impact or environmental
benefit? Some of those seem fairly straightforward, but some of them are not so
straightforward. And if we want to make sure that we truly are giving the customer what
they need in the manner in which they need it, we need to understand what that is and
equity is a comparative construct. You need to be able to compare one group versus
another group to determine if there is in an inequity.
Annette Brandon: So first we have to decide what is the benefit before you even get to
measuring any kind of inequity. What is the benefit? Well, the benefit is that I can go
home, and I can turn on my lights, and I can do all my basic needs. I can meet all my
basic needs. OK. That's a benefit. Now, does one area of town versus another, are they
limited to be able to go home and turn on the lights, so the liability. Well, maybe let's
measure that. Let's see if there are, the terms that get used a lot are disproportional
impact or disparities. Those inequities, those words are used a lot. And on its face, it's a
comparison of an impact of something. In our case, energy, generation, transmission
distribution. Do the benefits of that, these benefits compare between groups? Is there a
difference? That's really what it means. That's we're trying to measure and then do we
understand first what the benefits are? Do we understand why there are disparities? Is it
geographic proximity? Is it physical attributes or sensitivities or they're socioeconomic? It
could be things like redlining. Redlining is a process, or a practice, in the 1970s where
mortgages were given to a certain race versus others. And although the intent of that was
not to discriminate the unintended consequences was that's exactly what was happening
is discrimination and that still stays today, and you still see that in areas of town. And
unfortunately, we have that on our map too, that are mapped so we'll be able to identify
that and measure where they are. But in terms of why some of the historical context is
just the evolution of the industry itself when it used to be that energy was luxury. You
could get safe, reliable power if you lived in town, but if you lived out of town, well, that
was a risk you took. But not anymore. Not now that it's so imperative that we all have
energy for so many different reasons.
Annette Brandon: Once we understand all of that, we can start to make some decisions.
The first thing that we have to do is we need to correlate it. What does that have to do
with us? Does that have to do with us and Avista? That would be direct and indirect if that
example earlier of education, but another example could be housing. We don't build
houses but we could help houses get more efficient and could we measure that? We likely
could even do something through change out of, well I'm just making that up, there's lots
of other things that we could do to help the condition of that house through our
weatherization efforts and those metrics we have, it folds into accountability. Finally, once
we know what these metrics are, what the goal is, then how are we going to use those to
make our decisions? Those would be used in all these different ways in our clean energy
plans, in our capital investments, in this scenario, and in in our federal and state grants.

Appendix A
We want it to be consistent across our company so that customers and employees don't
think, oh well that stops at the border, or oh well that's only electric customers not natural
gas customers. We want to understand the benefits of the overall energy system today.
We're talking about just electric, but there's benefits of the natural gas system as well, so
that shouldn't be forgotten either.
Annette Brandon: Next. These are just some of the examples of what these are. For
me, energy is the actual physical delivery of the power. But social metrics might be is my
process inclusive and accessible? Economic might be job creation, economic growth.
Reliable supply and affordability and environmental might be public health. Indoor/outdoor
air quality and sustainable. Sustainability might come in when you think about the fact
that we're upgrading our resource or we're changing out a resource because we want to
ensure that resource lasts a long time. Our dams are so important to us, and we need to
make sure that they continue to be there for us. They're not only a clean resource, but
they're great for reliability and for reserves and for a lot of other operational reasons. So,
a focus on sustainability in that aspect is really important. Again, a lot of these things, the
issue is what do we do about those factors that we cannot measure, but we know are
important.
Annette Brandon: Next slide. Some of these barriers that we could consider, that again
maybe correlate or maybe do not correlate, but unemployment or underemployment.
Well, maybe we can correlate that with the number of job fairs. But long-term planning
that doesn't apply. And once we get to resource deployment a lot of this is going to fit into
resource deployment. As I said earlier, it's going to be part of an overall company strategy
of working towards equity. So, awareness of programs we talked about that with barriers,
housing conditions, income disparities. What else goes into income? There's lots of things
besides just education, economic impacts. This was an example specific to the transition
of clean energy. Are we considering the economic impacts on fossil fuel workers, for
instance, we need to make sure we consider that if that is the consideration, access is
kind of tricky word because it can mean physical access, or it can mean access to the
process. So, we need to we need to make sure that the process is easily accessible for
all customers. The flip side of that is it is not easily accessible for all customers due to
financing or other accountability structures. A good example of that is transport
electrification and that got brought up in a meeting last week. We can put fast chargers in
certain neighborhoods, but what do we do about helping or should we help those
individuals to have access to that clean technology? Is it geographically accessible? What
about people that are renters that see the need, that understand it, but unfortunately, they
don't see either the financial benefit or they're just flat out not allowed. And then some
mobile homes just are not able to use technologies, that's your physical access.
Annette Brandon: And then reliability, you've got aging infrastructure, limited investment,
grid updates, lack of redundancy and supply, reliability. I think after the events of the cold
snap a few weeks ago, that lack of redundancy of supply. That could be something that

Appendix A
we want to consider, that we need reliable supply, reliable diversity and supply. I think
that's my last slide.
Annette Brandon: Oh no, not at all actually. So alright, so this is now. Diving a little
deeper into the metrics themselves. The ones that are in green are the ones that we've
been talking about. Clean energy was inferred because it was a Clean Energy
Implementation Plan. If we're going to look at something that is consistent across the
company, then we need to have a focus on clean and sustainable, and we should have
some metric on meaningful participation. Currently, I really like the word sustainable
because I just used it again, so we should also make sure that we have a metric on safety.
Let's see what I'm missing. And, transparent like due process, really meaningful
participation. We have it. There are areas that we have considered and areas that we
should consider. The challenge is how? If we have performance measures, how are we
going to measure? Are the metrics working as intended? Some of these questions stem
from results-based accountability and our equity advisory consultant is certified in results-
based accountability. I've seen a few places where that's being used in correlation with
equity. I think that might be another method that we could use to develop some metrics,
but I'm not sure that's applicable in this session.
Annette Brandon: The reason why we're doing this right now also, so the timing of this
is good, is earlier when I was saying that we rushed the CEIP. Also, the limiting factor
with that is that our Clean Energy Action Plan had already been developed. You can't go
back and remake the, can't go back and recreate. This time we want to make sure that
these metrics, whatever we decide, help to inform on a proactive basis. And then as it
helps to inform our Clean Energy Action Plan, then as we get into the development of the
Clean Energy Implementation Plan, that's where they'll have metrics that extend that
across the clean energy as well as capital planning and integrated and grant work. That
process will continue, it won't just stop, it's an ongoing process, but that's where the timing
of this is right now, because James and his team are working on that right now. That's
why these questions are coming up right now. There have been ideas that is there a way
that you can take these metrics and do a point system. Some kind of a point system where
you make everything a point whether it's quantified or qualified, make it a point. Because
then you can pull it all into the same apples and apples, and then you can score it
accordingly. That's an idea. How do you do that? How do you how do you prioritize that?
That would be a lengthy conversation. Not saying that we couldn't have it at some point,
but that would be a lengthy conversation. Also, as I referenced Tim Wolfe earlier, he has
a least cost, best fit analysis, and so he has ideas. If it's mandatory and compliance, you
would evaluate it one way versus if it had a little bit more optionality to it, you would
evaluate it a different way. But again, I don't know if that is related to IRP planning. I think
that is related to after if the model chooses a new wind farm, then it seems like you would
use that in that area. That's where you would evaluate it. And again, if the goal is equity
and everything you do and to ensure that we have an equitable overall process, it doesn't
have to be only in this one piece as long as overall the goal at the end of the day or that
we reach, we work towards meeting the goal at the end of the day that customers have

Appendix A
equal opportunity to receive equitable outcome from our decisions and from our practices
and policies.
Annette Brandon: What else did I print out here? There's lots of ideas in distribution
planning, but a lot of it is about non-wire alternatives or grid mod. The US Department of
Energy Modern Distribution Grid Strategy and Implementation Guidebook that was
published in 2020. That gives some ideas as to how you might do that on a distribution
level. They use things like target population identification, investment decision making,
which includes program accessibility, energy cost index, energy burden, late payment
index, appliance performance. Some of those they use also have some equity in
investment decision making program funding, energy use, energy quality, energy quality
which would mean like those are your measurements: SAIR, SAIDI and CAIDI) those
measurements, program impact assessment would be not necessarily affordability but it's
program acceptance rate or energy savings or energy cost. Energy cost savings relates
to energy burden which then relates to affordability but it's the catalyst side of the fact that
a lot of the time we are impacting rates because we're building new resources or
identifying new resources potentially in this process. So, the key is to do so, being good
stewards of our resources and recognizing that this is going to have an impact and doing
our best on that impact.
Annette Brandon: Let me see what else I have on this. I wish that there was some kind
of energy standard that we could all follow, but there's not really. There's just a lot of focus
on availability, affordability, due process, energy burden. We're all really familiar with.
That's the percent of household income. But I think do you have that? Second we can do
some little bit of brainstorming sessions.
James Gall: Sure, we have some time.
Annette Brandon: Sure. That sounds good. I think I'll stop my brainstorming then. And
then the rest of these slides are just supplemental. They are the metrics we're tracking.
James Gall: Since we have a little bit of time before a break, I'm going to go through
quickly some of the metrics that we included in the last IRP. Maybe it'll give you some
ideas on is this something that we should continue to use in the IRP? Is there something
we're missing or should add? I'll quickly go through those and please raise your hand if
you have any ideas or questions even on the metrics that we're tracking. I'll try to give
you a brief overview of how it's used and calculated.
James Gall: Annette mentioned energy burden in the IRP. We are trying to identify the
number of customers that have energy burden with this. This is percentage of income
versus the cost of their energy. This is, I would argue, a very high-level estimate. But the
idea behind this metric is to ensure that we're not creating adverse cost to our customers
that have the lowest ability to pay. Like we mentioned earlier, we're not targeting our
modeling to ensure this this specific CBI goes down, but we're monitoring it now. Could
you create a plan that requires us to reduce? Yes. And we'll get into that a little bit later
today. This is just something we are tracking. So, this one, number of customers, it's

Appendix A
around 45,000, it's very flat or around our low growth expectation. Another way to look at
it is percentage of customers, around 20% of our customers have a high energy burden.
They're above 6% of their income and that's expected to remain flat in this last IRP. What
does that cost of excess burden measure? This is measuring the actual dollars that is
above that 6% of their income. That's around $1,000 initially, and this is actually an area
where we're seeing customers with lower incomes have a higher energy burden. CETA
law, the Clean Energy Transformation Act is not likely to lower costs of electricity. It's
going to increase cost to electricity. This kind of shows that impact to customers at lower
incomes were they'll have a lesser ability to pay now with energy burden resource
selections. Not the only way to address energy burden, which is one of the reasons why
this is something we don't necessarily target in an IRP because there are other
mechanisms to help these customers through energy assistance, rather than just
resource selection.
James Gall: Another one that we're tracking is megawatt hours of distributed energy
resources in in communities. Part of the CBIs was to increase distributed generation
resources or storage resources in the Named Communities. We did have some new
distributed energy resources selected through our Named Community Fund which
contributed towards an increase. You can see the history and the forecast in this slide,
history shows the real weather impacts of distributed energy resources. Production does
change over time and the forecast is more of an average energy or expectation of normal
weather going forward.
Kelly Dengel: A hand is raised.
James Gall: OK, go ahead Heather.
Heather Moline, (UTC): Thanks, Heather from Utilities and Transportation Commission
staff, this includes energy efficiency savings.
James Gall: I don't believe so in this this case. We have a different metric for that one,
but this one is just generation. I think energy efficiency would be higher if I remember
right, generation and storage.
Heather Moline (UTC): This would be generation and storage. OK. That makes more
sense. Is demand response included here or just generation and storage?
James Gall: I think this is just generation because demand response will be very few
megawatt hours, you wouldn't notice it, and it would be available to all customers.
Heather Moline (UTC): OK.
James Gall: I think those are different metrics that we're tracking. And then, energy
efficiency, I believe that's separate as well, but we could check that.
Heather Moline (UTC): And so DER's, this generation that's connected to the distribution
system, so like rooftop for community solar and what else I guess is in this category is my
question.

Appendix A
James Gall: Yeah, so this is mostly actually PURPA generation. This would not include
customer owned generation. This is utility owned or utility purchased. We have a number
of small hydro facilities in our service territory. That's what most of this generation actually
probably is, PURPAs. PURPA would count anything that's under 5 megawatts.
Heather Moline (UTC): OK.
James Gall: Storage, for example, doesn't generate energy, it just moves energy.
Actually, storage would probably reduce these amounts, so maybe it's not a good
resource to put in here because it's a load. It's not a generator.
Heather Moline (UTC): OK, I'm chewing on how a PURPA hydro facility would
necessarily bring a benefit to a community where it's located. I'm not saying it wouldn't.
I'm just chewing on that.
James Gall: Yeah, that's OK. I could give you ideas if you want, but this was, again, in
our CEIP process. This is one of the items that came up that we were asked to track. And
if this isn't relevant anymore or should be changed, I think this is a good time to talk about
that.
Heather Moline (UTC): Yeah, I would love to get your ideas, I think when people bring
up DERs in Named Communities they mean because of the definition of CETA and
because of the clean energy transformation standards which say equitable distribution of
energy and nonenergy benefits to Named Communities. The intent here from that law is
how are we distributing benefits and non-energy benefits equitably and so if you all are
clear, that a hydro PURPA facility is bringing some benefit to the communities where it's
located, even if it's owned by Avista or even if it isn't right? Then great. Let's talk about it.
But I do wonder if this is what folks had in mind when they asked you to track this
condition.
James Gall: Yeah, you're right. Definitions matter.
John Lyons: I thought this was also more for having a clean, local, reliable resource. We
had an area that was a disadvantaged community, and they traditionally had some
problems with outages by having a resource located in that community that should help
with that.
Heather Moline (UTC): That makes more sense, which is different from. Well, it's not the
same thing as equitably distributing benefits, non-energy benefits. This is just a
hypothetical question. Oh, and I guess Sofya and Josh went away, but just before I jump
in a hydro facility that's five megawatts or less located in a Named Community. The way
the grid works, if there was an outage there, would it necessarily mean that outage would
be restored quickly just because there's a PURPA hydro facility nearby?
James Gall: Well, I would argue an outage is going to take the, it's not going to prove it's
more of a preventive of an outage if there is a load that can serve it. I wouldn't argue that
this will prevent an outage. It may be more prevention in certain circumstances, but if you

Appendix A
had a line go out from the generator to the customer, that's not going to prevent an outage.
It's very situational, but I think this really was driven by economic benefits to the
community. You have increased tax base, you have potential for jobs. So, their reliability
helps, but you may have lower cost to the area because you have generation near a load
that you don't have to upgrade distribution equipment as soon as you would otherwise.
But reliability I think is very situational. Whereas if your system was overloading, but you
have a generator there, that prevents an overload that would prevent an outage. I don't
think these resources would sustain a customer through an outage unless the generator
is at the customer's premise or directly connected, it's not going to prevent an outage. It's
not going to serve a customer during an outage unless it's directly connected. OK, so we
have two more hands up. Sofya, go ahead.
Sofya Atitsogbe (UTC): Hi, James, this is Sofya Atitsogbe with the Utilities,
Transportation Commission as well. My first question was the same question Heatherjust
asked about the resilience and the reliability enhancement that the DRs would bring to
the Named Communities. I'm kind of surprised by your answer, because everything we
see about the benefits of the DER and the economic reasons or the economic benefits
older although exist are not as great as the reliability and resilience reasons for the DERs,
so it's interesting that you are mentioning that they are actually secondary to the economic
reasons.
James Gall: OK.
Sofya Atitsogbe (UTC): That's just a note that I would need to research further. And the
second question, if that's the economic reasons that drive the DER, that's probably not
that important. But if we go from the, I would say federal understanding that cause I'm
hearing it from all the commissions including ours. Storage of energy is pivotal for the
Named Communities that get a power disruption and although it's consumption, when the
battery gets loaded, it is well, I considered generation when the battery gets discharged.
My question is, doesn't it make sense to include the battery that would be able to serve
as an energy source for the community that gets an outage into this DERs and Named
Communities graph?
James Gall: Yeah, as far as a Named Community grant side, yes. But I actually was just
saying a literal MW hour accounting of a storage resource, the amount of charging is
going to exceed the generation. If you netted the two, it would be a reduction in
generation, not an increase unless you ignored the charging cost. The way we dealt with
storage, we had a separate category and that's on this next slide which shows the amount
of MW hours that is available for charging. This is a better way to characterize energy
storage and separate it out from this calculation here, which is why we did that because
we didn't want to basically put a resource in there that's really a load and show that
benefit. So, it is separated here. Again, this one is just intended to be how much energy
we are acquiring. Storage we separate out, that makes it, I think, a little clearer.

Appendix A
Sofya Atitsogbe (UTC): Got it. Yeah. Thank you, James. Can I ask you to, when you go
to the next slide, to also touch on if this battery storage will help Named Communities in
resilience and reliability, but I'll wait until you get to that slide.
James Gall: We'll do that.
Sofya Atitsogbe (UTC): Thank you.
James Gall: OK, no problem. Go ahead, Josh.
Joshua Dennis (UTC): Joshua Dennis from Utilities and Transportation Commission.
Also, I was going to talk about the battery situation, but I think Sofya touched on it. But I
guess more so I would like to expand on that a little bit. I know that Avista has their virtual
power plant at 3rd and Hatch with two named communities in that pilot and I was
wondering if that in particular is going to be considered a load or generation because of
some of the things that I was reading in the DOE application on what Avista was
considering load and generation.
James Gall: Yeah. Just from a practical point on a battery is both a load when you're
charging it and its generation when you're discharging it. Its generation is going to be less
than you're charging as far as a battery that's owned by Avista and controlled by Avista.
The load side is not charged to the customer. If a customer puts a battery in their house,
they're going to have an increased bill because of charging that battery. Unless they have
say time of use rates that they arbitrage but just need to be aware of what you're getting
with a battery is you're being able to move power from one period to another at a cost of
energy to do that. I don't know if anybody on the call from Avista that may have some
information on how that program works at 3rd and Hatch to help with Josh's question.
Otherwise, I'll be speculative on how that program works. I'm not hearing anybody from
Avista jump in. We may have to get back to you, Josh, on that.
Joshua Dennis (UTC): Oh, for sure. Just one more considering grid modernization. And
I know that a large focus has been on reliability, but could you touch on any metrics that
intersect with the resiliency that's going on with the focus on energy justice for these
Named and Highly Impacted communities?
Annette Brandon: There's a lot of information out there on resiliency, but of course no
solutions. What tends to happen, and this would be evaluated in the DPAG, they start
with a consideration for all of your operational parameters and then resiliency is added
on top of that. That's where your difference between your least cost and what they are
calling least cost best fit and I want to dig in my paperwork right now, but it's where two
different scenarios are then added together to come up with the scoring. That's really
what I've been following and trying to keep track of what's going on there with the national
laboratories. It was put out from Berkeley. Wait, I have it exactly, here is the benefits and
costs of grid modernization benefits that was put out in 2021 Benefit Cost Analysis for
Utilities Facing Grid Modernization Investments, Trends, Challenges and Considerations.
I've been looking at that, but so far, they haven't come up with any kind of solutions.

Appendix A
guess the answer to your question is I'm not sure yet. But I would imagine that would be
looked at in our DPAG.
Joshua Dennis (UTC): Thank you so much.
James Gall: Alright, I'm going to touch on Sofya's question here on reliability when it
comes to storage. Now there's what can happen and what is more of reality to some
extent. If you think about a distribution system of a neighborhood and there's a storm that
goes through, unless that battery is connected to that home directly and is isolated. When
an outage goes through, it's not going to protect from reliability. Now, in a separate event,
like if you had another heat dome event where there was a battery on a distribution system
that could relieve loading on the line and prevent an outage from an overload, a battery
can help with reliability in that situation. Just because we have additional energy storage
in a Named Community doesn't necessarily mean it's going to prevent outages. It's going
to prevent maybe extra cost to our system, or it could prevent an outage in a specific
situation. Unless that customer has the battery and the ability to disconnect from the grid
and use that storage, it is not going to prevent an outage for that customer. I think we just
got to make it very clear on what you're getting with storage. Now if we created islanded
off communities, then that would be a different situation. But hopefully that helps as we
go through this.
John Lyons: A good example you'd see on that, success stories, where it'd be either a
hospital or a university where they totally disconnect from the system, and they have their
own battery storage system. That way they disconnect, they supply their own load, and
then they usually have some other supplemental generation to refill the battery, a solar
panel, something like that.
James Gall: Josh, go ahead.
Joshua Dennis (UTC): So, when you said disconnect, it reminded me, and I wanted to
check on the progress so far with the microgrid project that the Spokane Tribe of Indians
and Avista are working on because it sounds like it is something that directly is what
you're talking about.
James Gall: Yeah, that is an example. I don't know if anybody from Avista on the call that
can let everybody know what that project is. I know enough to be dangerous, but I'm not
an expert. No one.
Tamara Bradley: I don't think we have Megan on the call, James, and she would be our
SME [subject matter expert].
James Gall: I'll give a brief concept of that for those of you on the call. The Tribe was
looking at trying to create a microgrid project and Avista was contributing dollars for
designing the microgrid. What it would do is there are a number of buildings in the town
there that would move to a backup generation source if there was a long-term outage. I
don't know exactly what their planned technology is at this time, but that is the concept
where it's a number of buildings would be able to sustain the outage, but it would be

Appendix A
limited load. It's not as normal, but it's critical loads that are able to continue on and then
I believe they had a desire to be able to stay online for those critical loads for up to a
week. Again, it's in the design phase last I heard.
Annette Brandon: Can I comment more on the, can you go back one with the one slide?
I want to comment on this slide a little bit. It took me a minute. I had to go back and
reference what we had done in the CEIP. I think the reason why we're talking about this
being the PURPAs and under 5 megawatts is because the condition and the associated
CBI was under our Named Community Investment. Our Named Community Investment
metric, that CBI. So that's why it was focused not on the economic benefit, but particularly
on the megawatt hours. Actual investments were the total megawatt hours of DERs, five
megawatts and under, and total megawatt hours of storage resources which he has on
the next one. But I think that's probably why, because the purpose for this one wasn't to
measure economic development. It was to measure just under 5 megawatts, which is
consistent with the PURPA definition, and I'm reaching back, but I believe that's why we're
tracking it this way.
James Gall: And I am starting to remember that I think customer owned solar may be
included in here because I remember Kim was trying to identify those. So, there's a good
chance that is in this in this calculation as well.
James Gall: All right. We got about 10 minutes before break. I want to kind of run through
the rest of these. This is a good discussion and it's important to have, so let's continue as
it comes up. Another metric we were asked to track through the CEIP process is to
account for benefits that are either non-energy impacts or utility benefits compared to
initial investment. This is a little bit of a loaded chart, but the concept is when we do our
modeling, we have a benefit, which I would call a revenue or a benefit, whether it's an
NEI or utility benefit. We are graphing the annual benefits of those resources. If for
example, our model picked a community solar facility, there would be an energy benefit
that would be shown in the orange and then there would be a non-energy impact benefit
or cost that is shown in green. I believe the costs aren't shown in this case. We were
asked to only show the benefits and those are the annual benefits of the resources that
are selected for Named Communities. That's compared to an annual investment that is
shown over time. To me this was, when you have people coming up with ideas, does this
idea come across with the intent of the idea? I'm not sure, but this was what was asked
of us. I don't know if this is something that we'll want to continue to do or we need to
reshape or reimagine how this looks, but this is what was asked for us in the last CEIP.
Definitely want feedback if you have it. If this works as is, that's good feedback. If we need
to reimagine this, I'm up to that as well.
James Gall: Continuing on, since we have a limited amount of time, planning margin is
the percentage of load, sorry the percentage of amount of generation that we have that's
available during a peak hour compared to load. We have a history and a forecast. This is
an area where our modeling actually has a minimum requirement of planning margins.
And what you see in the past is what actually occurred. You're looking at how much

Appendix A
generation was actually available against peak load and then the forecast is trying to
forecast out based on normal weather conditions, how much generation is available
compared to that expected peak load. Now as we go through time, you're going to see it
move up and down like you saw in the last couple years. We also have new generation
coming on over the next few years, which is why you see an increase from recent history.
But again, this is an area where we actually do have a minimum requirement in our
planning. We're going to be evaluating changing our minimum requirements in this IRP
and they'll be some discussion of that in a future TAC meeting.
James Gall: Another thing that was asked of us in the last CEIP process is to look at
generation that's connected to our system, or in the State of Washington. The reasons
for this one is partly economic development. Partly you're increasing reliability and
resilience because you're selecting resources that are on your system and not further
away from your systems. There's the probability potential loss is greater when you look
at projects further away from your system, that's at least the theory, but as you can see
we've historically been around 80%. We expect that the increase as a percentage of our
load when some new resources come online, but then after that our IRP expects a
reduction of localized resources when we start looking at the same resources maybe that
are in Montana or wind or systems that could be out of state. But in reality, an IRP versus
when you actually go require the resources will likely come up with a different answer. It's
interesting to track historically, but we can't necessarily predict if a resource that's 15
years from now is going to be in the State of Washington or connected to our system.
We'll go through a request for proposal process where we'll evaluate alternatives, and we
may select the one that's on our system in the state or we may not. So, this is very
speculative in an IRP.
Clint Kalich: James, when you do your RFP valuation metrics, you have metrics to say
bias for certain [too faint to hear] set this to occur, so it's not something that's lost in
processing still and that can be affected by the metrics that's created when we do the
...[trailed off].
James Gall: Correct.
Clint Kalich: If we have a need, we can increase the weighting of those types of things.
James Gall: Well, I don't know if everybody heard Clint, but he was mentioning. Quick
mic check for everybody here because he is far away from the microphone.
Heather Moline (UTC): No.
Kelly Dengel: No.
James Gall: OK, I'll repeat what he said. Basically, in this instance, our request for
proposal process when we evaluate resources will pick up this metric because we're
going to include an incentive for the utility to want to acquire this resource, maybe over
another resource. I'm going to actually touch on that in my last presentation of the day.

Appendix A
Lori Hermanson: The other question is about when the next IRP update is being
released.
James Gall: OK, so the next IRP, we will have a draft out September 1st and we will file
that with the Commissions in both states on January 2nd of 2025. So, it's coming up.
Another one we track is Washington air emissions, and this is what our plants in the State
of Washington are producing from an SO2, NOx and VOC perspective. We also have
another one on greenhouse gas that's separate, but we've targeted just these three
metrics from our last CEIP and this one I want to touch on. This is something we talked
about. Are you planning for a specific outcome in this case? We include an economic
penalty for these emissions so that our model can take the economic benefit or cost of
these emissions and weigh that against other resources. Again, we have greenhouse gas
forecast and the plan again, this is another thing just like the air emissions, we put an
economic cost of these emissions and obviously CETA does require 100% clean energy
by 2045. That's a goal or a target in the plan, regardless of what the metric is.
James Gall: We also tried to look at regional emissions in our plan. I would say this is a
very difficult thing to do because we are not in control of transportation emissions. We
also have customer level emissions we're not in control of. The only thing we can really
account for is to look at history of where emissions are tracking in Eastern Washington.
We could try to forecast how much our emissions are going to reduce. We can forecast
maybe how much natural gas emissions are going to produce based on the plan. We can
forecast how much EV load that we're including in our IRP, but that doesn't necessarily
mean that emissions from the transportation sector are going to be falling. It depends on
how much new cars are on the market. This is an area where it was a noble idea to model
in an IRP. I don't know if this is something we want to continue doing in the next plan just
because there's so many factors outside of our control, but I think it is important to at least
track historically. But from an IRP perspective, can we forecast emissions? I think the
answer is no. This might be one that maybe not be appropriate for an IRP in the future or
maybe it is. But love to hear feedback on that since we are getting close to a break.
James Gall: That's the last slide I had. These are the metrics we're monitoring. We did
have an idea to add a target on, I wouldn't say a target, at least a metric on how our
resources are separated by fuel source. So, if we want a more diverse fuel supply, we've
discussed creating a metric on that which would theoretically lead to increased resiliency.
For example, I think it was in our last TAC meeting we talked about using a Herfindahl
Index of our resource supply so that we could try to measure diversification of our
resources. We also talked about potentially looking at a metric for wildfire resilience.
We've done some more investigation on that, and I don't think that necessarily applies at
least as a metric in our IRP, but that's something we can think about. But what I would
like from the TAC here is if there are ideas that we're not including, or there's items that
we should probably think about changing or removing, let us know, We don't have to do
that at this meeting here, but email would be appropriate afterward as well. But when we
take a break, maybe that's the time to think about it if you want to. We'll just check in with

Appendix A
the group when we return from break to see if there's any additional ideas. With that, let's
take a break. We'll come back at 10:45, 1 think is what we had. OK. We're going to go on
mute and then we'll be back at 10:45.
How Avista Includes Equity Principles, Tamara Bradley
James Gall: Welcome back. It's 10:45 before I turn it over to Tamara. I just wanted to
check in if anybody had any additional thoughts on Customer Benefit Indicators during
the break. I'll just let it pause for maybe a few seconds. Any ideas before I turn over to
Tamara? OK, so if you do think of something, please put it in the chat or email me later.
We're going to do a presentation on how Avista practices equity outcomes. Tamara
Bradley is our, so we get your title right, but a Manager of Customer Impacts. Is that still
what it is?
Tamara Bradley: Social impact. Close.
James Gall: I was close, alright.
Tamara Bradley: Close. Am I sharing slides, James or do you guys have my slides?
James Gall: It would be best if you did. You could do that.
Tamara Bradley: OK. One momento, please. Unfortunately, the slides that I have say
draft across the top of them, but I think we'll be OK. Let me see if I can get there. Are you
guys seeing them in the room?
James Gall: We do, but if you could make it bigger or full screen, that'd be better.
Tamara Bradley: I only have this version, I think. How about that? Is that a little better?
James Gall: That's better. Yeah.
Tamara Bradley: I can try once more. Oh, that's too big. OK, how about that?
James Gall: We can see it now.
Tamara Bradley: OK. Well, we will do our best. Thank you and welcome back from break.
As James said, my name is Tamara Bradley. I'm the Manager of Social Impact here at
Avista and I'm happy to give my friend, Annette Brandon a chance to catch her breath
after all of that information. My colleagues are here today to actually share about some
of the ways that at Avista, we are actually practicing equitable outcomes. I'll touch on a
couple of our equity efforts and then we're going to dive into affordability and also the
investments that Avista has already been placing into our Named Communities.
Tamara Bradley: So, with that, Annette had touched on the evolution of equity, but I have
this light up here because I just want to point out that the energy industry is no different

Appendix A
than any other industry and that we are really impacted by what's happening in the world
around us. And so, for you historians out there, we are actually gearing up to celebrate
our 135t" birthday, and I won't make us sing happy birthday here. But we were founded
in 1889 as Washington Water Power Company and back then, for many decades the
emphasis was on safe and reliable energy. And then came the Great Depression, starting
in 1929 that lasted till roughly 1939-1941 and then the focus was not only safe and
reliable, but now we're going to add affordable energy into that. And then Fast forward to
the 90s, one of the best decades, I'm just going to throw that out there. We start hearing
about clean energy and the impacts to our environment, which really brings us to present
time and the utilities building equity into our everyday practices, our deliverables and our
outcomes.
Tamara Bradley: So, the first thing I wanted to highlight, and Annette mentioned the EAG
and that is Avista's Equity Advisory Group. This group was actually established out of
direction from CETA legislation, and it was formed all the way back in spring of 2021 and
the members, I think Annette also pointed out they had actual significant impact on input
on our 2021 Clean Energy Implementation Plan. That included definition of vulnerable
customers in our service territory as well as the creation and prioritizing of our Customer
Benefit Indicators. We continue to meet with the EAG monthly offering two different
sessions. For three years we have met with this group on a monthly basis and when our
plan was approved, our CEIP was approved June 16t", I think 2022. In that approval,
Avista accepted 38 conditions that came along with the approval from the Commission.
And of those 38 conditions, I think it's important to point out that 11 of those 38 had direct
impact with the EAG, so that could have been where we needed their guidance, their
support or their approval on those conditions.
Tamara Bradley: We filed the outcomes of those conditions in our biennial report, which
was just recently filed in November 2023. The EAG is also significant because they have
dollars to play with, so they provide direction on $500,000 of our named Communities
Investment Fund and we're going to dive into that as well. And I like to explain that EAG
either live, work, play or represent our Named Communities. These are not folks that
speak utility talk. They are not a technical group. They really are our equity lens that we
utilize to help Avista make decisions that affect our communities and the customers that
we serve. We talk about a variety of topics. Could be anything from electric transportation
to indoor/outdoor air quality.
Tamara Bradley: Our CBIs are the way that we are measuring. Over these next couple
months, we're actually speaking to them about our current CBIs, but also looking at
opportunities for new Customer Benefit Indicators for our 2025 CEIP. I have an audience,
so I'm going to make a plug if you want to learn more about the EAG. If you're interested
in attending, listening or becoming a member, I'm going to have my friend Annette throw
my email into the chat and also Amanda, if you could put the CETA email address in
there, that would be great. So, happy to talk with you offline if you would like to learn more
about our Equity Advisory Group.

Appendix A
Tamara Bradley: I did want to point out, sorry, managing a couple different screens here
that we do have additional advisory groups here at Avista besides the EAG. I'm just kind
of biased towards that one, but we have the Energy Assistance Advisory Group, and this
group is really an established forum that focuses on low-income energy assistance
efforts. They monitor and explore ways to improve Avista's low-income rate assistance
program, which is referred to as LIRAP.
Tamara Bradley: And in fact, the Washington low-income program just went through a
major overhaul and Kelsey Solberg will speak to that after me and talk about the ways
that equity is represented in that program. We have the Energy Efficiency Advisory Group,
which is made up of stakeholders that advise Avista on conservation programs. And
again, look for ways that we may modify or measure those programs differently or develop
new programs. And then the DPAG, the Distribution Planning Advisory Group is our
newest established in 2022. It is a technical group, and its purpose is to examine
distribution efforts and non-wire alternatives for our major transmission and distribution
investments. We also have the natural gas IRP, I think that was mentioned, and one that
doesn't get talked about too often is an electric vehicle supply equipment stakeholder
group. I just wanted to plug all of those and you can learn about all of our advisory groups
at www.myavista.com/CETA and we will put that in the chat as well.
Tamara Bradley: Annette touched on public participation and equity as about really
actively seeking out and empowering our customers and communities through
meaningful, and I know she really stressed that word, meaningful participation. Equal
opportunity and fair access to our energy services. So, removing barriers is key,
especially for our customers that have faced many barriers to participation and not been
able to participate in the past. We recognize that at Avista we are not experts at
determining all of the barriers that our Washington customers face. So, in Q3 of 2022, we
contracted with someone who is an expert and that is Public Participation Partners,
referred to as P3, to examine which barriers our customers do face in our service territory,
which was one purpose, but even more to help us build a mitigation plan on how to reduce
those barriers to participation.
Tamara Bradley: In May of 2023, so many dates — so many reports, Avista filed our
public participation report with the Commission. This public participation report is tied to
CETA, but it is a separate report and this outlines our actions that we intend to implement
to reduce the barriers that our customers face. I'm pleased to say that since May of 2023,
we have actually implemented several of those action items and we will continue to carry
out our plan throughout 2024 and 2025. We don't have time to go into the details of all
the actions that are listed, but I wanted to point out our language strategy and our
roadmap around language because that is a barrier that tends to rise to the top for Avista
customers. We are in the process of developing our multi language road map and this is
in order to provide really adequate assistance, information and accessibility to our non-
English speaking customers. And we do this by evaluating our customer facing channels.
This includes our website, our mobile app, our IVR which is our phone system and other

Appendix A
areas of the company. That effort is underway. Again, it is a road map that will take some
time to achieve all of it, but I think it's important to highlight.
Tamara Bradley: Other topics to touch on includes capital planning, federal and state
grants, and supplier and employee diversity. Avista is developing and implementing
equity as a requirement in our capital planning process. We're looking at how our large
capital projects are being implemented and affecting the customers for that location and
even more so giving the customers a voice to that project. I think Annette had also
mentioned that. We know with this administration that there is a lot of federal money out
there. There's a lot of state dollars out there and so Avista has established a key internal
stakeholder group that is looking at securing funding that reduces the barriers and
burdens that our customers face. This could be going after funding that increases access
to clean energy, ensuring broadband to some of our most rural communities. As you
know, Avista has a large service territory. Or even providing workforce training and energy
related fields to those that may not have access otherwise.
Tamara Bradley: I'm going to the supplier and employee diversity aspect which, actually
both of those are Customer Benefit Indicators in our CEIP. This is really important
because Avista wants to represent through our suppliers and work force the communities
in which we in which we serve. We know that diversity strengthens partnerships, it fosters
innovation and competition. It enhances customer loyalty, and it contributes to the overall
economic growth and development of our communities. Again, those are just highlights.
Tamara Bradley: The next slide is our CBI slide, which Annette also showed. It's
important and you're going to see this from Kelsey as well in just a minute. But the reason
why I have this slide up here is because regardless of what topics we're talking about with
our Equity Advisory Group, we also hold quarterly public participation meetings. Our next
one's going to be in March of 2024. Everything really ties back to our Customer Benefit
Indicators. I touched a little bit on unemployed diversity and supplier diversity, but that
first equitable area there, affordability, is so key to our customers. As we survey our
customers, it's the one that always rises to the top and like I mentioned, our program just
went through a major overall. I'm going to pass it to Kelsey Solberg. Who is our program
manager of our low-income assistance programs to talk about that program in more
depth. Kelsey, I'll give it to you, and you let me know as you want me to go through the
slides.
Kelsey Solberg: OK, sounds good. Thanks, Tamara. Good morning everyone. As
Tamara mentioned, I oversee our low-income energy assistance programs and we'll be
talking today about how those programs help to increase customer affordability and also
promote equity. We can Scroll down there. This will look familiar, I just wanted to highlight
that the affordability CBI includes everything listed there. We have participation in our
company programs addressing households with high energy burden. We did hear a little
bit about energy burden from Annette earlier, but we'll touch on that, and then residential
arrears and disconnects. Arrears are past due balances for our customers. These are all

Appendix A
indicators that we really addressed through our bill assistance programs and then and
that's what we'll be talking about here. We can scroll there.
Kelsey Solberg: Thank you. So what is Bill assistance? Bill assistance really focuses on
increasing informed affordability and it uses energy burden as the metric for affordability.
That's how we're measuring it. Energy burden, this was mentioned before, but it's pretty
simple to calculate. This is just the percentage of monthly income that is going towards a
household's energy cost. What percent are they spending on energy of their overall
income. Industry wide, we look at high energy burden as being 6% or greater than 6%
and a severe energy burden being 10% and up. And so most forms of Bill assistance,
including ours here at Avista are aimed at reducing that 2 below that 6% threshold. So
that's increasing affordability is sort of the result of that.
Kelsey Solberg: If we Scroll down there for me. Thank you. These are the different ways
that we aim to reduce energy burden. All of our programs fall into each of these
categories. We have the affordability increase. We also seek to address past due
balances for our customers, so helping them get back to a zero balance. We provide a
lot of support during hardship, so we recognize that life happens. And we want to be able
to meet customers where they're at and provide them with support. We also do education
around energy conservation, using tools and resources, providing those to our customers
so that they can actually reduce their usage of energy, therefore making it more
affordable.
Kelsey Solberg: The next slide shows more of how we do it. This is a kind of at a glance
overview of the programs that we offer at Avista that fall under that LIRAP umbrella or
low-income rate assistance program. These all seek to reduce energy burden. You'll see
the categories there on the left. We have affordability, past due, hardship, and energy
conservation. Those are the ones that we just looked at and each of these has a program
that's associated with it. But for the purposes of this, I'm really going to be focusing on
those top two, so affordability and past due. This is really because one, these are most
closely related to CETA, which we've been talking about today and they also have
features that not only support affordability, but they also have a lot of equity design
components that we will touch on as well. That's where we'll be focusing.
Kelsey Solberg: In terms of increasing affordability, this is one of the programs that really
marks what Tamara mentioned as being kind of this overall overhaul or major change
that happened just this last October in Washington. The new program that we launched
is called My Energy Discount and in in many ways, like I mentioned, it really did change
the landscape of the list for Avista. With this program, customers who are income qualified
can receive a monthly discount on their Avista bill and not a discount based on their
income. And these discount percentages are designed specifically to reduce that
customer's energy burden to below 6%. Again, we're really aiming at reducing that energy
burden for folks. And this is one of the ways that we're doing that. Another thing that's
notable about this program is that there is no paperwork required, and so customers don't
actually have to provide proof of income. They simply attest to their income and their

Appendix A
household size, and we use that information to determine their discount percentage. It's
a very low barrier in terms of accessing the program. Something else that makes this
easier for customers is that we now are joint administrators of the program. Previously,
customers could access energy assistance through their local community action agency,
and that would involve making an appointment, getting to the appointment, perhaps they
need childcare, or perhaps they need to translate. Or perhaps they need to pay for
transportation. They would need to bring their paperwork and go through that process in
order to get energy assistance. But now, as of October, Avista is a joint administrator so
customers can actually come to Avista. They can call us, they can apply online, or they
can file a paper application, and they can of course still go to their community action
agency. But we're really just opening three additional doors to accessing these benefits
that were not there before.
Kelsey Solberg: Customers who enroll in the program also remain eligible for other
energy assistance programs. There are federal programs that are available. A lot of our
action agencies have access to other grants or donation-based programs that they can
support customers with, and so just because the customer receives this benefit does not
mean that they become ineligible. It's just another item on their menu of supports. We
auto enrolled 18,000 customers in October of 2023. These are customers who within the
last two years had received income qualifying assistance. This was a way for us to
increase accessibility to the program and recognizing that these are customers who have
received energy assistance before, they're likely still eligible. And so, we're going to simply
enroll them based on the income information that we have. And finally, we do have a
verification process in place for this program and through this we will be selecting 6% of
the customers who enroll in the program to be randomly selected for income verification.
These folks would go through the process of going to their community action agency,
verifying their income. And this is just a measure in place for us to really maintain the
integrity of the program and sort of monitor how effective the income attestation or the
self-attestation of income is going.
Kelsey Solberg: Thanks Tamara. Past due balances are the other piece of this puzzle
that we're trying to address. I shared this to give you all a sense of the landscape of past
due balances in Washington. These numbers are as of the end of December, but we have
just over 29,000 customers who have past due balances. All of those together, totaling
$6.3 million and the average past due balance is $216. So, this is clearly something that
we are wanting to address and support our customers in getting on top of these past due
balances. If we go to the next slide.
Kelsey Solberg: This really demonstrates the need, and this is how we are meeting that
need or how we're addressing it. We have two different programs that fall under the
umbrella of arrearage assistance. Again, arrearage being of a word for past due balance,
and these programs are designed to meet customers in two different situations. We have
our arrearage forgiveness program and this is for our customers with the greatest need.
To give you an example, in Spokane County, if we had a household of four, they would

Appendix A
be needing to make less than $15,000 a year to qualify for the average forgiveness
program. So, like I said, really for our customers with a great need. Those customers can
have their balance actually forgiven up to a certain dollar amount. For other customers
whose income is slightly higher, we offer what's called an arrearage management
program. This is essentially a payment plan that our customers can enter into with Avista,
where over the course of 12 months they will pay 10% of their past due balance and
Avista will credit 90% and that's under the assumption that the customer is making regular
on time payments and that they're also paying off their new or their current charges as
well. This is really a great opportunity for a customer who maybe had a situation happen
where they built up a past due balance, but now they're in a better spot, more consistent
income, and they're ready to address that in partnership with us. Those are the two
programs that we have that are administered in partnership with our community action
agencies.
Kelsey Solberg: This is a quick, very high-level view. We have a lot of data within each
of these bullets around our active participants. The discount percentage they're receiving.
The counties? They're in in the service territory that we serve and a lot more, but really
just to give you a sense of how many folks are active in our program. In the bill discount
program, we have a little over 28,000 participants active as of now. The next slide will
show and we won't jump there quite yet, but the next slide will show a little bit more about
what that number means for us putting it in context. We have 662 participants active in
our arrearage management program, so they're currently enrolled, they're working to pay
down that balance over the course of that year. From the launch of this program in
October, just in three months, we've provided 351 customers with arrearage forgiveness.
So just chipping away at those past due balances and then if we go to that next slide
there, Tamara. Like I mentioned, giving those numbers a little bit more context, this shows
you the percentage of customers who are receiving assistance out of those that are
eligible.
Kelsey Solberg: This is our saturation rate for our LIRAP programs here. You'll see we
have just under 130,000 customers in Washington that are estimated to be eligible. Their
income is estimated to qualify them for these programs and right now within three months
of the program we have 24% of those customers enrolled. And just to give you a sense
of comparing that to past years pre COVID, so 2017 to 2019 over the course of three
years, that average was about 15%. Just to show that this percentage or saturation rate
has increased significantly and in line with CETA we're pursuing a 60% saturation rate by
2030 and then a 90% saturated by 2050. That number of eligible customers will also
continue to rise based on what we're seeing already. We'll continue to be pursuing that
increased saturation rate, but a lot of our outreach is really focused around increasing
that 24% and reaching those customers.
Kelsey Solberg: Finally, just to highlight some of the pieces that we've put in place in
terms of equity as we've been designing this program. I picked four major ones. The first
one being the removal of barriers with self-attestation. This is something I touched on

Appendix A
earlier, but before this was in place, customers did have to make that appointment. If
English was not their first language, they might have had to bring a translator. Some of
them have their children translating for them. Some people would have to get childcare,
find transportation, but now they can simply just apply online. They can apply over the
phone. We have customer service reps who are experts in this bill assistance program
and have been really wonderful in enrolling our customers. They have access to
translation services as well. They can help those customers who might not speak English,
get enrolled, and customers can also still go to their community action agencies. But there
are several other options for them. We feel like this is a been a huge measure and creating
more access to this program, the discount percentages as I mentioned before, these are
designed specifically to address energy burden and the percentages are higher for folks
who have lower income.
Kelsey Solberg: Annette touched a lot on what's the difference between equity and
equality. If we're going for equality, we'd give everyone the same percentage, but we're
going after equity. So, we're saying based on your income and the discount tier that you
fall in, will address your specific situation. We're really trying to create more equity in the
discount percentage that folks are receiving so that their energy burden is being reduced
proportionately to their situation.
Kelsey Solberg: Tamara touched a little bit on multilingual, this is a company-wide
initiative that we're pursuing. We've done a lot within this program to have resources
available on our website for non-English speakers and we have several more languages
available in some of our print material. We've been intentional about having flyers and
applications available in at least five different languages as a start for us in this way.
Finally, increasing readability. This is something that we've been cognizant of pursuing a
6t" grade reading level for all of our bill assistance content. We actually worked with some
customers to get feedback on our website. We made things a little bit less jargony. We
took out some acronyms and really just made it as accessible as possible so that people
could easily apply and access the program.
Kelsey Solberg: So that is our affordability initiative. Glad to be passing it on here to
Kristine Meyer and Ana Matthews, who are going to talk about the purpose and the early
impacts of our Named Communities Investment Fund.
Kristine Meyer: Next, Kelsey, I was thinking about this looking at us being at the three-
hour mark and driving across the state, would we be at Vantage yet? I think probably.
Goodnight, 3 hours, you guys are troopers. My name is Kristine and I'm the Executive
Director of our foundation and also managing alongside Ana Matthews, our Senior Energy
Efficiency Program Manager, together we are managing the Named Community
Investment Fund. We'll tell you a little bit about that today. Tamara, are you advancing
our slides for us? If you'd go ahead and get us there.
Kristine Meyer: OK, so the Named Community Investment Fund, we talked a little bit
earlier today about the Named Communities, but here they are represented

Appendix A
geographically. These are communities that are defined by the [Washington] State's
Department of Health and in the sense Eastern Washington, where we're situated. We're
looking at about 142 census tracks that are targeted for investment of these dollars within
our Eastern Washington Service Territory. Go ahead and advance the slide.
Kristine Meyer: The $5 million, where does that come from? This funding is equal to
about 1% or approximately $5 million. 1% of our electric revenues annually. We divide
this up into five different buckets. You'll see on the right there. Put on your glasses so you
can see the font, but it's divided into $2 million for energy efficiency programs or
investments, and then the other aggregates to $3 million that go into investments in
distribution resiliency, things like solar investments, battery backups, things like that. And
the other is about $2 million in other kinds of projects. Remember that Tamara mentioned
$500,000 of that are in projects that were identified for focus from our Equity Advisory
Group. Things like investment in tree canopy that reduces heat island impacts, third party
investments, outreach and engagement so that we can share with folks in Named
Communities. The opportunities to submit applications for these dollars and to explain the
Named Community Investment Fund and CETA and those kinds of things to raise
awareness, go ahead and advance the slide please, Ana.
Kristine Meyer: Wait, you're on mute.
Ana Matthews: Thank you. On this slide, I'm addressing one of the five buckets that
Kristine covered on the previous page and that's the focus on energy efficiency, energy
efficiency, energy efficiency, because it's comprised of programs that directly benefit
customers. And as a cost-effective method for achieving clean energy goals, the cleanest
energy is the energy that we never use. Helping our customers to use energy safely and
efficiently is the strategy of this portion of the Named Communities Fund. The energy
efficiency portion of the Named Communities has five separate categories. Similar to the
energy efficiency for the Named Communities Investment Fund, overall energy efficiency
has five distinct categories and the first and most importantly includes a commitment to
public engagement through community identified projects. And Kristine talked a little bit
about this, but this is the area where we've dedicated a portion of the funds to be utilized
or identified by the Equity Advisory Group to identify the initiatives within Named
Communities that are specific to energy efficiency.
Ana Matthews: What's really interesting is through a results-based activity process with
the Equity Advisory Group, they identified energy efficiency initiatives that closely align
with the specific energy efficiency actions that we've identified in our Clean Energy
Implementation Plan. You can see the influence of our Equity Advisory Group, that is a
huge component of that public participation process throughout our Clean Energy
Implementation Plan as well as our commitment for what we're striving to do under the
Named Communities Investment Fund for energy efficiency and the areas that group
identified for concentrated attention. This includes the implementation of programs for
multifamily complexes, and health and safety for manufactured and mobile homes. As we
know, those folks have a lot to deal with in terms of maintaining the efficiency in their

Appendix A
homes and we want to make a difference for them with specific emphasis on health and
safety, weatherization for single family homes. What we can do to contain drafts in the
wintertime so that investment that folks are making to heat their home isn't just going out
the window. And focus on small businesses because we know that small businesses,
they're mighty and they are doing a lot for the economy of our communities and can use
all the help that they can and doing some energy efficiency initiatives or practices for them
can really make a difference in their cost. This group also identified specific focus for
tribes. We talked a little bit previously about the grid resiliency project that Spokane Tribe
has undertaken. And there's an energy efficiency component to that project as well. And
then, as Kristine mentioned, they have identified tree canopy which we know may have
an energy efficiency benefit when the right tree is placed in the right place. Next slide
please.
Ana Matthews: The biggest thing I want to impart to you about this slide is our
commitment to leveraging all available methods for raising awareness amongst interested
parties about the availability of these funds. We want to engage those parties so that they
can bring forth proposals, recommendations, ideas for how we can make a difference for
those that we're going to serve through the Named Communities Investment Fund with
assurances that the transformation is equitable for all, to establish a variety of avenues
for interested parties to share their ideas and proposals. We first started with an online
application. It's simple to complete but assures that applicants consider all components
of the project to assure alignment with the Clean Energy Transformation Act. This isn't
usual projects that we're doing for general operations or any other initiative, it has to have
a specific alignment with clean energy transformation. And what we're striving to achieve
through a Customer Benefit Indicators additionally through our outreach program.
Ana Matthews: We have a robust outreach program at Avista. We've been in
communities, gosh, for over 20 years now working with a variety of nonprofits to get the
word out about all of our different programs. We have regional business managers that
work with different government entities. And we have account executives that work with
our business customer base. With all of those connections that we have in the community,
we're leveraging those connections. We spread the word. We put the word out amongst
all of those parties and then we're really dedicated to having an avenue open for those
that are interested. They might have not engaged with Avista on any other initiative or
activity before, but we want them to know that if they do have something that's going to
help us achieve our clean energy initiatives that we'd like to hear their ideas or their
proposal. We're looking to make sure that folks are aware of the funds. There's a variety
of ways that they can make the proposal or share their interest, and then we're even
reaching out to those organizations that may not have heard about it or may not even
know that they could be interested in it.
Ana Matthews: So, as an example and what Kelsey was talking about, as we start to
learn more about who's participating in the bill discount, we might see that there's a
specific demographic group that's not represented in the participant pool. So, we'll

Appendix A
probably approach an entity that's representative of that group and have discussions
about how we could inspire participation amongst that target demographic and if needed,
we could utilize the Named Communities Investment Fund to support them and engaging
those individuals for that company benefit. Additionally, just to make sure that folks are
aware of the benefit of the program, but then also how do they access it? We'll be hosting
informational sessions either virtually or in person, and so virtually you know that just
gives us an ability to cast a wide net to touch a lot of people from the comfort of their own
office or home, but then in person too. We're willing to go out, have conversations with
unique and specific organizations to make sure that they understand about the Named
Communities Investment Fund and how to access that benefit. Next slide please.
Ana Matthews: With everything that's been shared, we wanted to provide you with the
basics of the process. Not a comprehensive overview of the complex processes that we
must undertake to ensure benefits for all customers while weighing equity considerations.
This slide is simply to illustrate the whole named communities process and so with that it
shows the avenues for access to an arrow in the middle that represents the complex
vetting process that ensures accountability for funding selection to the equitable
outcomes. And I just want to spend some time on that big arrow because it captures an
abundance of actions from the receipt of the proposal to assure that submitting entity was
supported through the process to the preliminary and subsequent screening activities that
are across the board within our organization and externally. So that we're getting inputs
on weighing on the different proposals that came forth to us and that the proposals are in
alignment with our energy clean energy accountabilities as stated in our Clean Energy
Implementation Plan with the assurance for equity and process. And to me, simply stated
equity and process requires a unique consideration for the proposal and the identified
impact for that targeted population.
Ana Matthews: Additionally, we look to leverage any existing programs, grants, or other
funding our resource support opportunities. If there's a grant out solely funding a project,
if there's another grant out there, or maybe we can leverage another activity that's going
on in Avista, such as the tribe example that was shared previously, there was a
Department of Commerce grant that we had assisted in writing for the grant. We're
bringing in the Named Communities Investment Fund for any gaps and implementing that
project. And then we just really want to ensure the prudent use of the funds with the
positive benefit to the target population. Now I'm going to turn it over to Kristine. Who's
going to cover the considerations that we have in that big arrow section.
Kristine Meyer: Thanks Anna. So, the big arrow that was in Anna's previous slide blows
out to show you that there are so many different considerations that we're looking at,
many different lenses in consideration to assure that equity is accomplished as one of the
many different things that we're looking at when we're reviewing a proposal. There's the
equity lens, and I won't read this, I'll let you guys spend some time on this and encourage
you to come back to this slide later when you have a little bit of time, but we're looking at
the features of equity in the first in the first box there, affordability and access to clean

Appendix A
energy and those different features there. But then you'll remember that under equity in
those earlier slides that you've seen several times that there are 13 different CBIs or
Customer Benefit Indicators and a couple of those match up to each of the features of
equity under affordability. Remember that CBIs one and two match up to affordability.
Participation in programs and the number of households with a high energy burden going
down, public health matches up to CBIs, number 13 matches up to indoor air quality and
so on. And then in the third box, we're also looking at the implementation plan and specific
actions there. We're looking at whether or not a proposal has a community identified
project. Does it match up and have impact to single family weatherization? Maybe it might
match up to a small business energy assistance benefit. Does it look at whether or not it
impacts single family weatherization? And then finally, we're looking at Equity Advisory
Group initiatives. Does the project have an increased tree canopy feature to it? Might it
have some matching funds for energy efficiency grant applications? And I'll talk to this in
a different way as well. Not every proposal hits on every single one of these features, but
we're looking to maximize these things in each proposal. To the extent that they can, so
the strongest proposals hit on as many of these as they can and do so in a way that
maximizes and leverages the resources that we have to be able to do this. We have $5
million to use to accomplish as much as we can through these lenses.
Kristine Meyer: If you can imagine trying to maximize the benefits while minimizing the
dollars utilized so that we can stretch them as far as we can to accomplish as much as
we can. That's what we're trying to do. As we look at each of these proposals that comes
through that process to ensure that equity is accomplished, as far as we can across those
Named Communities. Next slide.
Ana Matthews: This slide captures all of the projects that were funded in 2023 for both
the community and energy efficiency categories and in some cases, we had combined
funding. As you can see, energy efficiency projects are in alignment with the categories I
shared from the previous page, from audits for the Spokane Tribe to identify where energy
efficiency improvements can be made at the facilities on the reservation to projects that
help contain drafts for those residing in mobile and manufactured homes, to
improvements for heating and cooling in affordable housing complex, to lighting for a
facility at a rural community. And then a full renovation at a pantry up in Stevens County.
These eight different projects to accomplish under energy efficiency we know will make
specific impact and change for the customers in the organizations that were serve. At a
minimum, these projects directly support our Customer Benefit Indicators of reducing the
energy burden, increasing participation in Company programs, and investments of
Named Communities, along with other benefit outputs that we haven't yet identified. Next,
Kristine will take over the community and combined section of what we've given out in
2023.
Kristine Meyer: Now, take a look at the next groups of projects in the green boxes and
the orange boxes. Last year, we also made some investments in these kinds of things.
The tree canopy, as an example in the green section, we made an investment in the City

Appendix A
of Spokane Parks and Recreation Department by helping them to purchase some tree
plotter software. This is software that uses GIS technology to consider planting the right
kinds of trees in the right kinds of places to minimize the impacts of heat islands so that
they are stretching their dollars in plantings that will maximize the impacts to reduce heat
effects in some of those neighborhoods and communities where those impacts are most
detrimental. At the MLK Center, we helped by leveraging some dollars from Commerce
and the federal government along with the Named Community investment monies to
make an investment in some solar panels, some battery backup and improvements in
their energy efficiency envelope to make that facility available when there are outages, to
improve resiliency in that community. And that facility becomes a refuge when power
outages might take place, as well as to improve the energy consumption in that facility to
reduce the energy burden for that nonprofit organization. One of the things that you'll look
at and see in the orange boxes and investment Ana mentioned earlier in the Kettle Falls
Community Chest, that's a rural food pantry that we made some investments to improve
their energy efficiency and reduce the burden there in their operations with their HVAC
system. We also used some of the money from the Named Community Investment Fund
to set up our online application to improve the accessibility to these dollars for folks to be
able to submit their online applications and make them easier to access. We'll turn it over
to James and the marathon continues.
Equity Planning in the IRP, James Gall
James Gall: The marathon is almost over. We're going to end at noon, and I believe we
have one last presentation by me, and I'm going to try to bring that up. We're going to get
into more of the nuts and bolts of how equity impacts our Integrated Resource Plan. Let
me pause here so I can find my slides. I think it's this one. All right, hopefully everybody
can see that.
Lori Hermanson: I can see it.
James Gall: It's a good sign. The goal here is to take everything we've learned this
morning on what the company is doing from programs to Customer Benefit Indicators to
how we want to incorporate equity. But how do we actually do it in the IRP? What are the
steps that we are actually doing, and should we make any changes? Is this more of an
informative exercise? Those are the two different goals here. An IRP is really looking at
how do we serve customer's power supply needs. That could be from energy efficiency,
that could be from generation sources. But I want to touch on how that all works together.
So, we're going to talk about energy efficiency and the Named Community Fund. There
is an aspect of the Named Community Fund in the IRP. We'll talk about how Customer
Benefit Indicators again are worked in non-energy impacts, social cost of greenhouse
gas, and the last topic we'll get into is a maximum customer benefit scenario.
James Gall: Let's get going so we can get done by noon. For energy efficiency, when we
look at modeling, energy efficiency or how we select it. We actually split energy efficiency

Appendix A
into two categories. We have a low-income category and a non-low-income category. The
low-income categories get what we call higher net energy impacts. So, when we look at
energy efficiency programs we calculate a non-energy impact, but if it's a low-income
customer, there's usually a different impact. That's non-energy compared to those that
are higher incomes. What that tends to do is the model will choose based on that
economic advantage, more low-income programs than say a non-low income program,
even if the cost is the same from the utility perspective. The non-energy impact will move
the selection to more of those programs.
James Gall: This next IRP, we are going to be trying, rather than just using low income,
but we're going to look into a Named Community potential rather than a low-income
potential. And what I mean by that is instead of looking at only income, we're going to try
to parse out the energy efficiency potential by which customers are in those Named
Communities from that map we had showed earlier. Again, how this impacts our plan is
we're trying to select greater amounts of energy efficiency to serve customers in a more
equitable way. At the end of the day, if we didn't make these specific changes, we would
have lower energy efficiency targets in our plan. But with these changes it does increase
the amount of energy efficiency that is selected. Feel free to raise your hand if you have
any questions or comments throughout the slides.
James Gall: The next aspect is the Named Community Investment Fund. We are trying
to model potential impacts of projects that will be selected by the team as projects are
submitted. I don't know exactly what community organization will ask for dollars for solar
or for energy efficiency. What we do to incorporate that in the plan is we select proxy
resources. For example, we have a target in our model to spend an initial $2 million on
energy efficiency. That may not be cost effective and what that does is that increases our
energy efficiency target as well, but it shows that we're actually looking for programs that
are beyond our required targets. We also put in our model around $400,000 that was an
estimate of how much of that program money might be spent on solar or wind in our IRP,
or sorry, not solar, wind, solar or storage. That number could change, but that caused the
model to actually select the most cost effective solar or storage system to incorporate the
likelihood of that types of programs will be in the future so that we're accounting for that
energy benefit.
James Gall: For example, if we remind ourselves back on that storage slide, I showed
earlier about how much additional storage was going to be added into the plan, though,
that's storage selection due to this change in our modeling it without this Named
Community Fund. Without these criteria selected, there wouldn't be any distributed solar
selected in the plan. Because of that economic reason, it it'd be more cost effective to
select if we needed storage. It's going to be more cost effective to do utility scale storage
rather than distributed, so this helps take into account when the model is trying to choose
which resources are most economic. It's a way to leverage or push the model towards
specific outcomes.

Appendix A
James Gall: And then non-energy impacts. There's always this issue of, it goes back to
Customer Benefit Indicators. But how do you prioritize one Customer Benefit Indicator
over another? The approach we took is using non-energy impacts where we're trying to
actually quantify the societal or indirect impacts of our choices. If a resource has an impact
of air emissions, we want to quantify what that error, that impact, is and if the result ends
up being that area, emissions are going to increase. We've included that outcome in our
analysis. For example, we actually saw that event in the Northwest IRP where we saw,
not a substantial reduction in NOx emissions because our model was selecting a power
to gas ammonia turbine to serve load. Serving load is very important. Reducing air
emissions is also important, but you set what is the cost to serve that load and weigh that
against air emissions. Based on the economics of that non-energy impact of that air
emissions, it was better to select a resource that had slightly higher air missions than one
that did not. Because otherwise we would not be able to serve load in the future to come
up with these cost impacts.
James Gall: We lean on a study that we got from DNV, a national consulting firm. They've
attempted to look at non-energy impacts for different resource options and they try to
quantify them when they're known, but there is let's say this is a study, or a field of study,
that's continuously evolving. It's also not a skill set that's in a typical utility. And in order
to do more or progress in the non-energy impact field, we have to hire consultants which
cost money, which means that it leads to down the road higher rates. We need to balance
how much do we want to spend on calculating non-energy impacts versus the cost to
identify it and what the actual impact will be for the company. For this IRP, we're going to
stick with the previous study. And then if we need to move to a separate study in the
future or enhanced study, we're going to have to figure out the most efficient way to pay
for that work. Again, what this will do from a planning perspective is it will actually change
resource selection when you look at evaluating tradeoffs, including a benefit or a cost of
a resource will change the outcome. If that cost or benefit is large enough to change the
result. Yes, Sofya, go ahead.
Sofya Atitsogbe (UTC): James. Thank you. Maybe it would be a good time now to hear
some thoughts from everyone present?Well, not everyone. Everyone who wants to speak
on the quantification of non-energy impacts and their attitude towards it and the
importance they see in Avista's IRP process for the non-energy impacts.
James Gall: Yep, happy to hear anything. I mean, if there's thoughts at the UTC, I just
want to remind folks though, the last CEIP where we're required, where we agreed to
include them, it would be good to know if we should continue this concept or pause or
change like Sofya.
Sofya Atitsogbe (UTC): Not everyone. All at once. OK. Well, I suppose that is something
that the UTC staff would like to hear other people's opinions on. I'll just keep it in the back
of my mind. Thank you.

Appendix A
James Gall: Thanks Sofya, for bringing that up. Feel free to reach out afterward if you're
not comfortable on this call, but you know we will be doing more collaboration in this IRP
and that may lead to something in the CEIP that comes later. That's the Clean Energy
Implementation Plan. A lot of the discussions on methodology of Customer Benefit
Indicators, or how we use non-energy impacts, that comes up in that process too. There
will be other opportunities to think about this situation. Also, I wanted to get into some of
the non-energy impacts that we are including. We have two categories, both on supply
side and demand side and in this area work really started on the demand side where we
were asked to include impacts to income or public health, property values and energy
burden. And then we got the thinking, you know, these impacts are not just to demand
side or energy efficiency programs, they are actually impacts to the supply side. To be
selecting resources on an equal footing, we conducted this study on the supply side for
the last IRP and the focus was really on public health. What is the financial or economic
impact of air emissions? We had PM 2.5 was quantified, S02 and NOx. We looked at
safety and what is the probability of an incident to workers or people around the facility,
and an economic value of those fatalities or injuries. We looked at environmental impacts
and this one was, I would argue, a little bit more qualitative because when you're
impacting land, for example for a wind farm, you are paying for the land that's part of our
energy cost. But you could argue there is a visual impact, but how do you quantify that?
This is something that's kind of hard to do when, which is why I said maybe this is
something we have to continue to study over time. Land use and water use are all things
that we pay for when we build a resource, but may have an impact that isn't quantifiable.
James Gall: So those were qualified impacts economic what we looked at is when we
invest in resources and capital costs there's construction costs, there's operating costs,
and that leads to economic benefit to the Community, whether it's property tax benefits,
it could be employment benefits. We try to include values to society around these facilities
that we add to the system. If you have a resource, for example, that has more employees
than another resource that will have a bigger economic impact to the community. Those
are things that we were including and this plan.
James Gall: I wanted to talk briefly about how we can utilize equity when we acquire
resources. I mentioned earlier that we talked a little bit about the RFP process. In an IRP
we select resource needs, but that's not necessarily the specific resource we're going to
acquire. We go to an open bidding process where developers have resources and can
submit proposals. Avista could submit proposals and we evaluate them through a specific
process and the Commission in Washington has a specific process that we follow to select
resources and the resources that are going to be bid to us. They also have a process to
get a permit, so it's a very rigorous public process. So, when a developer wants to build
a wind farm, they have to get a conditional use permit, which requires them to do studies
on how it impacts wildlife, how it impacts the community, and there is a time for the public
to be part of that process. There are definitely many layers to engagement with customers
or with citizens. When we select resources, part of it is on the developer of the resource
and part of it also comes in when we evaluate those alternatives. For starters, those NEls

Appendix A
or non-energy impacts we talked about on the previous slide, we do include those when
we select resources for serving load in Washington. And in addition to that, we have six
different categories that we evaluate resources on the first one and the highest rating
category.
James Gall: This slide is the topic, the percentage of how much we grade the proposals
on, and then in the parentheses is some additional things we're looking at, customer
energy impact. What we're talking about is 40% of our evaluation of a resource is the cost
of that resource. Obviously, we're looking for the lowest cost resource, but given that's
only 40% of the weighting factor that we selected when looking at resources. We also
look at risk management. That is when we look at the ability of that company to construct
a resource, how solvent are they. We're really looking at can they deliver on the project
they say they can and at the cost. They say they can, so that's about 20% of the other
grading. 5% is with price risk and that has to do with when they propose a project is the
price fixed or is it variable. So, if you had a project that is fixed, that's going to be the same
price for energy today, tomorrow, and the next day. That would get say 100% credit. But
if you had a price that is based on the CPI or some other unknown metric, then we would
assign a risk factor to that because we're not sure what price we're going to be paying for
the energy. The 4t" category is electric factors. This really has to do with deliverability and
technology risks and what I mean by that is, let's say there's a project in central
Washington. They have the ability to build it, they have the land, they have the permits,
but they can connect it to the grid. The power cannot get from the location of the facility
to Avista's customers. The delivery risk or delivery impact, that's something we include.
Also, technology. What if it's a new technology? Avista typically is not looking for high risk
projects where we could be, we call it serial number one, where we're taking more of an
R&D perspective. We're trying to actually serve customer load, so we are definitely
looking at is a technology viable, their experience with the technology, and that's included
in the evaluation.
James Gall: The last item has to do with non-energy impacts that are qualitative. This
has to do with community involvement, Named Community impacts location. I think
location was mentioned earlier where if a facility is in our service territory or connected to
our system, we would give it extra credit. That's what we're talking about here. We're
looking at local labor force use, and then supplier and owner diversity. That's 5% of the
weighting. So, when our IRP comes out and we have a resource need identified, let's just
pretend we have a resource need for a new wind project in 2029, for example. About two
or three years ahead of that time, which would be a couple years from now, we would
issue an RFP. And, we would be looking for solar or other alternatives. Just because the
IRP selected a specific resource, we're not going to limit it to that resource. We're looking
for something that can deliver those characteristics of, say, clean energy in that time
frame. And then we would evaluate those options using this criteria. At least this is the
criteria we used in our last evaluation process. The IRP is not the end of equity
considerations in the selection process.

Appendix A
James Gall: The last thing, and I think this is my last slide, is we are required by the UTC
to conduct what's called a maximum customer benefit scenario. In this scenario we're
required to conduct, we're looking at what resource strategy changes would we make if
we're trying to maximize customer benefits. Unfortunately, there's no definition or specific
requirements of what the scenario must entail. So, it's really up to Avista and our TAC to
come up with ideas on how we meet this requirement. Last IRP, what we did to meet this
requirement is we called on our model to still find the lowest cost solution. But we're going
to change the resource options available to the model, so some of the changes we made
is the model could only pick in-state generation resources for renewables, which meant
no Montana options. We told the model it could not select ammonia gas to power turbines
because they have air emissions. So, if we were trying to maximize all of our Customer
Benefit Indicators, we do see air missions would be one of those. Ammonia gas to power
turbines, they have a small amount of NOx emissions and if you're trying to eliminate NOx
emissions that would not be a resource you would select. So, we remove those fuel cells
using hydrogen. We still allowed those lowering excess energy burden via community
solar was a priority in this analysis. So, in their preferred strategy we would argue that to
lower customer burden that we showed earlier would be met through energy assistance
that Kelsey went through. But another way to do that is if we built community solar that
was maybe paid for by some funding mechanism that would offset those customer bills.
We would have more distributed energy resources potentially and then we would use that
money towards low-income customers. So, the model was biased against selecting more
of those resources.
James Gall: The last thing we included, which I think is maybe debatable, but no nuclear
energy. It was an option that we talked about including. I think maybe we should talk
about that one for this scenario. Is that really a benefit or not a benefit to maximizing
customer benefits? I don't know if that is or is not, but that was something we assumed
last time. With the few minutes we have left, I'm just curious if we think this is the right
track. Should we want to make changes to this? Are we not thinking about something that
was maybe intended? Should there be changes? We are open to ideas and nothing's
wrong, nothing's right here, but any thoughts? It's OK if you don't. What we'll probably do.
Got a hand up our Heather's got one. Thank you. Go ahead.
Heather Moline (UTC): Thank you. Staff will be following up on a few things that came
up today. Some of this I think is moving a little too quickly for folks to be able to chew on
and offer targeted feedback during this TAC meeting. I might think we want to discuss if
you're, and this is not just Avista, if there's going to be as much content as there was
today discussed in a room like this, we need two separate meetings. Just so there's at
least a 10 second pause after every slide for folks to be able to chew on what they just
heard. Luckily, Staff is a little more versed in this stuff than maybe other folks are, who
don't do this for their day job. I think we do have some feedback, but we'll send it as a
follow up in writing because I know that's helpful to you all. But I wanted to go back to
slides 7, if that's OK., just that so resource acquisition, equity considerations, this is very
creative to me. Thinking of these things as NEls in the context of resource acquisition,

Appendix A
because I'm used to thinking of NEls only in the context of procuring, well, not procuring
in planning, resource planning.
Heather Moline (UTC): So very cool. Going to chew on this. I'm not sure that I would say
that all of these are equity related though. The first bullet, customer energy impact, that
we would only say that's related to equity if it's considering whose bill is higher and whose
bill is low or who has the ability to pay as opposed to keep costs low for everyone. Anyway,
all that is just food for thought at this point.
James Gall: Some of that Heather, and we can talk about this when we talk offline, but
some of that even though the non-energy impacts is 5%, some of those other equity
conditions are embedded throughout. We just didn't call them out specifically. For
instance, in your customer energy impact we asked the question is your project located
in a Named Community and then it's score it receives a higher or lower score depending
on if that's a yes or no because the thought there is that it would impact cost. I'm just
picking this as an example, but it would impact cost and energy burden depending on
whether it benefited those customers or not. I think we should probably have a follow up
conversation on that also because during the RFP process itself that was a little bit of
confusion, and it was hard for staff and others to compare us then to Puget because of
that reason it's kind of embedded there. So, happy to happy to talk about that again.
Heather, you mentioned something that's probably critical to how this TAC process works.
We send slides out ahead of time to give people time to look at it. We talked about it here,
but it sounds like maybe we need a third step in that. Do we maybe follow up emails, do
we have another TAC meeting. Part B, a week later that's 1/2 hour for people to provide
comment. That's a new concept to me I wanted to explore a little bit in the three minutes
we have left. I would also because I feel a lot of times when I'm talking about equity that
I'm talking at you all and I am aware of that and I don't know the answer, but I feel like
you do, Heather. I don't know if this should be pre work or if this should be, I don't know
exactly, but I do agree that this is a lot to digest and then to provide feedback. We're open
to suggestions.
Heather Moline: I don't know the answer in that. I'm figuring this out with you all. I
appreciate that, though. No, we'll confer internally. Staff has been thinking about
guidelines on conducting TACs and the only thing that occurs to me in this moment is
when the information is fresh. It's good to provide different venues for input, so staff
obviously will have the capacity to read through slides and provide written comment either
before or after. But for folks who may not have time to do that, leaving a blank space after
sharing dense information for folks to just chew on, it seems to me to be a best practice,
which again, I recognize that you all have to get through all this information. You want
feedback on it, but to me the way to solve that would be less information and more
meetings. I don't know if that's right, but that just occurs to me as a solution about how to
make sure there's space and that is accessible to people.
James Gall: OK, I'm going to throw out an idea. I'm not going to commit to it, but it's
something we've tried, and maybe it helps, we've recorded the presentations before

Appendix A
ahead of time and made them available. And then people could listen to them at their
pleasure. And then we have the meeting to discuss high level topics. I think that works if
people spend the time listening to the presentation, but if they don't then it may be a waste
of time, but that's another approach. We look forward to that discussion. We do have
more TAC meetings coming. We have our next electric one on March 21 st. It's a half-day
session like this. That meeting will definitely be a lot more technical than this meeting,
and then we have a natural gas TAC meeting on February 14t" as well. For those of you
that are interested. I don't know if there's any last questions or thoughts before we go.
OK. Well, I thank you for your time and input and we'll see you at our next meeting. Again,
feel free to email us and or give us a call and we'll figure something out. Thanks. Have a
good day.

A endix A
Vop
2025 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 3 Agenda
Tuesday, March 21, 2024
Virtual Meeting — 8:30 am to 10:00 am PTZ
Topic Staff
Introductions John Lyons
Review of January Cold Weather Event James Gall
Wholesale Price Forecasts — Natural Gas and Electric Planning Team
Portfolio and Market Scenarios Options James Gall

���r r/ISTA
2025 IRP TAC 3 Introductions
John Lyons, Ph.D.
Technical Advisory Committee Meeting No. 3
March 21 , 2024

Appendix A
Today's Agenda
Introductions, John Lyons
Review of January Cold Weather Event, James Gall
Wholesale Price Forecasts — Natural Gas and Electric, Planning Team
Portfolio and Market Scenarios Options, James Gall
2

Appendix A
Remaining 2025 Electric IRP TAC Schedule
• TAC 4: April 9, 2024: 8:30 to 10:00 (PTZ)
o Future Climate Analysis
o Economic Forecast & Five-Year Load Forecast
• TAC 5: April 23, 2024: 8:30 to 10:00 (PTZ)
o Long Run Load Forecast (AEG)
o Review Planned Scenario Analysis
• TAC 6: May 7, 2024: 8:30 to 10:00 (PTZ)
o Conservation Potential Assessment (AEG)
o Demand Response Potential Assessment (AEG)
• TAC 7: May 21 , 2024: 8:30 to 10:00 (PTZ)
o Variable Energy Resource Study
o Portfolio/Market Scenarios
• TAC 8: June 4, 2024: 8:30 to 10:00 (PTZ)
o Load & Resource Balance and Methodology
o Loss of Load Probability Study
o New Resources Options Costs and Assumptions

Appendix A
Remaining 2025 Electric IRP TAC Schedule
• TAC 9: June 18, 2024: 8:30 to 10:00 (PTZ)
o IRP Generation Option Transmission Planning Studies
o Distribution System Planning within the IRP & DPAG update
• Technical Modeling Workshop: June 25, 2024: 9:00 am to 12:OOpm (PTZ)
o PRiSM Model Tour
o ARAM Model Tour
o New Resource Cost Model
• TAC 10: July 16, 2024: 8:30 to 10:00 (PTZ)
o Preferred Resource Strategy Results
o Washington Customer Benefit Indicator Impacts
o Resiliency Metrics
• TAC 11 : July 30, 2024: 8:30 to 10:00 (PTZ)
o Preferred Resource Strategy Results
o Portfolio Scenario Analysis
o LOLP Study Results

Appendix A
Remaining 2025 Electric IRP TAC Schedule
• TAC 12: August 13, 2024: 8:30 to 10:00 (PTZ)
o Preferred Resource Strategy Results (continued)
o Portfolio Scenario Analysis (continued)
o LOLP Study Results (continued)
o QF Avoided Cost
• September 2, 2024- Draft IRP Released to TAC.
• Virtual Public Meeting- Natural Gas & Electric IRP (September 2024)
o Recorded presentation
o Daytime comment and question session (12pm to 1 pm- PST)
o Evening comment and question session (6pm to 7pm- PST)

���r r/ISTA
MLK Weekend 202 Weather Event
James Gall, Manager of Integrated Resource Planning
Technical Advisory Committee Meeting No. 3
March 21 , 2024

Appendix A
January 13, 2024 Low Temperatures
4M
o
o� -13
Ild
-9 1S on^ _4l�f - ans -
Rsservatwn
• C m1 '•
ar_y 3 — Post F-i 1 J
pnz-15 _7 -11 -1 -8 °JA13 15
w10
-10 -6 -6 -10 -
4
10 "6 15
—� —V "4 —1 L Pullman FAc�sray -�(� c��p
F-
-11 '
10 3 —2 _4 _ —12
a,t:t�1,128 _4
VVajjz:V_Aj,
5 2 _1 _10 t, F
4 `3. t-,a� J! —8
2

Appendix A
Loads and Resources
2,500 Capacity Required
(Op Reserves/ EIM Load Adjusted for
Flex Up) Curtailed Industrial
Demand
Load sales
N 1 ,500 / % ase ....
Hydro
as -
1 ,000
Wind/Solar
Natural Gas
500
Colstrip
0 - - .
11 12 13 14 15 16 17
3 Day

Appendix A
Gas vs . Electric Demand
Total MMBTU of Daily Demand
500
450
■ Electric
400
■ Curtailed Electric
■ LDC Natural Gas
0 300 F 315 283
250
m 200
150 6
100
50
1/13/2024 12/22/2022 6/30/2021
4 Daily electric MWh multiplied by 3.412

Appendix A
Regional Power Challenges
Some of the WAPA&Southwest imports are NW
resources located out-of region
'Graph shows flows,not power origin:California
Flows into the Northwest was net importing from the Southwest while
also exporting to the Northwest
Imports and exports(NW with 100'„NWMT 8 PACE)
1,000
(11000)
�z -
Resource stack (approximate) (3,000)
r
Northwest (including 100% of NWMT and PACE) ("000)
45,000 42,253 42,919 42,925 (7,000)
1/11/2024 1/12/2024 1/13/2024 1/14/2024 1/15/2024 1/16/2024 1/17/2024
40,000 ■Canada California' ■Southwest ■WAPA
35,000 AN, A& A& I
y EIA form 930 data.Data have been edited to address discrepancies;some discrepancies may still exist.Canada includes interchange with
30,000 &C&AESO;California includes the AC line&power flowing into PACE:Southwest is NEVP&AZPS;WAPA is WAUW&WACM.
3
25,000
20,000
15,000
10,000
5,000
1/11/2024 1/12/2024 1/13/2024 1/14/2024 1/15/2024 1/16/2024 1/17/2024
Nuclear Coal Gas BPA Et GRID other' Solar iiiiiiiiiiiiiiiiiiiiWind r-190ther Imports Hydro— *Demand
"BPA It GRID other"is likely mostly natural gas plants
W 'IM
EIA form 930 da ed to address disCIMM discrepancies may still exist.Incl
PACK PGE,BPAT,SCL, TWPR,PSEI, CHPD,DOPD,GCPD,AVA,AVRN,IPCO,NWMT, WWA,GWA,plus the BPA import portion of GRID.

Appendix A
Potential Resource Adequacy Changes
✓ Update load forecast dataset to include new event.
✓ EIM Uncertainty Flex Ramp Up will be additional planning requirement.
✓ If planning margin is less than the single largest contingency resource, the
planning margin will be adjusted to this level .
• Should we assume a low water for storage hydro resources QCC?
• Is a lower Loss of Load Probability (5%) target more prudent?
• Can Avista depend on the market in extreme events (330 MW)?
• Should we plan for meeting an extreme day such as this as a minimum
resource adequacy standard vs LOLP method?
6

WES TA
Natural Gas Fundamental Forecast
Wood Mackenzie
2025 — Electric IRP
Technical Advisory Committee Meeting No. 3
March 21 , 2024

Appendix A
Lower 48 Demand
160
■ Residential ■ Commercial Industrial
Blue Hydrogen ■ Power LNG Exports
140 ■ Net Mexican Exports ■ Transport Other
120
100
U
80
60
40
7
20
0
O co (0 0') N � 00 ti CD (0O
� � � � N N N co co co 1;T IZT
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
2
Source:Wood Mackenzie

Appendix A
North American Supply
180 1,000
■Total Oil Rigs ■Total Gas Rigs
160 900
140 800
WCSB
700
120
600
100
Northeast 500
80
400
60 Permian 300
40 200
Gulf of Mexico
20 6*5 Wn Gulf Coast 100
0 Rockies 0
r- O co CO O N LO 00 � O CY) L!7 � O M LO ti CA M Ln t` O
N N N N M M M cr LO N N N N M M M M M NT It � It q�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
N CV N N N N N N N N N N N N N N CV N N CV N N CV N N N N N
3 Source:Wood Mackenzie

Demand woodm ac.com
Natural gas' share of total energy demand increases over time Appendix A
Gas plays a crucial role for energy security even through energy transition
Primary energy demand mix* in North America
• Industrial gas demand maintains steady growth to mid-
` Canada century with rising oil sands production. especially with
the recent approval of a new greenfield oil sands
project.
• Gas intensive industrial projects are attracted to
western Canada with low cost feedgas and potential
decarbonization options such as carbon capture_
• Efforts to match the IRA in policy incentives spell good
news for blue hydrogen and low-carbon industrial
100 projects across both coasts with additional tax credits_
• Gas demand grows at a CAGR of 0.5%between 2023
United States 0 I and 2035, driven primarily by coal retirement in the
■Other solid fuels 2.500 2023 2035 2050 power sector and new industrial projects. Post-2035,
CAGR drops to-0.5%due to energy transition
■Other renewables 2.000 accelerating, such as gas displacement from low-
United carbon hydrogen in the industrial sector and building
■Hydro 1 500 ■ electnfication in the LDC sector.
•States While the IRA is expected to bring substantial build of
■Nuclear renewables, large-scale deployment of renewables
■Coal 1.000
poses potential risk in the brig term on transmission
costs, interconnection costs and negative bidding- This
■Oil 500 helps natural gas demand in the power sector to stay
relatively resilient even out inthe long term.
■Gas 0
2023 2035 2050
'Gas is based on Wood Mackenzie 2023 North America gas straoegic planning outlook Other commodores are based on Wood Mackenzie's 2022 investmety horizon_
Source:Wood Mackenzie Energy Transition Tool
4

Census Reg-Map
West Mitlwest Northeast
Me „, *Appendix'"'AA I a. a.ea
Regional Demand
eee. �� � soua.e
South
9 Pacific 7 Mountain
i Residential ■ Commercial Industrial Blue Hydrogen ■ Power Transport ■ Other ■ Residential ■ Commercial Industrial ■ Blue Hydrogen ■ Power Transport ■ Other
8
6
7
5
6 Oil
or
5 4
U U
4
3
3
2 2
1 1
0
O M (0 O N LO 00 r r— O co CO O
N N N M M M N NT N O
O O O O O O O O O O O O O O O M O O N Ln 00 - r` O co (0 M
N N N N N N N N N N N N N N N N N co co co It It
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
5
Source:Wood Mackenzie

Natural Gas Market Price Forecast
Michael Brutocao, Natural Gas Supply Analyst
Technical Advisory Committee Meeting No. 3
March 21 , 2024

Appendix A
Henry Hub Expected Case Price Forecast
$12 100% Levelized Price: $4.99
• Data Sources
$10 — NYMEX forward market prices on
75% December 15, 2023
Annual Energy Outlook
2023$$
Consultants 1 & 2 monthly price
... ..
A
forecast
:.:.:.:.:.:... . . .
.........................._.._...... _ :. ....
50%
Methodology
. :.:.:.:.:.:.:.:.:.:.:.:.:.:.:.:.:.:.:.:.:.:.:.:.:.:.:.:.:.:.:.:.:.:.:.:.:.:.:.:.:.:.:. .
> `r `f _ — Average price of forecasts
$4 — ecrea n o X
D sing ble d NYME
0
25 0
YMEX N Other
2026 100% 0/o
2
0
00
$- 2027
0% 75% 25%
Cfl ti oo rn o (N CO 't Lr) co r` oo rn o N M Ln 2028 50% 50%
N N N N M C'7 M M M M M M M M Nt It It It Nt
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
�L C= C= C= C= C= i= C= C= C= C= C= C iL C= C C= �L C= C=
2030 - 2045 0% 100%
Nymex EIA/AEO Consultant 1 Consultant 2 Expected Case
2 Annual Energy Outlook 2023 — Natural Gas Spot Price at Henry Hub .

Appendix A
Henry Hub Stochastic Price Forecast
$25 $25
• Stochastic Inputs —
— Expected Case Forecast $20 / � $20
• Data Source:See previous slide
— Autocorrelation (94.16%) $15 / $15
• Data Source: Historical monthly prices at Henry Hub .� 0
Standard Deviation of Errors — .00
• Data Source: Historical daily NYMEX forward market prices $10 / $10
• Data Source: Historical monthly prices at Henry Hub 0000
$5 — _�Z — — — — _ $5
140% OW
100% $- $-
Cfl � 00 M O N CO 'T lf) C0 r— 00 M O N C7 U-)
80% 0 0 0 0 0 0 CO 0 0 0 0 CO 0 CO 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
60%
Min — —Percentile: 25% Input Mean — —Percentile: 95% Max
40%
20%
o% CO
IN� CO
ON OM M NM MM NtM Lr)M (MO Mf­ M0 aM O � Methodology
C) 0 0 0 0 0 0 0 0 0 CD C) N N NN � �N N N N Start from E xpected Case ForecastNNNNNN NNNNNN C C C C C C C C C C C C C C C C C C C C
Perform adjustment for Autocorrelation to prior month
standard Deviation of Errors — Randomly draw from prices with lognormally distributed standard deviation of errors
3 Historical Monthly prices at Henry Hub

Appendix A
All Basins Expected Case Price Forecast
$10 $10
$9 $9
$8 $8
$7 $7
Levelized Prices
$6 $6
$5 i $5 Henry Hub $4.99
$4 $4 AECO $3.58
$3 ' J $3 Sumas $4.31
V
$2 $2 Malin $4.37
$1 $1 Stanfield $4.26
cD I- 00 O') O N CO ct LO (D f` 00 0') O N m 't LO
N N N N m m m m m m m m m m � Nt 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
Henry Hub AECO Sumas Malin Stanfield
4 Data Source: Consultant 2 percent basis price differential to Henry Hub forecast .

�i�iVISTA
Wholesale Electric Market Price Forecast
Lori Hermanson, Senior Resource Analyst
Technical Advisory Committee Meeting No. 3
March 21 , 2024

Appendix A
Market Price Forecast - Purpose
• Estimate "market value" of resource QUEBEC
N TERCONNECTIONS INTERCONNECTION
options for the I RP
• Estimate dispatch of "dispatchable"
resources NPCC '
y
M RO
i
• Informs avoided costs F
WECC
SPP
• May change resource selection if SERC
FRCC
WESTERN
resource production is counter to '- - - - - �
NTERCONNECTION EASTERN
needs of the wholesale market THE INTERCONNECTION
ERCOT ,
INTERCONNECTION
Source: NERC
2

Appendix A
Methodology
• 3rd party software - Aurora by Energy Exemplar
• Electric market fundamentals - production cost model
• Simulates generation dispatch to meet regional load
• Outputs:
— Market prices (electric)
— Regional energy stack
— Transmission usage
— Greenhouse gas emissions and cost
— Power plant margins, generation levels, and fuel costs
— Avista's variable power supply costs
3

Appendix A
Wholesale Mid =C Electric Market Price History
Mid Columbia Electric Prices
$140 (317/2024)
Energy 12Crisis Day Ahead • RT/EIM
S120 117
Forwards
$100 as of
31712024
80 82 78 79
L Natural Gas Market Tightens 64
58 59
C . $60
Cheap 51 49
64)- natural 42 45
Shale Develop me
540 gas, good 38 36
hydro 32 33 32 30
23 23 22 23 23 20 22 7 21
$20 13 191 1 q F" *
♦
s0 AM IbL
I� CO 0') O - (N M ":T Lr) (D f�- CO 0') O - CV CO q�j- Lr) (0 f` 00 0) O - CV C7 � Lr)
0') (3) 07 0 0 0 0 0 0 0 0 0 0 - � = te r = = = = = N N N N N N ,
4 0 0 M 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
CV CV CV CV CV N N N N N N N N N N N N N N N N N N N N N

Appendix A
2023 Fr - - Ivy
Northwest U .S. Western Interconnect
69% GHG Emission Free 47% GHG Emission Free
Wind Solar Petroleum
Nuclear 4% 11% 10% 0%
Wind Other
11% Nuclear 0%
Solar 8%
2%
Hydro Coal
50% Petroleum 15%
0%
Other Hydro
2% 20%
Coal
8%
Natural Gas Natural Gas
23% 36%
Source: EIA
5

Market Indicatorch - Market is TighteningAppendix A
Daily NG vs On-Peak Electric Spark Spread
$50 46.1
$100 O
$90 x $40
$80 v $30 24.446.37
$70 =
L
Q $60 • t' N $20 13.116.5
O 7.95
4} $50 $10 6.137.02 7.24 7.71 6.92 7.83
U $40 • • 4.57 3.89 3.62 4.43 1.30, 4.54 5.164.19
-0 $30 • Y= 8!271 x+ 3.8178 $0 0
R2 = 0.8248 (2.45)
$20 $10
M 'T lf) cO I-- 00 C'> O T­ N M IT u') co I�- O C') O T­ N M
O O O O O O O � � � � � � � T- � N N N N
$10 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
$0
$0 $2 $4 $6 $8 $10 Daily Mid-C Price Standard Deviation -0 ak
Stanfield $ per DTh $70 On Pea
$60
Implied Market Heat Rate
18,000 $50
t
16,000 3: $40
c 14,000 M
$30
X 12,000 Q
<n 10,000 ' tfr $20
0 8,000 , $10
L '
w 6,000
$0
� 4,000 M le to eo ti ao M CD M -e � m r• ao
O O O O O O O O . � � V.. N N
a 2�000 • N N N N N N N N N N N N N N N N N N N N N
0
6 M v W ti W O N M v LO a) � N
O O CD O O O N N N N
CD O CD O O CD O CD CD O CD CD O CD CD O CD CDO O O
N N N N N N N " N N N N N N N N N N N

Electric Greenhouse Gas Emissions Appendix
U .S . Western Interconnect
400
350
N
300
C
0 250
L 200
150
0 100
50
0 1990 1991 1992 1993 1994 1995 1996 1997 19981999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
Change
-3.7 WY 36 35 38 36 39 36 37 36 40 38 40 40 39 39 40 39 39 40 40 38 39 38 40 43 41 40 37 37 37 33 32 31 32
2.2 WA 9 9 11 11 13 10 12 10 13 12 16 16 13 15 15 15 10 13 14 14 14 8 7 13 12 12 10 11 11 15 12 11 11
-3.0 UT 29 28 30 31 32 30 30 31 32 33 33 33 34 35 36 36 37 39 39 37 36 34 32 36 35 34 28 28 29 28 26 30 26
5•8 OR 2 4 5 5 6 3 4 3 7 7 8 9 7 9 9 9 7 11 11 9 10 7 7 9 8 9 8 8 9 11 9 9 8
-16.0 NM 27 23 26 27 28 28 28 29 30 30 31 31 29 31 31 32 32 31 30 31 27 29 27 27 23 23 21 21 16 18 16 15 16
1.4 NV 17 18 19 18 20 18 19 19 21 21 25 24 21 23 25 26 17 17 18 18 17 15 15 16 16 15 15 13 14 14 13 14 14
-2.2 MT 16 17 18 15 18 17 14 16 18 18 17 18 16 19 19 19 19 20 20 17 20 17 16 17 17 18 16 16 15 16 10 13 14
1.8 ID 0 0 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 2 1 2 2 2 2 2 2 3 2
-1•8 CO 32 31 32 32 34 33 35 35 36 36 40 42 42 41 41 41 42 44 42 39 40 40 40 39 38 37 36 36 35 34 29 31 30
-8.2 CA 53 50 58 54 62 50 47 50 53 58 68 72 60 56 60 55 60 63 63 59 55 48 59 57 58 55 47 44 44 41 43 45 44
-0.2 AZ 33 33 36 38 39 33 33 36 39 41 46 47 46 47 53 52 54 56 59 54 56 54 52 55 54 50 45 44 47 44 36 34 33
Source: EIA
Emissions are adjusted for generation within the Western Interconnect
7

Appendix
Modeling Process
3 Capacity Expansion
For
i --
2 Input Changes Add new resource
30 yr. hydro with climate forecast 6 Re-Run Capacity 7 Run Full
1 Vendor 8 Run Scenarios
change 5 TestYear Forecast
Database (Capacity/RPS) 4 Preliminary Expansion
NG prices Stochastic Study Stochastic& Deterministic
2023 North Include known Deterministic Increase/Decrease
( Regional Loads retirements Study Test Resource Planning Margin Deterministic Stochastic(if
American) Adequacy Targets necessary)
Avista Resources/Loads Model adds resources
Operational Detail to meet planning
targets
'a 'TrI/1STAa

Draft WdC t
Load Forecast
Western Interconnect Annual Load
• Regional load forecast from IHS 140.000
— Forecast includes energy efficiency 120,000 ■California/Baja Rockies Canada Southwest ■Northwest
• Add net meter resource forecast 100,000
— Annual input with hourly shape M 80,000 MEM
6 ■ ■ ■ ■ ■
60,000
• Add electric vehicle forecast
— Annual input with hourly shape Q 40,000 ■ ■
20,000
• Future load shape differs from
today's load shape - CO r- CO 0) COCONMCOCOCOCOCOnO CO 'IT LO
N N N N CO CO CO CO CO CO CO CO CO M V � V � � V
CD O O CD CD O O O CDO O O O O O O O O O O
N N N N N N N N CA . . . . N . . N . . N
9

Appendix A
Carbon Pricing Assumptions
Nominal Price per MTCO2e
$350
$300 Used consultant's carbon pricing
• $85.32 levelized carbon price
• Modeling CCA and CA/Quebec as a
$200 OW as sip joint market; assume no national
$150 too, ' carbon price
• Regions importing into CA or WA
.••••i''=' 00 too too----- ,.,,, ....•:. � incur a carbon price adder to transfer
s1 SWffWW------- power
— .
..........•
$50 , r..�• t t� Assumes carbon cost in dispatch for
.................................................................................
$ all resources beginning in 2031
°° M rn " m rn M fn ^ M q* N m � Stochastics — will use 300 random
N N N N N m m m m m m m m M m v g � � �
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 d raws
Min Percentile:25% — —Mean Median Percentile:95% — — Max
10

New Resource Forecast (Western Interconnect) Draffi ecast
350.0
324.2
300.0
262.8
250.0
200.0 192.0
3
150.0 119.5
100.0
50.0 LM il
2030 2035 2040 2045
■H2CCCT 0.3 0.3 1.5 3.1
■H2CT - - - -
■SCCT 6.4 8.8 12.8 15.2
■CCCT 4.9 4.9 5.9 6.4
Nuke - 0.5 0.5 0.5
DR 5.1 5.3 5.5 5.8
■Storage 19.1 38.1 58.0 66.8
Net-Meter 9.1 13.5 16.8 20.8
■Solar 46.0 71.6 90.8 110.2
■OSWind 1.5 8.3 15.2 23.9
■Wind 23.8 35.9 49.4 62.8
■Geothermal 1.8 2.8 4.1 6.0
■Biomass 0.2 0.4 0.5 0.7
■Hydro 1.3 1.5 1.8 2.1
11 4�

Draft W65M
U . S . West Resource Type Forecast
120,000
Other ■ Hydro Nuclear ■Coal ■Wind ■Solar Natural Gas
100,000 Significant changes
2045 to 2026 (aGW)
U)
_■■
80,000 Solar: + 19.7
Wind: + 17.6 ro
a�
so,000 Nat Gas: - 7. 1
a� Coal: - 8. 1
Nuclear: - 2.8
> 40,000 Other: + 0.6
Total: + 20.0
20,00'
N M "t In CO ti M M O — " Co "t m M ti w O O r N M "t LOW I,- W O O N M � M CO f� 00 O O N CM It In
O O O O CD O O CD O — — — — — — — — — — N N N N N N N N N N COM Co M M M M CM CO M � V V � qzr 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 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
12 tl�=

Draft WdC t
Northwest Resource Type Forecast
35,000
Other ■ Hydro Nuclear ■Coal ■Wind ■Solar Natural Gas ■Petroleum
30,000
Significant changes (aGW)
2045 to 2023
� 25,000 —
Solar: + 3.6
20,000 Wind: + 4.1
Nat Gas: - 2.6
Coal: - 1 .1
15,000 Other: + 0.8
c�
a� Nuclear: + 0.2
Q 10,000 - Total: + 5.1
5,000
N MItT LO C0 r— 00 M O N M I LO t0 f.- M M O N M 'IT LO c0 f� M M O N MItT LO C0 r— M M O N M I LO
0 0 0 0 0 0 0 0 0 N N N N N N N N N N M M M M M M M M M M � � � 11* q 114"
O O O O O O O O O O O O O O O O O O O O O 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
13

Greenhouse Gas Forecast Draft foftcVt
U .S . Western Interconnect
400
■AZ ■ CA CO
350 ID ■ MT ■ NV
■ NM ■ OR ■ UT
300 m WA m WY
250
O
H
v 200
150
•0 100
50
11
O N 'Cl, CD CO O N E (0 o0 O N T O 00 O N 1 O 00 O (V � (0 CO O N E
O O O O O O O O O O �T— = = = = CV N CV N N M n M n 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
N N CV N N N N N N N N N N N N N N N N N N N N
14

Draft forecast Appendix A
Mid =C Electric Price Forecast
$70 Levelized Prices:
Flat Delivery vvICCA -Flat Delivery vvlo CCA -Avistr
$60 — $48. 12/MWh w/CCA
$50 — $45.52/MWh w/o CCA
$40
— $42.56/MWh Avista
L
°- $30 Forecast includes
$20 expected resource
$10 additions
$0
roroNmrororororor(, OItNmItL, Potential for increased
N N N N m m m m m m m m m m � � � � � � •
O O O O CDO O O O CD CD CD CDO CD CDO O O O
N N N N N N N N N N N N N N N N N N N N
prices if new resources
don't come online
15

Draft forgCg$t
Hourly Wholesale Mid =C (w/o CCA) Electric Price Shapes
Winter: Dec 16 - Mar 15 Spring: Mar 16 - Jun 15
$120 2030 2035 2040 2045 $120 2030 —2035 2040 —2045
$100 $100
$80 $80
$60 1 a`, $60
Q Q
60 V)
$40 $40
$20 $20
$0 $0
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
LJ-.,,
Hour
Summer: Jun 16 - Sep 15
—2030 -2035 2040 —2045 Fall: Sep 16 - Dec 15
$120 $120 2030 2035 2040 2045
$100 $100
$80 $80
v $60 $60
own
a a
$40 $40 -
$20 $20
$0 $0
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hour Hour
16

Draft foftcVt
Northwest Wholesale Electric Price Comparison
60
cD � 00 (0) O r_4 N M It Lr) cD � 00 G1 O r-I N M Rt u"1
N N N N M M M M M M M M M M Rt It It Rt Rt �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
Flat Delivery vv/o CCA - Flat Delivery w/CCA - Avista
-Consultant 1 -Consultant 2
17

Draft foftcV t
Mid =C Price Forecast History and Actuals
$120 2005 IRP 2007 IRP' � — 2009 IRP" —2011 IRP
—20131RP 20151RP —20171RP —2020IRP
—2021 IRP —2023 IRP •2025 IRP —Actual
$100
de .
$80 /
i
i
$60
CL ago am
$40
$20
SO
I-- CO M O — N Mzf LO (D � CO M O — N M "t u7 CO A M M O — N M I u7 CO ti M M O — N MI- LO
O O O � N N N N N N N N N N Coco Co cM Coco CO CO cM CO IT "T IT "TIT S
O O O O O O O O O O O O O O O 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
18

Appendix A
Next Steps
• Finalize deterministic case
• Conduct stochastic studies and verify resource adequacy
• Run scenarios (deterministic/stochastic as appropriate)
19

Appendix A
2025 Electric IRP Portfolio Proposed Scenario List
Scenario Sensitivit . - LOLP
kL Study Study
1 Preferred Resource Strategy Deterministic X X
Low NG Prices
High NG Prices
2 Alternative Lowest Reasonable Cost
3 Baseline: Least Cost Reliable Portfolio Deterministic X X
Low NG Prices
High NG Prices
4 Clean Resource Portfolio by 2045 Deterministic X X
Low NG Prices
High NG Prices
5 Low Economic Growth (Low Load Growth)
6 High Economic Growth (High Load Growth)
7 80%Washington Building Electrification by 2045
8 80%Washington Building Electrification by 2045 &
High Transportation Electrification Scenario
9 Extreme Building/Transportation Electrification for X
Washington & Idaho w/o new Natural Gas CTs
10 Maximum Washington Customer Benefits
11 Least Cost+ 500 MW Nuclear in 2040 Deterministic X
Low NG Prices
High NG Prices
12 WRAP PRM X X
13 Least Cost+ 0% LOLP X X
14 Power to Gas Unavailable X
15 Minimal Viable CETA Target
16 Maximum Viable CETA Target
17 Preferred Resource Strategy w/CCA repealed No CCA Forecast
18 Unconstrained Cost Preferred Resource Strategy
19 High QCC on Demand Response (w/minimum X
selection)
Avoided Cost Portfolios
A No Supply-Side Resource Additions
B Clean Capacity by 2045
Other potential scenarios
• RCP 8.5 Weather: Given the expected case includes RCP 8.5 for summer, is it necessary to
understand the impacts of lower winter capacity needs to warming temperatures?
• 20-year Weather: Assumes the last 20-year average temperatures continue through the planning
period to understand impacts of the warming temperatures.
2025 Electric IRP Scenario Listj Page 1

Appendix A
Scenario Description:
1- Preferred Resource Strategy: Using the expected case load, resource, and stochastic price
forecast, the model will determine the least cost resource strategy meeting each state's energy
and capacity requirements. Portfolio will also track Customer Benefit Indicators in Washington
and use Social Cost of Greenhouse Gas (SCGHG), Non-Energy Impacts, and Named
Community Fund (NCIF) spending for Washington's portfolio optimization. Idaho's optimization
will focus on least cost to meet energy and capacity requirements. Portfolio uses planning margin
requirement to ensure 5% Loss of Load Probability (LOLP) in 2030. CETA targets are shown in
Figure 1.
2- Alternative Lowest Reasonable Cost: Required study to determine CETA cost cap impacts.
This scenario assumes no CETA clean energy requirements, no NCIF, but includes SCGHG for
resource selection [in Washington]while meeting physical monthly energy/capacity requirements.
3- Baseline: Least Cost Reliable Portfolio: Determines the least cost portfolio to meet energy and
capacity requirements based on economic decisions w/o SCGHG or CETA; same as the
`Alternative Lowest Cost Alternative' scenario w/o SCGHG prices for Washington. The portfolio
will also be used to develop avoided costs as it separates portfolio costs by renewable and
capacity premiums; quantifies the impacts of SCGHG.
4- Clean Resource Portfolio by 2045: Determines the portfolio to eliminate all greenhouse gas
emitting generation resources in the portfolio by 2045. The resulting portfolio must meet all
capacity and energy requirements.
5- Low Economic Growth (Low Load Growth): Studies the portfolio effects of loads not
materializing due to lower growth than forecasted.
6- High Economic Growth (High Load Growth): Studies the portfolio effects of higher load levels
materializing due to higher growth than forecasted.
7- 80%Washington Building Electrification by 2045: Determines the least cost portfolio of
converting 80% of Washington State natural gas residential and commercial demand to electric
through heat/water conversions to heat pump and resistance technologies by 2045.
8- 80%Washington Building Electrification by 2045 & High Transportation Electrification
Scenario: Determines the least cost portfolio of converting 80% of Washington State natural gas
demand to electric through heat/water conversions to heat pump and resistance technologies by
2045 along with a higher-than-expected electric transportation forecast.
9- Extreme Building/Transportation Electrification w/o new Natural Gas CTs: Determines the
least cost portfolio of converting 80% of Washington & Idaho natural gas demand to electric
through heat/water conversions to heat pump and resistance technologies by 2045 along with a
higher-than-expected electric transportation forecast for both states. This scenario also assumes
all natural gas resources are retired by 2045.
10- Maximum Washington Customer Benefits: Washington State required scenario to understand
the portfolio and cost impacts of improving Customer Benefit Indicators. This portfolio will exclude
non-Washington sited resources, air emitting resources and lower energy burden through
additional energy efficiency and community solar for named communities. Higher named
community penetration of roof-top solar and electric vehicles from the Distributed Energy
Resource Study will also be considered.
11- Least Cost+ 500 MW Nuclear in 2040: Uses the Preferred Resource Strategy assumptions with
the addition of up to 500 MW of nuclear generation beginning in 2040.
12- WRAP PRM: Solves for the least cost portfolio meeting capacity, energy, and state policies using
the Planning Reserve Margin currently required in the WRAP.
13- Least Cost+ 0% LOLP: Solves for the least cost portfolio meeting capacity, energy, and state
policies, but acquires generation to ensure the loss of load probability (LOLP) is zero rather than
5%.
14- Power to Gas Unavailable: Similar portfolio design as the "PRS" scenario without the option of
using power to gas fuels such as Ammonia or Hydrogen.
2025 Electric IRP Scenario Listj Page 2

Appendix A
15- Minimal Viable CETA Target: Uses the same portfolio design as the "PRS" scenario except the
CETA targets for clean energy use the minimal viable targets from Figure 1.
16- Maximum Viable CETA Target: Uses the same portfolio design as the"PRS"scenario except
the CETA targets for clean energy use the maximum viable targets from Figure 1.
17- Preferred Resource Strategy w/CCA repealed: This portfolio uses the No CCA market price
forecast and estimates the portfolio if the CCA is repealed by voters in November 2024.
18- Unconstrained Cost Preferred Resource Strategy: In the event the PRS scenario is
constrained by the 2% cost cap, this portfolio illustrates the cost to comply with 2045 CETA
regardless of cost.
19- High QCC on Demand Response (w/minimum selection): This portfolio will be optimized
using a higher QCC for demand response programs than used in the PRS scenario. If the
portfolio does not result in higher demand response, the lower cost program options will be
included in the portfolio.
Avoided Costs Portfolios:
No Supply-Side Resource Additions: This "portfolio" is only used to estimate the capacity premium of
the avoided cost calculation; uses same EE selections as `PRS' scenario; uses same assumptions as
`baseline' scenario except uses market purchases to meet demand instead of acquiring new resources.
Clean Capacity by 2045: This portfolio is similar to the `baseline' scenario except it does not allow for
new natural gas generation, does not require the model to satisfy monthly energy targets and assumes
Coyote Springs 2 is not available in Washington in 2045. The portfolio is used to determine the clean
capacity credit for avoided cost calculations only.
Figure 1: CETA Target Scenarios
o o e
000
000
100% O o 0
■Minimal Viable Targets
LO
95% ■Expected Targets N
o � �
CO ■Maximum Viable Targets o o
p 90% OR CO
OR ro
J o o°
_ Ln
CO
CO 85% Cq o
o OR N
O O c0 CO
o O O
80% o �, CO
O a
o o LO
75% o CO COr
m
� o
CO
m
70% o
0
ID
O o `O o o a
65% n u' Un U'
ID
N
60%
D_
55%
50%
2026 2027 2028 2029 2030-33 2034-37 2038-41 2042-44 2045
2025 Electric IRP Scenario Listj Page 3

Appendix A
2025 Electric IRP, TAC 3 Meeting Notes, March 21, 2024
Participants:
John Barber, Customer; Shawn Bonfield, Avista; Tamara Bradley, Avista; Molly Brewer,
Washington UTC; Terrence Browne, Avista; Michael Brutocao, Avista; Logan Callen, City
of Spokane; Katie Chamberlain, Renewable Northwest; Josie Cummings, Avista; Corey
Dahl, Public Counsel; Kelly Dengel, Avista; Joshua Dennis, Washington UTC; Mike
Dillon, Avista; Chris Drake, Avista; Michael Eldred, IPUC; Ryan Finesilver, Avista; Damon
Fisher, Avista; Grant Forsyth, Avista; James Gall, Avista; Amanda Ghering, Avista; John
Gross, Avista; Leona Haley, Avista; Lori Hermanson, Avista; Mike Hermanson, Avista;
Jackson Parthasarathy, Grid United; Mary Kulas, White Gull Analytics?; Mike Louis,
IPUC; John Lyons, Avista; Patrick Maher, Avista; Heather Moline, Washington UTC;
Thomas Morrissey, NWPCC; Tom Pardee, Avista; Lloyd Reed; John Robbins, Wartsilla
Energy Solutions; John Rothlin, Avista; Jennifer Snyder, Washington UTC; Dean Spratt,
Avista; Lisa Stites, Grant County PUD; Brandon Taylor; Tyler Tobin, Puget Sound Energy;
Yao Yin, IPUC
Introduction, John Lyons
John Lyons: I'm John Lyons with Avista's Resource Planning Group. Welcome to our
third Technical Advisory Committee meeting today. We'll do a brief introduction, then we'll
get into a review of the January cold weather event, then the wholesale natural gas and
electric price forecast, and then we'll end with the discussion on portfolio and market
scenario options that we're planning on looking at. We had some discussion here early
on in this 2025 TAC process and a lot of the feedback that we got was that it's an awful
lot of information that we're going through and members would like some time to process
it and work that out in their mind. The thought was if we have more frequent TAC meetings
that are shorter, that will keep people more involved with the process, but also, we will try
to focus on just one or two key items.
John Lyons: We also, if you'll notice when I send out the email with the slide deck, we're
trying to put on the key questions we're going to be asking you so you can start thinking
ahead of time the ideas we would like to discuss. We will still take comments afterwards,
if those come to you later. Also want to do a quick reminder, we have our DPAG
[Distribution Planning Advisory Group] meeting next week that's on the 27' and that's
going to be on EVs and solar in particular. If you're interested in those topics, be sure to
call into that. If you're not on the DPAG, you can contact me, and I'll get you in touch with
that.
John Lyons: Also, a lot of the data that we're starting to share is already out on the
Teams site for the IRP. One thing we are asking if you go out to the Teams site, let us
know if you're having problems pulling that data because we did receive a notice that

Appendix A
there are some potential security issues and they might be locking some of that up, but
so far it looks like people can still access it, but if they're not able to, please let us know.
And then we would just go back to posting that on the website and after that part of the
today's agenda, we do have the remaining TAC meeting.
John Lyons: Starting April 9t", will be every two weeks, with the exception of the Fourth
of July weekend, and got those on there. They're also posted on the website, and you
can see the topic. Next time we have future climate analysis and the economic forecast
and the five-year load forecast. We also have the technical modeling workshop on June
25t". That is the only one that I haven't sent the meeting notice out yet, because I didn't
want to hit everyone with too many meeting notices all at once. I'll be sending that out
soon. August 13t" will be the last TAC meeting for this series, this every other week
schedule. We will release the draft IRP September 2nd and the final IRP January of 2025.
John Lyons: And then we also will have a couple of public sessions where we'll have a
recorded presentation and then we'll have a daytime and an evening time period for
comment. That's all I've got for the introduction, unless there's any questions. Hearing
none James, do you want to take it over and start sharing the load event presentation?
Review of January Cold Weather Event, James Gall
James Gall: Do you see my slide?
John Lyons: I do.
James Gall: OK. We're in good shape then.
John Lyons: Hopefully someone outside of Avista can see that as well.
James Gall: Hopefully. Usually that's the case. Good morning everybody. The MLK
weekend weather event. I'd say it's kind of the canary in the coal mine event for the region.
The reason why I say that is I think that's the closest our system in between Avista and
the region has been from not meeting loads. Actually, Avista did have to curtail some
loads which I'll get to in a little bit. But it shows the dire need of resource adequacy in the
Northwest. We'll go through some Avista's experiences.
James Gall: We had some very unique experiences during that event compared to the
region Feel free to stop me as I go through this. If there's a question that comes up, there's
your hand. I'll probably see that, or Lori or John might see it as well, and we can pause.
Or go ahead and put it in the chat and that works as well. I'll getting started.
James Gall: This is just to give you an idea of the temperatures that we experienced on
January 13t". These are the low temperatures. Spokane, which we typically plan for, we
were minus 10 at the airport as a low. Our high was minus four, maybe minus two. Parts
of our service territory got in the minus 20s, minus 28 down in Lewiston, or Sandpoint
area minus 17. We saw extreme temperatures during this event, and this was, I would

Appendix A
say, very similar to an event we had a year ago on December 22, 2022. We saw almost
identical low temperatures and very close to the same high temperature. So, we saw two
of these events in the winter in a row, but we actually saw different outcomes in load and
also in performance.
James Gall: We'll get to the performance of the gas system in a minute. This chart
represents our loads and resources, and this is what we're trying to balance. If you want
to relate this to an IRP, this is the best illustration because the IRP is trying to plan our
system to meet this type of an event and the black line on this chart represents what our
actual load was. During this event, we had our highest load on the 13t", which is a
Saturday, which is typically uncommon. But right here in our 18, in this black, dotted line
represents what the load would have been if we did not have to curtail some of our
industrial customers. One was voluntary, one was involuntary, and what I mean by
involuntary, we had a natural gas issue on the GTN pipeline. Upstream of us there were
some mechanical problems on a compressor station and that reduced the pressure for
the Spokane area. In response to that, two of our natural gas facilities had to curtail, and
a substantial amount of industrial customers also had to curtail. And when that happened,
one of our industrial customers on the electric side has both gas and electric service had
to reduce their loading. I see a hand up by Molly. You have a question?
Molly Brewer(UTC): Yeah, there's the question is, is curtailing like load shedding or what
exactly is curtailing?
James Gall: Yeah. Think of his load shedding.
Molly Brewer (UTC): OK.
James Gall: Essentially asking that customer to reduce their demand. One of our
industrial customers, we have an agreement to reduce demand and there's a
compensation package for that and other customers. If there is a reliability event, there
are some agreements to reduce demand in those circumstances. Those are very rare,
and this is a very rare event.
Molly Brewer (UTC): OK. Thank you.
James Gall: From that point of view, the red line that's dotted on top represents how
much capacity we actually have to hold on our system. Even though our load may have
been at the level you see here, we actually have to reserve capacity on our system for
that higher amount to meet two critical things. One is operating reserves. Those are
reserves that we're required to hold by WECC, 3% of our load amount and 3% of our
online generation. Those reserves are required to keep our system stable in the event a
unit trips. For example, when we had to bring units down here in the early part of the day
on Friday, something has to respond to that unit going down. That's why we hold these
reserves and that's required by every generator and load serving entity in the Western
Interconnect. The other component of capacity we have to hold is something that is newer
to Avista and that is EIM flex ramp. When we participate in the EIM, we actually have to

Appendix A
hold capacity on our system to participate in the market. Before EIM, we ran our system
as we saw fit. We wanted to hold reserves for our needs, but now we actually have a
mandated amount of reserves we have to carry. These two things add up to maybe a
couple hundred megawatts between the two that we have to carry in reserve.
James Gall: I'm moving to the resource side. On the bottom we have our Kettle Falls in
our qualifying facilities, and black - Colstrip and brown - our natural gas, and yellow —
wind, solar is the green, and hydro is in the blue section. How this chart works is if you
see colored area below the black line where purchasing power on the market and if we
are the color is above the block line we're selling. You can see here, during our peak
event when we lost our generation, we had a substantial purchase. When we plan our
system and IRP we do expect to rely on the market to a certain amount. It's about 330
megawatts in our planning and we also intend to serve all of our loads. If from an IRP
planning type of event, when we model those, we're trying to see what is the probability
of a loss of load event? That is a circumstance where you can't serve all of your load with
your generation or up to 330 megawatts from the market. This event actually qualifies.
This would be a loss of load event in our planning process methodology.
James Gall: This is actually pretty concerning from a reliability point of view because it's
starting to show maybe we do not have enough capacity. Going into this event, last IRP,
we thought we had quite a bit more capacity than, or I should say we were capacity long
think to about 2035, but there's a few things that have changed since then. One is we
are seeing substantially higher loads for this load level for the given temperature. Given
that we had the same temperature last winter was around, I believe 70 or 80 megawatts
higher at that peak hour, and that doesn't even include some of the load shedding we had
to do. So, there has been some load growth, also this EIM flex ramp that we're required
to hold that is something we've not really planned for. In the past, we've planned for a
lower amount of flexibility. We're going to see in this next IRP, because of this event and
we have real data to the look at, we need to start planning for these types of events and
if a future occurs like we're we know in 2026, this brown, bar down here, Colstrip is not
going to be available to us. How do we serve these events?
James Gall: We call them sustained peaking events and without a stable resource it's
going to be difficult in the future to have a reliable system. One analysis I looked at after
this event because again this is a low hydro event, high load event with some resource
outages that if we even had 10 times as much wind which would be around 1 ,600
megawatts more of wind and 100 times more solar, say 2,000 megawatts of solar. That's
the future we're tracking towards. How do we serve this event with those resources? And
really, at the end of the day, it comes down to we need storage assets, but the amount of
storage we need is so massive, the service of and I don't know how that's going to occur
at least in the next decade. Just to give you an illustration, if the common battery of today
is four hours, if we had four-hour battery and the renewable resources I mentioned earlier,
we would need 14,000 megawatts of batteries. Now that's more than is on the Western
system right now and that's just to serve our load. Long duration batteries is probably

Appendix A
where we need to go. If we had 50-hour batteries, we would only need around 1 ,200
megawatts. But the challenge with that is at 1,200 megawatts at the 50-hour battery, even
if we perfectly timed our dispatch, we would have nothing left at the end of this week to
serve the next week.
James Gall: The key to have a future, a reliable future with no natural gas or no coal,
we're going to need some extremely long duration energy storage facilities. I see a hand
up. Actually, I see two hands up. I don't know who is first. Kelly, go ahead and go first.
Kelly Dengel: Yeah, James, thanks. This is Kelly, from Avista. This is just painting the
picture of the electric customers and you're not really showing the picture of what the gas
customers experienced, right? So just where?
James Gall: That's next line. Yep.
Kelly Dengel: OK, because then this pictures only compounded when you include the
gas customers that were affected by outages or the shortage of resources as well. That's
all I wanted to say.
James Gall: I'll get into that a little bit. I don't have the amount that had to be curtailed on
the industrial side. Our firm customers were not curtailed, but I'll illustrate a little bit of how
much equivalent electric load there is on the gas system. I can't see who had the other
hand up but go ahead.
Jackson Parthasarathy: Jackson, with Grid United. Nice to meet you. Due to the kind of
regional nature of this weather where you have this extreme event that's impacting the
whole Pacific Northwest all at the same time creates large hurdles for resource adequacy
as you're pointing out here. How do you think about, I guess to take a step back, you were
talking about batteries as well and the resource build out of batteries that you might need
in order to be able to serve load in such events where gas pressure drops, and gas plants
leave the system. Do you think about interregional transmission, and I mean particularly
one of our projects proposes to connect Colstrip with SPP and MISO and the ability to
import resources from outside of the region. If you could talk a little bit about that.
James Gall: Sure. Actually, that's going to be one of my topics coming up on a couple
slides.
Jackson Parthasarathy: OK.
James Gall: But you know transmission is, I'll put it this way, it's an option to help with
resource adequacy if you can contract for a resource on the other side and there's been
some historical examples of transmission is not a necessarily reliable resource and it can
be, if you have differing weather patterns. But if you all have a similar event at the same
time, it makes it a challenge to rely on the transmission. The one event that comes back
to me was a summer event. I think it was in 2006 or 2007 and the whole West was hot
and we could not send power to California or vice versa just because we both had severe
events. But if we had contracted resources that we could depend on and we had pretty

Appendix A
solid evidence that there is a diversity of resources over there, we might be able to argue
there's a capacity value there. But again, do we have a secured asset over there and how
much can we really rely on the market? Because even if you go into eastern Montana,
which is not far from where you're talking about the wind facilities over there, they were
frozen up. They could not produce energy. Is that going to be a similar circumstance in
South Dakota, North Dakota? I don't know. It's a good question. I don't have the answer,
but it definitely gives you options, I'll put it that way.
Jackson Parthasarathy: Thank you.
James Gall: All right. Just to wrap things up here. Assuming we did not have the loss of
gas pressure, would this have been an IRP type of loss of load event. It probably would
not have been, we would have been in our planning criteria although we did have higher
loads, lower hydro production. Basically, what we're finding in resource planning when
we do these analyses, we know it's going to be an event like this where you have high
loads or slightly above high loads, low water, and then low renewable production and a
unit trips. That's the remedy for having resource adequacy issues and those all
compounded together. And this event from a price point of view, when we had to go out
and buy replacement power almost this whole week was near $1,000 a megawatt hour
at the first cap. This is an expensive event when you don't have resources available and
that $1,000 represents the need of the region. And I got a slide a little bit later on that, but
also the transmission system to California was on. There's two lines that connect the
northwest to California. One of those was down on maintenance and that also made it
difficult to move power around. So, there's another example. Can you rely on transmission
and that case the PCDC intertie was not available at the time. OK.
James Gall: Into gas really quick. I just want to illustrate the amount of load that's on the
gas system versus electric system on these days. As I mentioned earlier, this event
compared to last winter was about the same load, but we did have to curtail some
generation or some load on this event, that's that red bar there. What we did is convert
the electric load to Btus, so we could compare those to the gas load, and this is our firm
gas load in Washington and Idaho. You can see our gas load is almost three times as
much as our electric load on these winter days. And we also set a winter peak load event
for the gas system, but like Kelly had mentioned earlier, if you look at our gas system and
you think of a future of we want to move people from the gas system to the electric system.
Our loads would be substantially higher. How do we manage that?
James Gall: We've shown that in many scenarios in the last couple IRPs, but the 315
mmBtus use, or thousands of mmBtus, wouldn't quite be that much on the electric side.
Electric system is a little bit more efficient, but still maybe 2/3 of that would be electric
load and it's just a good illustration of the challenges of electrification of buildings, of the
quantity of megawatts of just generation you need, but also how do you deliver that to
load.

Appendix A
James Gall: It's a substantial challenge that the region would have if we electrify, and
you compare that to our highest summer day. So, on our summer day, which was the
Heat Dome event June 30t", 2021, highest peak hour we've ever seen and the amount of
load that day though was still less than these events because most of that load was
concentrated in the evening where the loads that you have in a winter event are all day
long.
James Gall: And just to kind of give you an idea that event was like a 1-in-100 event.
Some people may argue these winter event temperatures are not unheard of in Spokane.
It was still not colder than our 2008 event, which isn't too long ago. Cold events are often.
But when you don't get one, our winter loads don't look very high. But when you get a
load event in the winter, it illustrates substantially higher loads. If we didn't have to curtail
generation and two customers, our load would have been substantially higher than the
most extreme event we've ever seen in Spokane.
James Gall: Just to wrap this up quick, from the regional perspective, this is a similar
L&R chart on the bottom left and the pink area is my biggest concern. That's the amount
of imports the region had to bring in, this here from the Power Council. The Power Council,
believe plans for around 1,500 megawatts of imports. The region was substantially short,
did not have enough generation within its own system to meet pretty much most of the
loads from late Friday into later in the week. This is really showing a resource adequacy
problem in the Northwest during these events. You can see that in market prices, and
also how much units are running, or peaking units are being dispatched more than they
have been in decades because there's just not enough energy in the system to continue
to meet demand. Demands are growing and we're not building dispatchable generation,
so we're starting to see more and more reliance on our natural gas units. And as coal
goes away because of lack of reliable generation and then moving to the right is the flow
of those imports come from, a lot of those come through California. But my understanding
is most of those flows really came from the southwest via California. We also did get some
energy from Canada and especially Avista. We did rely on Powerex quite a bit. While our
units did trip, so we appreciate their support, but I see Kelly, you have a hand up.
Kelly Dengel: Yeah. James, on the left with the resource stack, I see a tiny little bit of
nuclear. Can you explain where that's coming from?
James Gall: Yeah, that's the Columbia Generating Station outside of the Tri Cities, it's
around 1,100 MW.
Kelly Dengel: OK. Thank you.
James Gall: You're welcome. OK. Just to wrap things up. Since this is a canary in the
coal mine event, what are things that we should be doing in resource planning to make
sure we have an adequate system? I have three things in red that we are, I would say
mostly going to do, or I should say highly considering. And then there's some other items
that maybe we should consider. The first one is, obviously, we're going to update our load
forecast with the data from this event. We're working on that this week. Grant has got that

Appendix A
nearly wrapped up, but what that will do is show a higher load forecast for winter events
in our next IRP, which means we'll have to acquire capacity resources sooner than later.
Another thing we're doing is we're including the EIM uncertainty flex ramp in our resource
planning. When we do our loss of load probability analysis, we'll include that capacity
requirement at the levels we are seeing the EIM asking us to hold. We've always included
a requirement for this, but the amounts we're being asked to hold are much higher than
we anticipated when we did our last round of analysis.
James Gall: The third item is something that is, I think, a key for reliability. It's, I'd say
less static. We call it the single largest contingency. What we mean by that is we should
be carrying capacity above our or should say we should have a planning margin higher
than our single largest contingency resource, which what that means essentially is if that
largest contingency resource tripped, we would have at least enough capacity to cover
the expected peak load from our other resources. Since Avista actually has probably the
largest single contingency resource compared to its load of any of the control areas, that
would essentially make us a little bit longer and likely the summer months is what we're
expecting. That change would likely push us into a shorter position this summer as our
Coyote Springs facilities is our largest single contingency unit.
James Gall: The fourth item has to do with low hydro years. The region used to always
plan for low hydro, but when we started moving to loss of load probability type analysis,
low hydro got moved to median hydro. When we got our QCC values for example, that's
qualifying capacity credit in our regional resource adequacy program, they typically
assume you know more of an average hydro or meeting hydro event, and should we be
assuming a low hydro event which means lowering the expectation of our storage hydro
units. And I think that has a lot to do with the regional response. We just did not get as
much out of our hydro system as maybe we had hoped for from a regional perspective.
At least that's my opinion.
James Gall: The next one, should we be looking at something different than 5% loss of
load probability? Essentially, when you plan for resource adequacy, a 5% loss of load
probably means that you're going to have a loss of load one out of every 20 years and
that's kind of what we got here. Is that the right level of planning? Should we be planning
for a more reliable system? And I think that might be a question for, even the tag here, is
5% too modest? Should we be more conservative and plan for something a little bit
tighter? One percent, 2%? What's an acceptable outage when you're having an extreme
cold event? I know there are consequences of losing load, especially when it starts
affecting residential customers.
James Gall: Another thing is how much can we depend on the market which is the
second to last bullet. We've always assumed around 330 megawatts. We were able to
lean on the market for that amount for a short amount of time. That was definitely not
something we could have done sustained. As you can see in that week, because the
whole region was looking for the market. That goes back to even the transmission as well.
We had more transmission. Can we rely somewhat on the market at a higher level and I

Appendix A
say those are still questionable. The last one, is doing loss of load probability analysis or
looking at statistics, a right way to do resource adequacy planning? Should we rather be
looking at event planning where we have a low water year event, we have a low
renewable output event with higher-than-average loads? Should we be planning for those
events rather than a statistical probability of an event? It starts to make some sense to
me to start looking at that. We'll be studying what that looks like in this IRP process, but
that's all I have. Are there any questions, comments? Katie, go ahead.
Katie Chamberlain: Hi. I think you may have explained this at the beginning and I'm
sorry if I missed it but could you just reiterate what happened with gas on your system? I
think on the 1 Sh
James Gall: Yeah. The late the day before. GTN is a pipeline that we use to buy gas
from for our local distribution customers and to supply our natural gas turbines. They had
a compressor station issue in Alberta, and they were not able to deliver as much gas as
we had requested. So, we had to bring down two of our facilities and then also some of
the natural gas transport customers who buy gas on that system in our area also had to
reduce their gas usage.
Katie Chamberlain: Got it. Thanks.
James Gall: Yeah. Any other questions? If not, I think I'm going to turn it over to Tom.
Wholesale Natural Gas Price Forecast, Tom Pardee and Michael Brutocao
James Gall: Tom, if you're got your slides ready to go.
Tom Pardee: I do.
James Gall: Yeah, it's all yours.
Tom Pardee: OK. I'll get my ducks in a row here. Share this screen. Pop this up. Hopefully
it goes to the right screen. Hey, can everybody see that? OK.
James Gall: We see your North American supply slide, OK.
Tom Pardee: Tom Pardee, I'm the natural gas planning manager in James' Group, in the
Integrated Resource Planning Group. One more real quick thing so I can see. OK, so I'm
going to go over a fundamental forecast from Wood Mackenzie. These slides will give
you an idea of what they're expecting as far as demand and supply within the region and
nationally.
Tom Pardee: This slide here is a lower 48, just the continental lower 48 in the United
States. What you can see here is the different breakouts for the demand between
residential exports, Mexico LNG industrial and where I would point to, there's a couple
interesting things in here. So, #1 this plot, the demand essentially is leveling out for natural

Appendix A
gas within the mid-2030s time range and then it starts to decrease and I'll go into why that
is. And then I'll also show the Pacific Northwest in our mountain regions.
Tom Pardee: Another interesting thing here is they expect blue hydrogen to come on
more. Blue hydrogen would help serve this load demand or the fuel demand. Blue
Hydrogen is using natural gas to create the hydrogen, you split it, and then you capture
the carbon, and you store it. That's what blue hydrogen is. You can see that little blue
sliver here, and if you can see my mouse there it is. By the 2050-time frame, there's I'd
say, a more sizable market for blue hydrogen in these expectations. Net Mexican exports.
This is exports from the United States and go to the generation plants in Mexico. There's
some pipelines and interties that export it down there and they have quite a large load
demand with air conditioning and otherwise, that feeds their generation plants. The
sizable piece to this is the LNG exports, and for those that follow the market it's comes
as no surprise, I believe there's 12 BCF a day of LNG exports is waiting to be built and
that's on top of roughly the same amount as of today. And so, LNG exports is really what's
driving this demand.
Tom Pardee: Finally, what I'll point out in here, because the other ones are mostly the
same. I'll point out here the power demand. You can see power is green and over time
it's shifting to a lower demand within the power sector and it's actually more substantial
within our region. And like James, please interrupt me whenever there's questions. In
order to fill this demand, there's a North American supply. On the chart on the left, this is
telling you the region where supply is coming from. Rockies is one region that we get our
gas from, and you can see over time that starts to decrease. The Gulf Coast is looking
for an increase. Permian is in Texas. Fort Worth, of course, in Texas as well. But then
you have northeast. Northeast is really Marcellus and Utica range. That's a lot of the high
production, fracked gas and that looks like it's mostly going to stay the same, maybe grow
a little bit. The other portion that we get our gas from is called WCSB, Western Canadian
Sedimentary Basin. That's essentially any gas that we get from Western Canada and then
they have a very small amount that comes from eastern Canada and feeds the East Coast
of the state. One interesting thing here is if you look at the supply growth, and we're right
in this region, if you look at that and then you compare that to the rig count, the rig counts
are looking to increase by 2027 and then they slowly decrease. Actually, not really slowly
in this depiction. A lot of gas gathering and production relies on efficiencies within the
drilling process itself. This tells me that they're expecting higher production rates from
lower rig counts. In other words, each well drilled is producing more and more gas, so
you don't need as many rigs either oil in the large. Let me step back, an oil rig is essentially
what you're doing. You're drilling for oil now in any process. That's why oil rigs are in here.
There's going to be a byproduct of methane and some other a liquids, but they're primarily
drilling and looking for oil within this lighter blue of the chart. But again, there is this side
product or that extra product that they're not looking for specifically that adds to the
economics. Because of that, the supply is going up because it's more efficient as the rigs
are driving down. This is a look at the natural gas share of this. This is total energy.

Appendix A
Tom Pardee: The other was in just gas, so this is a look at total energy by fuel. Some
things I'd point out here is that in the United States, you can see that gas is roughly staying
the same, oil is decreasing overtime over this horizon from 2023 to 2050. And then you
have a removal, mostly in coal, by 2050 there's not much energy coming from coal.
Nuclear is staying roughly the same, but the other renewables are what you're driving that
delta from, oil or gas, as far as an energy component to renewables. Canada in this case
is looking at load growth in gas and they have a new LNG facility up there, LNG Canada.
That's going to drive some of their demand. But overall, their trajectory for oil looks much
the same and they have a lot of drilling and oil in Canada as well. You can see the overall
energy demand of oil is expected to go down as well.
Tom Pardee: I believe this is my final slide. When we step back and look at from the US
and then realize that policies are much different as compared to the US, we have the
Pacific demand on the left and then mountain demand on the right. I pulled in mountain
because of how they break it out. Idaho wasn't included in Pacific, as you can see. It's
Washington, Oregon and California. Mountain includes Idaho, but there's a bunch of other
states in there, the mountain regions. I'll start with the chart on the left, the Pacific region.
Here again you can see blue hydrogen coming into their expectations here in the near
term and then increasing to what is roughly a BCF a day by the long term by 2050. But
the power demand in this chart is really what drives the reduction in demand in the Pacific
region. By 2025, they're expecting power demand or power produced from gas to
decrease by quite a bit. And then it slowly trickles down to maybe 750,000 MMBTU per
day. I'll keep going. Residential demand in their expectations is staying roughly the same
commercial, the same in industrial. It looks like it's going down and my expectation is this
blue hydrogen is replacing this. This industrial load is now moving over to the mountain
region, you see much the same depiction of the Pacific. In reality, what's driving the
reduction here is the power, the lack of demand or decreasing demand in the power
generation. The other is for byproducts and let me see. Pacific demand declines from 7
more moderate build out. In this piece, it's going towards other processes, chemical
processes and things like that. In both cases, what you're seeing is an expectation from
a fundamentals forecaster of reducing demand in both of these regions and I would say
mostly because of the lack of power generation that's expected in the regions.
James Gall: Heather. Go ahead, you have your question?
Tom Pardee: Yeah.
Heather Moline (UTC): Yeah. Heather from (UTC), Tom. When were these demand
forecasts from Wood Mackenzie created?
Tom Pardee: They only release theirs once a year, and unfortunately this was from March
of 2023. We would just be on their new one. This is from their 2023 case, long term case.
Heather Moline (UTC): Thanks.
Tom Pardee: Yep. Any other questions?

Appendix A
James Gall: Kelly.
Kelly Dengel: Yes, any of these decreases in demand take into effect policy changes for
the gas industry.
Tom Pardee: Yeah, I'd say both of them do. The decrease in power generation is
definitely driving that from a policy change. And then also the increase in blue hydrogen
expectation in the Pacific region, but also within the mountain regions as well. Any other
questions? OK.
James Gall: Alright, I apologize. I probably didn't set up Tom's presentation too much,
but I'll try to do that a little bit for the next two presentations and we're going to get into
the natural gas and electric price forecast.
James Gall: These two price forecasts are extremely important for an IRP process. One,
the gas forecast that Michael Brutocao is going to go through next is an input into our
Aurora model that really helps drive what electric prices will be in the future or at least is
one of the major components. We'll start with the gas forecast and then we'll get into the
electric price forecast with Lori's presentation. Michael, if you're ready.
Michael Brutocao: I am trying to share my. Ah, there we go. Hopefully you can see this.
James Gall: We can see it.
Michael Brutocao: OK, I don't know if you see yourself on there also. Yeah. Thank you,
James. Like James mentioned, I'll be covering our natural gas prices. Our forecast. When
we generate our natural gas prices for the IRP, we first start by coming up with the
expected price forecast. These are monthly prices and the first year you can see here, on
the far left, 2026 is fully following what the forward market prices are on the NYMEX. The
reason we do this is there's a high volume of trades at Henry Hub and these prices are
very informed as we move out through time. The volume of trades decreases and
eventually there aren't any trades going on and there's no information as to what prices
may be out say 2040, mid 2030s. We bring in three different forecasts from various market
consultants and the EIA's annual times three years and then eventually moves into purely
forecasted prices.
Michael Brutocao: At the Ievelized price you can see is about $5 over this time and one
reason we use three different price forecasts is that one may be biased upwards, one
may be biased downwards for various reasons. Averaging these three or blending them
in together decreases or offsets those potential biases. So, this is the expected price
forecast, but not necessarily what we anticipate. Prices are going to be with 100%
certainty. To address that uncertainty, we use a process called stochastics. How we run
300 stochastic price forecasts, you could think of each one of those as a different, back
to this previous slide, as a different line. It may be higher, may be lower, in different
months, but it varies from our expected price. These 300 draws all start from that expected
price forecast. And then they move away back towards down. They differ over time, and
that difference comes from two different inputs. The standard deviation of errors and the

Appendix A
autocorrelation factor, so standard deviation of errors is essentially looking back at historic
prices and what the market volatility has been.
Michael Brutocao: That allows us to draw around that expected price and you see
overtime as these blue lines, the mean and max does start to widen. It's the jaws of our
price forecast and the reason for doing that is that the further you get away from today,
the less certainty there is around what prices may be. There's less information and it's
more likely that prices are going to be further away from what you may expect, and the
autocorrelation factor in this when it's drawing.
Michael Brutocao: Actually, let me let me back up here and just explain what one
stochastic draw may do. You start with your expected price. Say it's $4 and based on
historic markets, when you're in that first month that distribution around where that price
might move in one month is much tighter than what a price might move from five months
out or a year out. And so, we take a draw around $4 and we draw $5, we then start the
next period recognizing that last month, even though we expected it to be $4, we drew up
here at $5. That's where this autocorrelation piece comes in. It says we're going to,
instead of now drawing from $4.05 like our expected price says, we're now going to draw
from say, $5 or $4.98 and draw from there. That's what also allows this base to deviate
from our expected case and the stochastics are a good way of measuring and addressing
that kind of risk, of the risk around us not having the exact correct price forecast in our
expected case.
James Gall: Michael, Molly has a hand up with a question.
Michael Brutocao: Oh yeah.
Molly Brewer (UTC): Yes, just wanted to know how is this taking in their houses
measuring price effect of the Climate Commitment Act?
Michael Brutocao: So that that affect I.
James Gall: I can take that one, Michael. The Climate Commitment Act, it's a single state
and that's affected on the retail side, not the wholesale side. The only way there'd be an
effect is if there is a lessening demand of natural gas on our system that slightly affects
national pricing or regional pricing. I'd say there's no direct or at least a very minor direct
correlation between CCA and a long-term price forecast of the country.
Molly Brewer (UTC): OK. What about? Well, I guess you can't. I don't know how you
would predict this. If there were something like CCA nationally or in many other regions
over the next decade is that somehow, does that factor into this?
James Gall: Yeah, we do have a low price and a high price natural gas scenario price
case. We'll run that through our Aurora model, so we can model those cases, or we would
have a high carbon price case. I'd say it's outside of maybe this part of the price forecast,
it would be more on the Aurora side.
Molly Brewer (UTC): OK. Thank you.

Appendix A
James Gall: Yep.
Michael Brutocao: All right. This is our last slide. To move those prices to our more local
gas basins where we're purchasing gas from, we apply a basis differential that comes
from our consultant too, basis differential forecast. That's the delta, the price difference
between Henry Hub and say AECO, Maline, Sumas, Stanfield and this is just the expected
case here. This would then be applied to every one of those 300 stochastic price draws
we're running the model. This will also vary as you saw back here. It'll have that same
general relationship. And I'll move it to Lori unless there are other questions.
James Gall: Josh has his hand up.
Michael Brutocao: OK.
Joshua Dennis (UTC): Howdy. So, my question is that those month to months are
extrapolated to years in the forecast.
Michael Brutocao: Are they're all, they're all monthly.
Joshua Dennis (UTC): OK.
Michael Brutocao: Prices. I'm sorry, were you referencing this this past slide having kind
of a inter linear?
Joshua Dennis (UTC): I think it was the slide before this one. Yeah. Wait.
Michael Brutocao: I'm sorry, OK?
Joshua Dennis (UTC): OK. Excuse me? I thought I heard that it was taken on a monthly
and then extrapolated to a yearly. So that's my mistake. Thank you.
James Gall: Yeah. All when we.
Michael Brutocao: There is one yearly.
James Gall: Go ahead, Michael. Sorry.
Michael Brutocao: Well, I was just going to say this Annual Energy Outlook 2023 price
forecast. But those are annual prices that they provide, and those are broken down to
monthly prices. But everything else is purely monthly. Yes.
James Gall: Yeah, just going to add on our Teams site, the monthly price forecast is out
there in a spreadsheet. So, if you're interested in looking at what our forecast is, it's that
black line on this chart and you can go out and see that along with the pricing that Lori's
going to present here.
James Gall: Next, on the electric side. Oh, there's any other gas questions.

Appendix A
Wholesale Electric Price Forecast, Lori Hermanson
James Gall: We'll move to electric. And we got about 30 minutes for the rest of the day.
So, I think we should have plenty of time.
Lori Hermanson: OK, let me share my screen real quick. Can you see that in
presentation mode? Yep.
James Gall: Now we see the other one. Sorry.
Lori Hermanson: Oh, sorry, on the screen.
James Gall: Yep. We lost your camera like we lost Michaels, but.
Lori Hermanson: How's that?
James Gall: That's much better.
Lori Hermanson: OK, so I'm Lori Hermanson. I'm the Senior Resource Analyst in the
Resource Planning group, and I'll be covering the electric price forecast. The whole
purpose of the price forecast is to estimate the market value of resources that end up in
our IRP and estimate how those dispatchable resources dispatch the price, informs our
avoided cost, which we use for our PURPAs and QF. And then finally, it could change the
resource selection if resource production is counter to the needs of the wholesale market.
For example, if there's a lot of renewables that have been built or forecast to be to be built
in a different region than maybe less of those resources would be selected for our area.
Lori Hermanson: We use Aurora, which is a third-party software. It's owned and
developed by Energy Exemplar. It's an electric market fundamentals production cost
model. It simulates the dispatch of generation to meet load and we put in all the loads
across all the WECC. We have all the resources we put in constraints, which could be
things like transmission constraints, but it could also be policy constraints, state or federal.
And then from all of that, we get the outputs which are our electric market prices. You
have a general indication of what the regional energy stack is, what the transmission
usage is, the greenhouse gas emissions, as well as the cost. What the margins are for
the power plants, the generation levels, and the fuel costs. Finally, we're able to determine
our variable power supply cost.
Lori Hermanson: Before we go deeper into the price forecast, let's look at the history of
the Mid-C prices. Back in the late 1990s, there was good hydro and we had cheap natural
gas prices. In 2000, 2001, we had the energy crisis that we all remember, and we saw
prices above $100 a megawatt hour. After that, we resumed briefly our kind of normal
conditions and then the natural gas market tightened as we had more demand and less
supply, and we saw prices approximately double from what we were used to in 2009.
And, for the next decade there were shale developments. And so, there was more supply
available, and we saw prices dropping back down to what we'd formally had in the late

Appendix A
1990s and as we come into the recent years, we're starting to see more upward price
pressure. This could be contributed to a few things, such as carbon policies in California
impacting us, but largely this is indicating what James was touching on earlier in his
presentation. It's a reliability issue and resource adequacy and because of these
shortages of supply, you're starting to see the prices spike in 2022 and 2023, but then
also predicted in our forwards for the next couple of years.
Lori Hermanson: Our 2020 fuel mix both for the Northwest and the WECC, this is based
on EIA on their 2023 preliminary results. They usually update their 2023 results mid-year
and so I only had access to preliminary results but our energy, or I should say our
greenhouse gas emissions, compares better than against the WECC. We have 69%
greenhouse gas emission free whereas the rest of the WECC is 47%. Largely this is no
surprise. It's due to our high hydro base. We have a 50% hydro footprint while the rest of
the WECC has about 20%. Our coal and natural gas footprints are lower compared to the
WECC. Our wind and is on par and our solar is considerably less than other areas of the
South. Compared to the rest of the WECC where they have 10% solar.
Lori Hermanson: Here are some other market indicators that are giving us some
highlights that maybe the market is tightening. This chart on the top left-hand corner is
daily natural gas compared to on peak electric prices. We show this because natural gas
in the past has been the biggest contributor to power prices. Here we're seeing that even
though we see spikes in gas prices here and there. Basically, the cost of, or the
comparison is increasing. You're seeing some outliers here compared to most of the
history and this could be driven by some of the carbon policies, like in California's carbon
pricing. Washington implemented carbon pricing in 2023, but a larger contributor to this
is our resource adequacy issues.
Lori Hermanson: The chart on the right is the spark spread. This is a comparison
between the mid-C prices and the Stanfield prices. Historically from 2003 to late
2018/2019 and it's been fairly stable. Now we're starting to see some spikes especially in
2021 and 2022 and nearly doubling and 2023.
Lori Hermanson: This chart indicates the profitability of a combined cycle, which in the
past, has been the marginal resource. But lately, especially in 2023, that marginal
resource has been more of a peaker. Again, this is indicating resource adequacy issues
and that there could be reliability issues. The chart on the bottom left-hand corner that
shows the implied market heat rate, which is similar to the spark spread chart, but it
compares the heat rate equivalent to price of power and gas. In the past you can see it's
been stable around a heat rate of 8,000, whereas in more recent years we're seeing more
spikes. And in 2023, it almost doubled what we've been seeing historically. Again, the
impact from California and other carbon pricing could have some effect here, but again,
reliability and resource adequacy issues are being indicated by what we're seeing in the
market. And then oh, sorry.
James Gall: Hey Lori, we have a hand up. Heather has got her hand up.

Appendix A
Heather Moline (UTC): Thank you, Lori. Going back to spark spread, two questions. So
first is I don't actually know what Stanfield times 7 means.
Lori Hermanson: Stanfield is one of the natural gas hubs. The Stanfield price times 7
subtracted from the mid-C price is what this this spark spread is.
James Gall: Yeah. Can I add a few things there, Lori?
Lori Hermanson: Sure.
James Gall: Other than a combined cycle which is, I'd say the main backstop of the gas
resource is going to 7,000 heat rate. The cost to run a combined cycle would be the
Stanfield price times 7 for the heat rate. This is showing the profitability of that facility and
what happens is if the power price, your mid-C price minus think of it as your fuel cost
gets too extreme. The value proposition of a combined cycle combustion turbine is
increasing. This is showing is that these turbines, these combined cycle turbines, are
vastly in the money, meaning that prices are so high, they're running nonstop, producing
power. That is a good indicator of not enough generation in the Northwest to supply the
demand, but also now that we have CCA in Washington, at least in 2023. Some of that is
contributed to that, which would be a profit reduction, if you're selling into the Washington
area. I think at the end of the day, all of these slides are showing the Northwest is capacity
constrained and fuel constrained by high price spikes by being deeper in the resource
stack and also seen in that last one that Lori's going to get to because volatility of market
pricing.
Heather Moline (UTC): OK. Yeah, there's some details there I'm not tracking, but I'm not
going to nitpick. Thank you.
James Gall: Yep. Yeah.
Heather Moline (UTC): Just the one thing I think the slides that were sent out, say,
Stanfield times 7 minus, mid-C and so I just want to double check that it's actually mid-C
minus Stanfield times 7.
Lori Hermanson: Yeah, we caught that after we'd sent those out. This is the corrected
version, and we always send out the final slides after the presentation. Thanks for pointing
that out.
Heather Moline (UTC): OK. Thanks.
Lori Hermanson: As James mentioned on that last chart on the bottom right-hand corner.
That is just showing the standard deviation of the mid-C price. As you can see earlier on,
there wasn't much, there was a lower standard deviation, and so there wasn't much
volatility. But in the more recent years, you're seeing more volatility, again indicating that
there's some reliability, maybe lack of resources available. This is a chart from 1999 to
2022. Again, my source was EIA and it's the greenhouse gas emissions. They only have
data available through 2022, but you can see that compared to 1990 we are slightly lower
than 1990. The states that have the largest decrease in greenhouse gas emissions are

Appendix A
New Mexico, California and Wyoming, the top three. Overall, our process for the price
forecast, we start with the vendor database we purchase from Energy Exemplar. It's
utilized within Aurora. We're using the 2023 North American database, which came
available towards the end of 2023. In addition to that, we add additional inputs such as
our 30-year Hydro, which includes climate futures. The natural gas prices that Michael
had presented earlier, we put those into the price forecast. We add in regional loads from
our consultants, regional loads including energy efficiency and hydrogen production. We
add in our own forecast of EVs, net metering, our loads and resources, and any specific
operational detail in regards to our generation resources. After that we do a capacity
expansion.
Lori Hermanson: We run a capacity expansion model, which is where we put in generic
resources and the model, based on the planning margins and the loads and everything,
it indicates whether or not it's short or long and it will pull from the generic resources and
select which ones need to be built. Then we'll run a deterministic study which we end up
with some draft electric prices which I'm presenting today. After that we will run
stochastics. The purpose of that is to test resource adequacy. We vary things like
renewable load shapes, gas prices, carbon prices, other fuel prices. We vary all those
along with hydro and climate futures, and end up with 300 different electric price forecasts.
Lori Hermanson: And then based on that, we look at the level of times that we're short
on serving loads and if we need to, we will rerun another capacity expansion model that
will build additional resources if necessary. Finally, based on all of that, we'll rerun a
deterministic and stochastic run and those will be our final price forecasts. Based on
those, we run various scenarios which James will present later today. That's our whole
process. Currently we're at Step 5.
Lori Hermanson: I'm presenting today, the preliminary electric prices that came out of
this preliminary deterministic study. Now we're testing our stochastic study and I'm doing
some small sampling of runs. We'll be launching a full study soon. As I mentioned, one of
the inputs is the load forecast. We get our regional load forecast from IHS, which is one
of the consulting services. We subscribe to their forecast it includes energy efficiency and
hydro production. We add to the load forecast net metering both annually and hourly as
well as the electric vehicle forecast. From that we get a forecast of our loads from our
planning horizon 2026 to 2045. You can see that the future looks different from today as
it's definitely growing. The inputs are carbon pricing assumptions.
Lori Hermanson: We use consultant's carbon pricing, which rises to about $85.32. We
are assuming that there's no national carbon tax. I think last IRP, we assumed that there
was in some areas, or we did make that assumption. We're assuming no national carbon
price. We're modeling both CCA and that we join California and Quebec as a joint market.
That should bring the prices down somewhat. We also assumed that any regions
importing into California or Washington incur a carbon adder, a carbon price adder for
transferring power into those regions. We are also assuming that, for example, some of
the larger generation in Washington. I'm going to forget the actual ones. I think it's Grays

Appendix A
Harbor and James, can you remember the other ones that we added carbon pricing to in
2025? Can you remember some?
James Gall: Yes, that's up in Chehalis have a direct price in 2025, Yep.
Lori Hermanson: And then for all the other carbon emitting resources, we added carbon
cost to the dispatch starting in 2031. And then as I mentioned, when we do stochastics,
this is one of the things that we will vary are the carbon prices options. Based on what
you're seeing here, there's a flooring and a ceiling and the prices will vary between there
and will take 300 random draws of that contributes to our price forecast. Did you have
something to?
James Gall: Lori, Molly had her hand up.
Lori Hermanson: Oh, OK.
Molly Brewer (UTC): Yeah. And maybe this is James or Lori, I don't know. But is this
where you're incorporating the social cost of greenhouse gases that we've been talking
about, James, the one that the Commission puts out an order to update it cost?
James Gall: What will happen is this is the price that our model will see for dispatching
units or selling into the market. And then when we do our capacity expansion study to
select resources, that selection process for both energy efficiency and other resources,
then that price will be included. So, if a Resource had a CCA price attached to it, it would
take the difference, we'd add the social cost of carbon to this value. Yeah, this is what the
model sees as a dispatch and then social costs will be in the resource selection side of it.
Molly Brewer (UTC): OK. Thank you for that clarification.
Lori Hermanson: OK. As I mentioned earlier, we put some generic resources into the
model that it can select if certain regions are short in order to meet their demand and
planning margins. Based on the new resources selected, this is our new resource forecast
for the planning horizon, just some excerpts of certain years. But this is very similar to the
level we had in the last IRP. The mix is changing slightly, but you're seeing more wind
and more nuclear and things like that. This is the resource type history and forecast of
the WECC as well as the significant changes by resource type. You can see how it's
contrasting against history. You're seeing increases in solar and wind, decreases in
natural gas, and those are the largest contributors to the changes for the forecast.
Lori Hermanson: Here's a similar look, but for the Northwest and you're seeing changes
in the resource types, increases of solar and wind and decreases in gas and coal. And
far as the WECC greenhouse gas forecast, compared to history, you're seeing a large
decrease over time. Since 1990, we're seeing a decrease of 135 million metric tons. And
then in the forecast from 2026 until 2045, you're seeing another decrease of 129 million
metric tons. And at the end of the day, this is the result of the price forecast. It's basically
mid-C prices.

Appendix A
Lori Hermanson: We created slightly different zones in Aurora this time compared to last
time. Formerly, we had an Oregon, Washington, northern Idaho Zone, but with the CCA
going into effect this time we broke it out a little bit differently. We have Washington with
and without CCA. And then Avista, which is Eastern Washington, northern Idaho, trying
to model based on different resources that could be selling into our market with or without
CCA. At the end of the day, the levelized prices are around $48 [per MWh] with CCA
around $45 without CCA, and about $42 for our Avista zone and contrasting that with our
last IRP, I think our levelized prices were about $35. This price forecast includes quite a
bit of expected additional resources in those early years between now and 2030. That's
a lot of resources to get built and online and permitted. If those don't come to fruition,
these prices would likely be much higher.
James Gall: Lori, I want to add one thing to that last slide and address the prices falling
like you mentioned from all these new resources coming online at least projected to be
coming online and then the price is bumped back up you can see in 2031. This has to do
with our assumption on how allowances will be distributed by the CCA in the future. The
law allows for a change in 2031 of how allowances are distributed to utilities and we're
assuming at that point in time the projects in the State of Washington would have to
include some type of price, the CCA price in its dispatch. The big change there is that
assumption that any generator in the State of Washington would have a carbon price in
its dispatch versus before that it's just plants that don't have free allowances or importing
into the state. So that's the cost of the big change.
Lori Hermanson: Thanks James.
James Gall: Yep.
Heather Moline (UTC): Sorry. Can you repeat, Lori, the kinds of new resources you're
talking about?
Lori Hermanson: The kinds of new resources let me hop back here. Whoops, sorry.
These are the new resources that were selected from this deterministic run, and this is
excerpts over time, 2030 through 2045. Most of the resources being selected are solar
and wind, some storage. Those are the big contributors. See a little bit of offshore wind
over time, but again are based on generic resources. What we actually acquire could be
very different because if we go short, or if we're predicted to be short, we would issue an
RFP and the people that submit for an RFP could be very different types of resources or
mixes than what we're showing here. We put in generic resources and this is what's being
selected.
James Gall: And this is selected for the West region, not Avista.
Lori Hermanson: Yes.
James Gall: Just to be clear, this is California, this is Arizona, Wyoming, Colorado,
Washington, Oregon. This is not Avista's preferred mix. This is what would likely serve
the greater region. Just to be clear.

Appendix A
Heather Moline (UTC): Thanks.
James Gall: Yeah.
Lori Hermanson: Oops, sorry I went too far. OK, this is basically the same price we just
showed, but by season, and this these shapes are very similar to what you saw in the last
IRP. A lot of it makes sense. Spring you see it suppressed because of runoffs and all of
them you see prices suppressed in the middle of the day. That's because solar comes
up. Then you see these evening peaks as solar drops off and people are coming home
from work and plugging in their EVs or that sort of thing. These are very similar to what
we saw in the last IRP.
Lori Hermanson: Finally, well, I guess I have one more slide after this, but this is
comparing the prices that we showed earlier in the flat delivery without CCA, the flat
delivery with CCA, and the Avista prices for those zones compared to a couple of our
consultant's prices. I think one of the consultant's price forecast was done in December
and I think the other one was done in July. This is just to compare results. Finally, these
are all of our IRPs since 2005, the black line is actual prices.
Lori Hermanson: This dotted black line is our draft electric price forecast for this IRP and
all these other, I mean basically at the end of the day, shows that a price forecast is very
difficult to predict what the mid-C prices are going to be. Of all these IRP that we've done,
there's six points in time, not six forecasts, but six points in time where we actually got it
right. It's just added context here, but it's difficult to forecast and it's based on all these
inputs that are best informed to help determine what the prices are going to be. But at the
end of the day, they're likely not right. That's why we do these price sensitivities and
scenarios that James will be presenting next. That's everything I have. What's left in the
process? We're going to connect our stochastic studies. We'll finalize our deterministic
and stochastic case based on if we need another capital expansion run. Finally, we'll run
scenarios and that's all I have for today. Are there any other questions?
James Gall: Looks like Heather has got a question.
Heather Moline (UTC): Yep, I'm back. Thank you, Lori. I don't know if this is for Lori
actually. Do the slides on lower 48 demand for gas North American supply for gas,
regional demand for gas Pacific versus mountain, those don't get used in the IRP. Right.
James Gall: Correct. They're context of what the national forecasters are assuming,
which basically are used to help develop those natural gas price forecasts.
Heather Moline (UTC): Yeah. OK.
James Gall: They run a model. These consultants, they run a national model for demand
of natural gas and that develops a price, and that price then is input into our Aurora model.
Heather Moline (UTC): Got it. That was going to be my next question. Is the thing that
they're relevant for is that price forecast and you just answered that. Thanks.

Appendix A
James Gall: If the future was we're going to build a bunch more gas turbines, then maybe
that would drop pricing. And for natural gas, if there was so much more demand than
there was supply as an example, so.
Tom Pardee: Hey, Heather, if I can add more context to that. Think of that as just one of
those forecasts that we use too. As Lori showed on the slides for price forecasting, those
are all we have, different forecasts from different entities like the EIA or a few consultants
in a forward price. We don't know what the price is going to be, but the law of averages
basically states the more you have, the better it's going to be. But this is just one point
out of the four points I believe that we used for the single price forecast. It's really just to
give context. If I were to show you our other consultant, it's mostly the same and just
came out more recently. It's just really contexts around, overall that they are expecting
less gas use in our area. That's kind of the one to one of why prices are doing what they
are.
Heather Moline (UTC): OK. Thanks.
James Gall: OK. Molly had a question. Go ahead Molly.
Molly Brewer (UTC): Yeah, this is going way back to that set of questions earlier for
resource adequacy from that cold event. How are we meant to go about answering those
questions. I just have follow up questions on them like how would we know if 1% or 5%
probability is more reasonable things like that?
James Gall: I think the expectation of reliability needs to be somewhat directed by the
Commission and that's my opinion. The utility is responsible for being able to provide a
reliable service. I think there's a level of expectation of what that is now. I think there's
also a level of expectation you're not going to overbuild your system. We've always looked
at what's the industry standard for reliability, but it seems to me that consumer
expectations are changing. Of what they expect. So, I think it's a broader question of what
is appropriate for resource adequacy. I mean another example, WRAP set a standard,
but is that standard the right standard of what our customers want? I don't know if there's
an answer to that without having regulatory bodies or legislature saying this is what we
expect. Otherwise, we're going to propose something and it's whether or not the
Commission agrees with what we propose. I don't know.
Molly Brewer (UTC): Yeah.
James Gall: If that's helpful or not, but Yep.
Molly Brewer (UTC): No, I mean that is because I just don't know. What's the standard
we're using to answer these questions?
James Gall: Yeah, there is no right answer, unfortunately.
Molly Brewer (UTC): That helps me understand the context of asking those questions.

Appendix A
James Gall: Yeah. Whether or not we use an example day as a resource adequacy
standard. I think it's good practice to show that and it helps policymakers understand what
they're getting into. If we build a bunch of four-hour batteries and rely on wind and solar
and we have an event like this, you can see we can't serve it. That is a good indication
why we need to look for longer duration storage or rely on natural gas. These are good
examples to show to understand what the results are of decisions that get made in these
planning processes. Unless there's any other questions, we were going to wrap up by 10.
Portfolio and Market Scenarios Options, James Gall
James Gall: I think we did reserve another 30 minutes on everybody's calendars for this
meeting because we weren't quite sure on the time, but I'm not going to take that 30
minutes because the scenario section was really just to go over what we're thinking and
let you all chew on that for a while, because we're going to actually cover scenarios in
more detail at a future meeting. And let me look up when that is, John had shown that
earlier, but I need to look it up again.
James Gall: We're going to cover the final scenarios at least the list and descriptions in
TAC 7, but the document we sent out is a description of what we're thinking right now and
how this works. We have 19 scenarios right now, or 18 if you don't include the expected
case, and then under sensitivity this refers to what price forecast we would be using.
That's that Aurora price forecast that we will be studying with each of these portfolio
scenarios. Then we have an LOLP study. This represents which of these portfolios will
undergo our reliability test to look at what's 5% loss of load probability or 1% if we ended
up going there in the future. This is our list. We also have a description of each of the
scenarios here.
James Gall: What we'd like the TAC members to do if you want to see something else
besides these, you want to add, please let us know. Or if you don't think that one of these
scenarios is useful, that's also feedback. But I'm trying to figure out when we wanted
feedback. John, I don't know if you remember. I was looking at our Work Plan when we
needed to get feedback from everybody on the scenario list. If you had that in your
memory or not?
John Lyons: Not off the top of my head. I'm looking really quick.
James Gall: OK, I think I'm there. It is March now that would be today. We have got to
push that out.
John Lyons: OK.
James Gall: Our Work Plan had it today, but if you have comments maybe next 30 days
for the scenario list, provide those to us. If you want to see something different. Or in
addition to these, we had some proposed ones that are on here as well, if that's something

Appendix A
you're interested in. We cover what some of the information is on what the targets are on
the bottom of what some of these scenarios are.
James Gall: So, with that, are there any questions, thoughts that people have? OK.
Alright, so hopefully everybody likes the new TAC schedule of every two weeks. That's
what we're going to be moving to going forward and the next couple TAC meetings are
really going to concentrate on our load forecast, which I kind of given a clue earlier on. It
will be a higher load forecast than we've seen in the past and we'll then go forth and figure
out what our availability is for energy efficiency, what resource options we have, what our
net position is over the next couple of months. By early summer, we should have some
resource selection and show you what types of resources are going to be needed and
when. It'll be for our team at least a very strenuous next probably three months, lots of
work to get done. It's crunch times for us.
James Gall: If there's no other questions or comments, I guess we'll call it a day.
Heather Moline (UTC): Sorry, James.
James Gall: Yep.
Heather Moline (UTC): Heather here. That list of scenarios, where does that live? Or is
it at the end of the presentation?
James Gall: Yeah, it is at the end of presentation we emailed out. We'll also post that to
the website today or tomorrow. It's also out on the Teams site as well.
Heather Moline (UTC): Thank you.
James Gall: OK, have a great day everybody. We'll see you next week at the DPAG
meeting, hopefully. Bye, bye.

A endix A
Vop
2025 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 4 Agenda
Tuesday, April 9, 2024
Virtual Meeting — 8:30 am to 10:00 am PTZ
Topic Staff
Introductions John Lyons
Future Climate Analysis Mike Hermanson
Economic Forecast & Five-Year Load Forecast Grant Forsyth

�I�r r/ISTA
2025 IRP TAC 4 Introductions
John Lyons, Ph.D.
Technical Advisory Committee Meeting No. 4
April 9, 2024

Appendix A
Today's Agenda
Introductions, John Lyons
Future Climate Analysis, Mike Hermanson
Economic Forecast & Five-Year Load Forecast, Grant Forsyth
2

Appendix A
Remaining 2025 Electric IRP TAC Schedule
• TAC 5: April 23, 2024: 8:30 to 10:00 (PTZ)
o Long Run Load Forecast (AEG)
o Review Planned Scenario Analysis
• TAC 6: May 7, 2024: 8:30 to 10:00 (PTZ)
o Conservation Potential Assessment (AEG)
o Demand Response Potential Assessment (AEG)
• TAC 7: May 21 , 2024: 8:30 to 10:00 (PTZ)
o Variable Energy Resource Study
o Portfolio/Market Scenarios
• TAC 8: June 4, 2024: 8:30 to 10:00 (PTZ)
o Load & Resource Balance and Methodology
o Loss of Load Probability Study
o New Resources Options Costs and Assumptions
• TAC 9: June 18, 2024: 8:30 to 10:00 (PTZ)
o IRP Generation Option Transmission Planning Studies
o Distribution System Planning within the IRP & DPAG update
3

Appendix A
Remaininq 2025 Electric IRP TAC Schedule
• Technical Modeling Workshop: June 25, 2024: 9:00 am to 12:OOpm (PTZ)
o PRiSM Model Tour
o ARAM Model Tour
o New Resource Cost Model
• TAC 10: July 16, 2024: 8:30 to 10:00 (PTZ)
o Preferred Resource Strategy Results
o Washington Customer Benefit Indicator Impacts
o Resiliency Metrics
• TAC 11 : July 30, 2024: 8:30 to 10:00 (PTZ)
o Preferred Resource Strategy Results
o Portfolio Scenario Analysis
o LOLP Study Results
• TAC 12: August 13, 2024: 8:30 to 10:00 (PTZ)
o Preferred Resource Strategy Results (continued)
o Portfolio Scenario Analysis (continued)
o LOLP Study Results (continued)
o QF Avoided Cost
4

Appendix A
Remaining 2025 Electric IRP TAC Schedule
• September 2, 2024- Draft IRP Released to TAC.
• Virtual Public Meeting- Natural Gas & Electric IRP (September 2024)
o Recorded presentation
o Daytime comment and question session (12pm to 1 pm- PST)
o Evening comment and question session (6pm to 7pm- PST)
5 ins

�iivlSTA
v1prw-
IRP Climate Change Analysis
Forecasted streamflow and temperature changes for 2025 IRP
Analysis

M Appendix A
Overview
• Data sources and methodology
• Hydrogeneration
• Temperatures for load forecast
• Temperatures for peak load forecast
°iw�sra

Data Sources Appendix A
• Climate and Hydroloav Datasets for RMJOC •
Long-Term Planning tudies: Second Edition —�
River Management Joint Operating Committee •
I
(RMJOC)
BPA, US Army Corps of Engineers, US Bureau of
Reclamation .,
Research Team •�' '• « • • •
University of Washington, Oregon State University • ;
• •
• Part I — Unregulated stream flows ••� •
' mow+' • j = ♦• ••
• Part II — Reservoir Regulation and Operations �• •��•� •
• Wind data — University of California-Merced
Data from 20 climate models downscaled using
the MACA (Multivariate Adaptive Constructed
Analogs).
4-4VISTA

Global Climate Models Appendix A
• Global Climate Models (GCMs)
Emissions Scenarios
Coarse resolution ranging from 75 to 4 Representative Concentration Pathways (RCPs)
300 km grid size Y
- Provides. projections of temperature Rcft
and precipitation, and other 12 RCP8.5: mactws 8 S w;m by 2100
meteorological variables (wind)
'0
Multiple Representative
Concentration Pathways (RCP 4.5 & • -
RCP 8.5) e
• 10 GCM models used in study s RCP6.0- stabilizes at -6 0 w/m' by 21SO
- CanESM2 (Canada)
- CCSM4 US � 4 RCP4.5: stabilizes at -4.S w/ml by 2100
( )
- CNRM-CM5 (France) � 1 �~
2 RCP2.6: peaks at -3.0 w/m, in -2040,
- CSIRO-Mk3-6-0 (Australia)
- GFDL-ESM2M (US) declines to -2.6 w/w�' by 2100
0
HadGEM2-CC (UK) A.
H ad G E M2-ES (UK) 1800 t 900 2000 2100
- inmcm4 (Russia)
IPSL-CM5-MR (France)
M I R005 (Japan)
4 �iiVISTA

Representative Concentration Pathways AppendixA
• Description by Intergovernmental Panel on Climate Change (IPCC)
RCP2.6 - stringent mitigation scenario
RCP4.5 & RCP6.0 - intermediate scenarios
RCP8.5 - very high GHG emissions
• RMJOCII Study evaluated RCP4.5 and RCP8.5
• RCP4.5 and RCP6.0 similar likely range by the end the IRP planning
horizon
rangeLikely Likely range
Global Mean RCP2.6 1 .0 0.4 to 1 .6 1 .0 0.3 to 1 .7
Surface RCP4.5 1.4 0.9 to 2.0 1.8 1.1 to 2.6
Temperature
Change (C°) RCP6.0 1.3 0.8 to 1.8 2.2 1.4 to 3.1
RCP8.5 2.0 1 .4to2.6 3.7 2.6to4.8
�iiVISTA

Downscaling Techniques Appendix A
�1
• Downscale GCM data to
finer resolution necessary
to model hydrology
Statistical methods to l
represent variation within i I- -
large grid size - ti
Two methods used (BCSD,
MACA)
Bias Corrected Spatial -� -
Disaggregation
Multivariate Adaptive
Constructed Analog G
' Al
. .........
�ii I STA

ModelingClimate Change Impacts on Hydrogeneration
d
• Hydrologic models rainandsnow ralnandsnow
Interception interception
• Downscaled temperature and precipitation ,
is input to hydrologic models.
• Hydrologic models use soil, geology,
slope vegetation aspect snow cover, etc. ----- ------ ----- ----------------
to model how precipitation translates into 2-laye*now Juno! 2-layers imps^i us:one runof
runoff and streamflow. '
r
sort moisture subsurface
flux recharge zone ; zone
2 different hydrology models used.
lower zone .�.
� :subsuA3te nrcrl+on
+ soil rechalue
1 version of PRMS model zone
3 versions of VIC model groundwarer
rcchargc
34ayer soil aquifer lmfflbasellow
• Hydro regulation models
Unregulated streamflow is input to
VIC PRMS
reservoir models of Columbia River system
to generate regulated flows.

ModelingClimate Change Impacts on Hydrogenerabon
d
4 hydrology models:
to transform precipitation to streamflow
10 BCSD VIC-P1 GCMs
10 BCSD VIC-P2 GCMs
2 downscaling methods: 10 BCSD VIC-P3 GCMs
for finer spatial scales
10 BCSD GCMs —H10 BCSD PRMS GCMs
80
10 GCMs climate
10 MACA GCMs scenarios
10 MACAVIC-P1 GCMs
10 MACA VIC-P2 GCMs
10 MACA VIC-P3 GCMs
10 MACA P RMS G CMs
°w�sra

2025 IRP Hydrogeneration Appendix A
• BPA selected 19 of the 80 scenarios that encompass a sufficient range
of uncertainty.
• Three regulated river flow data sets utilized :
BPA 1929-2018. Most recent data available from BPA for each Avista project.
2019 utilized actual flow.
2020-2045 used climate change data set.
• Median of 19 BPA selected scenarios was used in the flow data set.
• All flows were combined into one data set (1929-2045) and ran in
Plexos to estimate generation for Noxon, Cabinet, Long Lake, & Little
Falls
• Run-of-river projects were estimated utilizing regression analysis based
on historical relationship of river flow and generation .

Results Appendix A
Comparison of Annual (aMW) of Avista Hydro Projects
• • Recent 30-YearChange
Mean 446 459 472
Median 363 390 408
Standard 224 204 211
Deviation
10tn
Percentile 227 276 262
Note: Does not include Mid-C due to contractual changes during planning horizon that impact generation quantities
• Recent 30-year shows slight increase in annual energy
• Climate change scenarios show an increase in annual energy consistent
with the projection of overall increase in precipitation in the Northwest
10 ,9-=HIMSTA

Results
2024-2045 Trend Appendix A
January March
600 600
500 500 ..... .......... ...........
400 400
m 300 m 300 —
200 200 —
100 100
0 pp �p 0 a �p
N N co N N N M M M M M M Cl) M M a a 7 a a N N CO N N N M M M M M M M M M M a a a 7 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
N N N N N N N N N N N N N N N N N N N N 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 Models 90 Year -30 Year ..... .
Linear(Climate Models) -Climate Models 90 Year -30 Year ......•••Linear(Climate Models)
February April
600 800
700
500
................... .. ......... ........
..... ........................ ..................................... 600 ......
400 Oe 500
m 300 m 400
300
200
200
100
100
0 0
N N N N N N M M t+N1 M t+N1 M M co t+01 V 7 C -IT 7 10 N N N N N N CO M M Cl) Cl) CO v a a a 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 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
Climate Models -90 Year -30 Year ......•••Linear(Climate Models) -Climate Models -90 Year 30 Year ......•••Linear(Climate Models) /III_
11 �drVISTA

Results Appendix A
2024-2045 Trend
May July
1000 700
900 ..... ............. ........ ............................ ..... ....................... .......... ........ ......... ............
600
800 v A 4.
700 500 .............
600 IIA
400 .............
m 500 m
300 v V
400
300 — 200
200 —
100
100
0 0
N N N N N N M M M M M M M M M 7 7 7 a a N W CD N N N N N M M M M M th coco coa a a a e
O O O O O O O O O O O O O O O O O O O O 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
Climate Models -90 Year -30 Year ......•••Linear(Climate Models) Climate Models -90 Year -30 Year ......•••Linear(Climate Models)
June August
1200 400
350
1000
.... ... 300 ••
800 .... ..... ........ ........ A
250
m 600 m 200
150
400
100
200
50
0 p 0 �p
N N N N N N M M M M M M M M coa a a a a N N N N N N M M M M M M M M M 7 7 7 7 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
N N N N N N N N N N N cm N cmN N N N N N 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 Models -90 Year -30 Year ......•••Linear(Climate Models) Climate Models -90 Year -30 Year ......•••Linear(Climate Models)
2 ,9-IIII I STA

Results Appendix A
2024-2045 Trend
September November
350 - 450
400
300
................ ....... .. ......
250
.....
300
3: 200 250
m m
150 200
150
100
100
50
50
0 p 0
N NNMMMM N NN M MN co N M M M 7 7 N N N Cl) �p
M M M 7
NNNNNNNNNNNNNNNNNNNNN NNNNNNNNNNNNNNNN. 7 7 7 7
N N N N N
-Climate Models -90 Year -30 Year ......•••Linear(Climate Models) -Climate Models -90 Year -30 Year ......•••Linear(Climate Models)
J i
October December
400 500
350 450
400
............. ..............................
350
250 300
m 200 m 250
150 200
150
100
100 —
50 50
0 N N N N N N M M M M M M M M 7 a 7 7 7 7 0
N N N N N N M M M M M t0 M Cl) M t 7 7 4
N NNNNNN NNNN N NNNNNNNNNN N N N N N N NN N N-Climate Models -90 Year -30 Year ......•••Linear(Climate Models) -Climate Models -90 Year -30 Year ......•••Linear(Climate Models)
13 ,AiiVISTA

Appendix A
Climate Change Temperatures for Load Forecast
• Data:
Daily max and min temperature for Spokane airport through 2045 that
correspond to the 19 BPA scenarios.
Data for both RCP4.5 and RCP8.5
• Temperatures for load forecast will use RCP4.5 for January —
May and October — December, and RCP8.5 for June —
September.
• Approach will allow representation of increasing temperatures
over the IRP period without losing cold events that are
important to plan for.
14 �ii I STA

Appendix A
Climate Change Temperatures for Load Forecast
RCP4.5/RCP8.5 Hybrid
8000
Actual Modeled
7000
Q 6000
2
c
5000
0 4000
U
c
3000
Q
2000
1000
0
110 r oo a) O r-I N M �t Ln �.D r` oo a) O r-I N c» R* Ln �O r 00 rn CD r-I N M � Ln
-I r r-I r-I r-I N N N N N N N N N N fM ro M ro ro M ro M M M � Rt R* Rt
O O O O CDO O CDO O O O O O O O CDO 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
-Annual HDD -Annual CDD
15 ,aliiVISTA"

C limate Change to Peak Load Appendix A
• Peak load model utilizes minimum/maximum daily average
temperature for each season .
Winter — January through May, and October through December
Summer — June through September
• Winter uses RCP 4 .5 and Summer uses RCP 8.5
• Median of minimum/maximum average daily temperature for
each season of all models.
• Winter peak is based on a 76-year* moving average, summer
peak is based on a 20-year moving average.
* Location for Spokane temperature data changed in 1947. Onl
16 �ii�1WISTA

G limate Change to Peak Load Appendix A
Seasonal Daily Average Annual High Temp RCP8.5
110
105 •
20 Year Rolling Average of Actual and Median of modeled values 0
•
Actual Temperatures •
•
100 • •
95 • '
90
85 86.76 T
IT
80
84.47°F '
75
(D NT D000N (DDCOON V wCO0N V w000cli w COON V CDCDO N V (D000N CDC ON V w 000N � CD
01 � G) 01) 1 � O� � G~) � d~� C� � � � � G�� � � � � � � SSSSS000000000000000 � ;S09
r r N N N N N N N CN N . N N N N N N N N N N N N N N
• Peak load estimate is a 1 -2 event
17
°lHIMSTA

C limate Change to Peak Load Appendix A
Seasonal Daily Average Annual High Temp RCP 4.5
20 Year Rolling Average of Actual and Median of Modeled Values
Actual Temperatures
95
•
90
< < I < lr
•
•
85
1 I 85.72 T
Eo < < l l
85°F
75
• Peak load estimate is a 1 -2 event

C limate Change to Peak Load Appendix A
Seasonal Daily Average Annual Low Temperature RCP4.5
JU
76 Year Rolling Average of Actual and Median of Modeled Values
40 Actual Temperatures
30
Zo
1 t
10
� < <
5.63 °F
T �
-10
3.98°F 1
-20 � •
0
-30
-40 pp O J � o OO �p pp m m SO �rCO O - O coC ON NpoM
O ; ONO M M "T �
0) 0) 0) 0) 0) 0) 0) 0) O 0) 0) 0) O 0) 0) 0) OOOO O OO
� O O O N N N N N N N N N N CV N N N CV N N N (V N ON NO
ON O
• Peak load estimate is a 1 -2 event
19 �iIVISTA

Climate Change to Peak Load Appendix
Seasonal Daily Average Annual Low Temperature RCP8.5
so
76 Year Rolling Average of Actual and Median of Modeled Values
Actual Temperatures
40
30
•
zo � lr • , � l _ � r
10 i,JL Jr F�i■M
6.07 T
10 4.05°F l 1 • .
-z0
-30
-40
^0�3',ohs�o 10 �o�^off�ooti^oeA�o�^off le,o1ry,°j�A^0�6,°�10^00°1�e��oeA Ice^off 10P,00�1ooa 10^off roc§'�o��ocP�c�P�000�,�tio�ry ^a do^��.��tio ti°��ti����ti0���^��lf�? 16�le tioA�leA
• Peak load estimate is a 1 -2 event
20 �uVISTA"

C limate Change to Wind Generation Appendix A
• Evaluated modeled wind speed in the north/south and east/west direction for a
historical time period (1950-2005) and climate futures using the RCP4.5 and
RCP8.5 (2006-2099) for the location of our Palouse Wind Project.
Average Daily Wind Speed East Monthly Maximum Daily Average Wind Speed North Monthly Maximum Daily Average Wind Speed South
6.00 10.00 0.00
9.00 -0.50 1 2 3 4 5 6 7 8 9 10 12
5.00
8.00
L -1.00
2 4.00 Q 7.00 a
E -1.50
E 6.00
a
v 3.00 all 5.00 a -2.00
CL
vai 2.00 4.00 -2.50
3.00 -3.00
1.00 2.00
-3.50
0.00 1.00
5 6 7 8 9 10 11 12 2/3
o.00 -a.00
_1.00 1 2 3 4 5 6 7 8 9 10 11 12 -4.50
-Historical 1950-2005 -RCP 4.5 2006-2099 -RCP 8.5 2006-2099 -Historical 1950-2005 -RCP 4.5 2006-2099 -RCP 8.5 2006-2099 -Historical 1950-2005 -RCP 4.5 2006-2099 -RCP 8.5 200E-2099
Average Daily Wind Speed North Monthly Maximum Daily Average Wind Speed East Monthly Maximum Daily Average Wind Speed West
5.00 12.00 0.00
4.50 -0.50 1 2 3 4 5 6 7 8 9 10 11 12
4.00 10.00 L -1.00
L Q
E 3.50 E 8.00 E -1.50
3.00 j -2•00
v a� 6.00 Q
ar 2.50 a N -2.50
a
2.00 4.00 c_ -3.00
1.50
-3.50
1.00 2.00
-4.00
0.50 0.00 -4.50
0.00 1 2 3 4 5 6 7 8 9 10 11 12 -5.00
1 2 3 4 5 6 7 8 9 10 11 12 Historical 1950-2005 FRCP 4.5 2006-2099 FRCP 8.5 2006-2099 Historical 1950-2005 -RCP 4.5 2006-2099 -RCP 8.5 2006-2099 -Historical 1950-2005 -RCP 4.5 2006-2099 -RCP 8.5 2006-2099
muff W W..W a A �

IRP Climate Change Approach Summary Appendix A
• Proposed approach utilizes both RCP 4.5 (winter) and RCP 8.5
(summer)
Description by Intergovernmental Panel on Climate Change (IPCC)
- RCP2.6 — stringent mitigation scenario
- RCP4.5 & RCP6.0 — intermediate scenarios
- RCP8.5 — very high GHG emissions
RCP4.5 & RCP6.0 are similar in IRP planning horizon
• Hydro eneration — Proposing to utilize latest BPA regulated flows
(1929--2018), one year of actuals and median of BPA selected climate
models. Monthly y w w r in Pl x develop
odes o s were used a os to de a op
• Peak Load Forecast — Proposing to use moving average of previous
20 years (summer peak) and 76 years (winter peak).
Used seasonal peak temperature (low and high)
22 �i'i I STA

V
�STN�wTAC Meeting April 9, 2024
2025 IRP : Economic Conditions and Preliminary
Medium -Term Forecasts
Grant Forsyth, Ph.D.
Chief Economist
[e-mail]

• Appendix A
utline
0 Service Area Economy
0 Medium-Term Energy Forecast (Spring 2024)
"This presentation is 40 minutes of a finite life you will never get back. "
-Grant Forsyth, April 9, 2024.
2

Service Area Economy: Non =Farm Employment Structure
Avista WA-ID MSA U.S.
Private Private Comments
Government Goods Government Goods
17% 14% 15% � 14i Employment structure very
similar to the U.S.
• Employment dominated by
private services. Without
service sector growth, very
little employment growth
Private will be generated.
Private Services
Services 71% Majority of public sector
69% employment is local and
related to education.
• If agriculture is considered, it
Avista WA-ID MSA Government U.S. Government would account for about 1%
Federal Federal to 1.5% of employment.
10% 12%
State
23% State
23%
Local
Local 67/
65%
3 Source: BLS and author's calculations.

Appendix A
Service Area Economy: Non =Farm Employment I-.j
AMMIII
12% Comments
• Region has recovered from
> 10% the pandemic faster than
the U.S.
o Growth has been strongest
v g% on the ID side.
• WA-ID employment growth
o has remained relatively
6% strong, even with the rapid
a,
£ rise in interest rates.
ra
4%
v
o 2%
L
fC
0%
r-I r-I r-I r-I rI r-I ri ri N N N N N N N N N N N N M M M M M M M M M M M M R* q*
N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N
�> c aGA Q > u c M > c abA ?. + > u > c a Q. + > u c -0
th o � a LA o ; LLa oz oz oz o
Avista WA-ID MSAs U.S.
4 Source: BLS, WA ESD, and author's calculations.

Service Area Economy: WA=ID Metro Population Growti-P.
2008-2012: Employment 2013-2017: Employment
Growth Slowing= Slowing Growth Increasing=
2.5% In-migration Increasing In-migration
Comments
• Population growth drives
2 0% most of our customer
growth.
00000 • Significantly higher than
U.S. growth because of in-
s 1.5% migration. Without in-
migration, growth would
o look like U.S. or be lower.
V
3 1.0% • Growth is highest on the ID
side.
Q • Strong employment growth
is correlated with strong
0.5% population growth...but
• Historical relationships
may be changing due to
0.0% high housing prices, but it's
not clear at this point.
2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023
Total Spokane+Kootenai+Nez Perce-Asotin, WA-ID MSA Pop. Growth ■ U.S. Pop. Growth
5 Source: BEA, U.S. Census, and author's calculations. ,

Service Area Economy: Spokane+ Kootenai
Residenti�WAppendixA
Units Permitted
8,000 Comments
• Strongly connected to
7,000 — population growth.
• Held up surprisingly well
6,000 - given increase in interest
rates.
v 3,966
5,000 — Prices of single-family
v2,380 2,691 2,327 housing have not declined
a 4,000 — significantly. The supply side
1,719 1,151 1,482 2,172
remains constrained.
3,000 1,205 Apartments and duplexes are
still and important source of
2,000 new housing in both WA and
3,252 3,246 3,237 3,214 ID. Duplexes are counted as
3,142 3,043 3,133 2,781 "single family" in the graph.
1,000 2,484
• Starting this year, ADUs are
0 now covered by Construction
Monitor.
2015 2016 2017 2018 2019 2020 2021 2022 2023
Total Spokane+Kootenai Single Family, WA-ID Total Spokane+Kootenai Apartments, WA-ID
6 Source: Construction Monitor and author's calculations. ,

Appendix A
The Energy Forecast : Basic Approach
Time
AL
2024 2028 2029 2045
Medium-Term Long-Term
f I
1) Monthly econometric model by 1) Shifting to end-use modeling.
schedule for each customer class. 2) Being handled by AEG with a few assumptions
2) Customer and UPC forecasts. from Avista.
3) 20-year moving average for "normal
weather."
4) Economic drivers: GDP, industrial
production, employment growth,
population, natural gas penetration.
5) Native load (energy) forecast derived
from retail load forecast.
6) Current 2025 IRP forecast is the
Spring 2024 Forecast (completed in
March).
7

MediummTerm Forecast : Ba
Appendix A
Approach
.A
In-house Forecasts Averaged with S&P Connect
I -
I Certain
Employment Population I
I Growth Growth I =>
Residential and
I Forecast Forecast I Commercial
I Forecasts
"Consensus" GDP (- - - - - - - - - - -
- - - - - -
Growth Forecast
L Industrial Certain Industrial
Production
UPC Forecasts
Growth Forecast
20-Year Moving
average of DDs and Certain Residential and
Residential Gas Commercial UPC
Penetration (WA) Forecasts
8

7ilss tio GDP Growth Assumption
9i f2r
Comments
7%
• Long-run growth is the sum of
6% 5.6% population growth and labor
productivity growth.
5%
• U.S. continues to have weak
4% productivity growth and weak
2.9% 2 9% population growth.
3% 2.5% - 2.4% 2.4% 2.5%
3 2.1% 2.1% The Fed's long-run
1.9%
2� 1.7% 1.7% 1.90� expectation for GDP growth
has fallen from 2% to 1.8%
a 1% 1•9% (red line). This is the growth
rate assumed from 2029 to
0% 2045.
Long-run GDP growth must
-1� exceed 1.6% for industrial
2% load to grow.
-3% -2.2%
2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024E 2025E 2026E 027F 2028E
1.8% after 2028 (AEG)
9 Source: Various and author's calculations.

Appendix A
Economic Assumptions : Population
Long-Term (AEG)
2.5% 1 Annual Annual
Growth, Growth,
11
1 11
1 11 04
1 11
1 1
° 20231RP* 1.1% 0.8%
1 � 1
1 2025 IRP 1.2% 0.6%
1
1 11
3 1.5%
0 2025 WA 0.9% 0.3%
1 11
1 11 2025 ID 2.0% 1.4%
3 1 11
1 1 * Spring 2022 forecast in 2023 IRP
a 1.0% 1 000t
1 11 Comments
I
1 From 2029 on, the time-path
1 11 reflects S&P 500 Connect
0.5% 1 population forecasts.
1
1 11 Average population growth is
1 a proxy for customer growth.
1
0.0% - -
rl iNi iM-I i�-I i�-I i^-I i�-I N N N N N N N N N N M M M M M M M M M M ICT ICT ICT ICT ICT ICT
O O O O O O O O O O O O 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
WA-ID Avista Metro Area —U.S.
10 ,
Source: BEA, U.S. Census, S&P 500 Connect, and author's calculations.

Appendix A
MediummTerm Energy
mmdA
Avg. Annual
Growth, 2024-
1,150 1,147 2028*
1,145 1,143 1,144 1,146 1,145 2023 IRP 0.59%
1,140 1,140 2025 IRP 0.22%
LA 1,135 * Spring 2022 forecast in 2023 IRP
1,135 1,132
M
3
1,130 Comments
1,126
• The difference reflects a
1,125 step up in residential
1,121 UPC starting in 2022,
a 1,120 forecasted declining gas
penetration in WA, and
1,115 higher forecasted
industrial loads.
1,110
• No significant difference
1,105 by 2028.
2024 2025 2026 2027 2028
■2023 IRP Native Load ■ 2025 IRP Native Load
11

2005p endix A
MediummTerm Energy Forecast: Native Load since
1,170
Comments
1,150 Prior to 2021/2022, the
' �, 0 housing bubble period
1,130 was the last significant
��. 00
LA 10 step up in native load.
4-0
3 1,110 A� '' The hybrid work
environment will have
1,090 ` �� some permanence, but
commercial buildings
tW
still need to be heated
1,070 and cooled.
Q
• Dashed black line
1,050 reflects an adjustment
for a specialized contract
1,030 with a large customer
with self-generation.
1,010
Ln to n 0o C1 O N M Ln to n 00 Q1 O r-I N M LA to N 00
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
Native Load 2025 IRP Native Load 2023 IRP Native Load Average 2005-2007
Average 2008-2020 Average 2021-2023 Average 2024-2028
12 al

Medium -Term Retail Forecast: Washington vs . Idaho
WA forecast explicitly assumes residential gas penetration
continues to fall. This generates a slightly different time-
path in the forecast compared to ID
NEENEENEEN- MEMO-.
NONE N,
I �
. I I 'VE11LAAMENNEEN
NEEMBEENNEENNEEN
NEENNEENEENEEN
. �
. � �
■ MEN ■■
- - - - - - - - - - - - - -

Appendix A
Questions ?
14 �

Appendix A
TAC 4 Meeting Notes, April 9, 2024
Attendees:
Diana Aguilar, Fortis BC; Andres Alvarez, Creative Renewable Solutions; Soyfa
Atitsogbe, UTC; John Barber, Customer; Shawn Bonfield, Avista; Kim Boynton, Avista;
Tamara Bradley, Avista; Annette Brandon, Avista; Kate Brouns, Renewable
Northwest; Michael Brutocao, Avista; Katie Chamberlain, Renewable Northwest; Josie
Cummings, Avista; Kelly Dengel, Avista; Joshua Dennis, UTC; Paul Dietz; Grant
County PUD; Mike Dillon, Avista; Nelli Doroshkin, Invenergy; Chris Drake, Avista;
Michael Eldred, IPUC; Rendall Farley, Avista; Ryan Finesilver, Avista; Damon Fisher,
Avista; Grant Forsyth, Avista; James Gall, Avista; Bill Garry, Customer; John Gross,
Avista; Leona Haley, Avista; Tom Handy, Whitman County Commission; Shaun
Harrington, Grant County PUD; Kyle Hausam, Avista; Mike Hermanson, Avista; Fred
Heutte, NW Energy Coalition; Allison Jacobs, PSE; Erik Lee, Avista; Dan Lively,
Clearwater Paper; Mike Louis, IPUC; John Lyons, Avista; Patrick Maher, Avista; Jaime
Majure, Avista; James McDougall, Avista; Heather Moline, UTC; Molly Morgan, UTC;
Paul Nichols, PSE; Michael Ott, IPUC; Tom Pardee, Avista; Michael Reimers, Grant
County PUD; John Rothlin, Avista; Nathan Sandvig, Avangrid; Ryan Sherlock,
Avangrid; Amanda Silvestri; BPA; Darrell Soyars, Avista; Dean Spratt, Avista; Victoria
Stephens, IPUC; Lisa Stites, Grant County PUD; Jason Talford, IPUC; Brandon
Taylor, PSE; Charlee Thompson, NW Energy Coalition; Jared Webley, Avista; Nathan
Weller, City of Pullman; Bill Will, WASEIA; Yao Yin, IPUC;
Recording started with the first presentation after the Introduction.
Future Climate Analysis, Mike Hermanson
Mike Hermanson: OK, as John said, I'm going to be talking about the climate change
analysis that we did. It's largely an extension of what we did for the 2023 IRP. But
given the additional new staff and other people that were not part of that process, we're
going to step through the whole methodology that we did. We're going to look at hydro
generation. What's the impact of the predicted climate on hydrogenation? We're going
to look at the temperatures that were used for the load forecast. We're still a few days
away from getting the load forecast, so we're not able to do a before and after look at
climate change versus no climate change on the load forecast, and then looking at
temperatures for the peak load forecast where we've made some moderate changes
to methodology.
Mike Hermanson: To start out. All of this data is based on work that was done by a
joint committee of three of the major players on the Columbia River system.
BPA, U.S. Army Corps of Engineers and the US Bureau of REC. They utilized research
teams from the University of Washington and Oregon State. This has been a long
study. They started out with unregulated stream flows. Looking at the system with no

Appendix A
reservoirs or reservoir regulation. The second part was looking at what happened with
new runs of these unregulated flows through their regulation modeling system. One
piece of data that we did add to this year was looking at some wind data from the
University of California, Merced. They have a data set where they've downscaled
some of the data to a level at which is useful for looking at smaller regions. We looked
at one of our wind projects on the Palouse.
Mike Hermanson: Getting to stream flow is a multi-step process. I'm going to start
from the from the top where the basic model, the data that drives the models and then
go through how you take these global climate models, which do not output stream
flow. That is not output that they provide, so you need to do some additional modeling
steps to get to stream flow. You start with a global climate model, and because it's a
global climate model you need to have some sort of workable model size, and these
are all spatially oriented. It uses model cells as the basic unit that you're looking at.
And in global climate models, they range from 75 to 300 kilometers grid size. That's
not, when you're looking at watersheds, the Columbia River watershed is obviously
large, but we are looking at watersheds that contribute to smaller areas such as the
Clark Fork or the Spokane River.
Mike Hermanson: The models provide projections of temperature and precipitation
and other meteorological variables, but the temperature and precipitation is the most
important part. Stream flow is the resultant output of the global climate model. An
important concept in this process is to look at the future of greenhouse gas emissions,
most notably carbon dioxide. The IPCC and other organizations that do this type of
modeling developed a standard set of climate futures based on carbon dioxide. This
chart to the right starts with real data and then you get 2000 to 2100 and that is
predominantly the model data. It shows what the concentration pathway that is
predicted. Depending on these different representative concentration pathways, and
they are largely derived by implementation of greenhouse gas reducing policies, how
successful they'll be, how widely they'll be taken. So, you have a range and they're
denoted by a number. The higher number is the larger quantity of greenhouse gas
emissions over a period of time, and so you have the RCP 8.5, 6.0, 4.5 and 2.6. The
interesting thing to note about this chart is that the endpoint of a lot of these models is
2100, but the IRP timeline is actually ending in 2045, so you bisect that tan area, and
you see the difference. When you get out to 2100, the difference between these
scenarios is quite large, but in the middle and slightly to the left of the middle of that
tan area, you'll see that greenhouse gas emissions and concentration within the
atmosphere is a lot closer. Multiple models are used, academic institutions and
different countries. There's a list here. I won't go through the list, but all of the different
models that were used in the BPA, Corps and Bureau of Reclamation study.

Appendix A
Mike Hermanson: We have 10 global climate models and there is a lot of variance in
the output. Some are biased high, some are biased low, so a lot of variation there.
Now just a little additional information about the different concentration pathways. In a
summary document from the Intergovernmental Panel on Climate Change, IPCC, the
de facto governing body of climate change analysis. They described the scenarios in
this fashion where RCP 2.6 is a very stringent mitigation scenario, the 4.5 and 6.0 are
intermediate scenarios, and 8.5 was labeled as very high greenhouse gas emissions.
The joint study evaluated RCP 4.5 and 8.5. They did not do 6.0, because it is largely
similar to the 4.5 in the initial phases up to 2050 and then as you go up. It pretty much
strikes the middle, there's just a lot of data. There's a lot of choices that needed to be
made by this group doing this. This was also pulled from some summary information.
Just looking at the RCP 4.5 and 6.0, and they had produced some information that
were so in similar time frames, looking at the middle of the time frame versus the end
of the time frame, and it looked at global mean surface temperature. Kind of an overall
measure of what the impact of these different concentration scenarios are. And if you
look in the 2046 to 2065, which is very close to the end of the 2045 IRP planning
scenario, you can see that the 4.5 and 6.0 are very similar. I looked at what we wanted
to use for the RCP scenarios. We kind of use this guidance. We didn't have the 6.0 to
test, but we did have the 8.5 and the 4.5 and intermediate scenarios. Alright, seem to
be consistent with the implementation to date of climate change. Policies and
projection of hopefully where they go and so that's why we chose that. You can see
that the mean is actually higher for the RCP 4.5 in the years going out from the end of
the IRP planning scenario. That's kind of about our choices going forward because
we're actually going to propose a hybrid method.
Mike Hermanson: Going through the mechanics of doing this global climate modeling
down to the watershed scale, where you can actually get stream flow out of it. On the
right-hand side, the top shows the typical global climate model grid size and as you
can see there's, the resolution at the global scale is fine, but for what we're doing is
not. They've been downscaled, which essentially means you use some sort of variable
that is present within those large grid cells elevation, other climate data to correct for
variations within that model size. Elevation would be a good example. You could have
an amount, Spokane within one of these grids and we know that precipitation and
snow accumulation and everything is different on the Palouse as opposed to in
Spokane City. We have a 4,000, 5,000-foot elevation came from two methods were
used and the bias corrected. Spatial disaggregation and the multivariate adaptive
constructed analog. And then this is the point we turn the precipitation and temperature
that we get from the climate models, and we turn that into stream flow, and it uses two
different hydrology models, and then they use three versions of one model and another

Appendix A
version of another model. So, we have four different models and what this does is
predict, based on the temperature, amount of precipitation, and what kind of ground
cover you have, what kind of soil you have. It predicts the hydrologic cycle and then
you find out stream flow reacts to that and.
Mike Hermanson: Right now, we have 10 climate models. We have two ways of
downscaling it and we have four different versions of hydrologic models that have all
been used. And we put all of that together, you get 80 climate scenarios and that has
a lot of data to work with. BPA, we follow their lead actually, selected 19 of the 80
scenarios and did work on finding 19 that represented a sufficient distribution of high,
low, medium and felt that those 19 scenarios represented the 80 scenarios
adequately. We used the ones that the BPA selected. That's what we use for the future
climate scenarios. Now I'm going to talk a little bit about how we actually put together
a whole flow data set because we have a flow data set that goes from 1929 to 2045.
We use the BPA 90-year data set of stream flow and we use 2019. Is not within either
of the climate change or the other BPA data set. And then we also used the climate
data set to generate this data set went for 1929 to 2045. We used the median of the
19 BPA selected scenarios used in the flow data set. Once we have flow, we then
need to turn that into generation within our system. And to do that, we used Plexos
and use the functionality of that to generate what the generation would be for our four
storage projects. We have four run of river projects in the series on the Spokane River
and those were utilized, or the data we used, for that was a regression analysis based
on historical relationship of river flow and generation.
Mike Hermanson: This is the output and looking at different time periods, the 90-year,
and this is the total mean generation over this time-period noted. We also have
contracts with the Mid-C. Projects, but we didn't include that in this because we have
changing contractual slices into the future that complicate reporting back. And if we
reported back, they're just total generation then that swamps what our generation
would be, so this is looking at Avista hydro projects. It's largely consistent with what
you hear about climate change in the Pacific Northwest, which is we're going to see
more precipitation and as I move on to the next slides, you'll see what is really
happening. We're getting a shift more in in the springtime, a little earlier than we've
had. And then we are getting lower flows during the summer. So don't need to read
off all of the values here. You guys can see that going from 90 years, the recent 30-
year to the climate change time periods, the quantity, the total megawatts generated
over those time periods increase.
Mike Hermanson: I'm going to go through each month just to give you a flavor for
what is predicted in these charts. The orange line is the 30-year as a flatline.

Appendix A
Actually, the orange is the 90-year, gray is the 30-year and then the climate model is
the average or monthly average for that time period. You can see the trend of where
things are going. As you can see in these four spring, winter, spring months, we
generally have a flat trend, but it's increasing generation over those other two time
periods. Moving on to the late spring and summer, as you can see, May is still we're
getting more generation and then as you move into June, July, August and then
September and October, we're seeing a trend of decreasing generation as we move
through the climate change time series and then December is pretty much similar for
all of the different time periods.
Mike Hermanson: OK, so that covers the hydro generation portion of our climate
change analysis and now we're going to look at temperatures for load forecast and
two different ways of looking at it. When we're just looking at annual energy, we look
at heating degree days and cooling degree days. And then for our peak, we look at
the actual temperature. We use the daily max and min temperature for the Spokane
Airport through 2045 that correspond to the 19 BPC scenarios. And then we are
actually proposing to use data from both the RCP 4.5 and RCP 8.5 temperatures for
the load forecast for the winter months, January through May and October. I guess
that's not all winter, spring, and fall. Winter we're proposing to use the RCP 4.5. And
then June through September using the RCP 8.5. This approach will allow us to look
at worst case scenarios in both time periods. It'll allow us to evaluate what the impact
of increasing temperatures from RCP 8.5 during the summer months whereas
capturing the low temperatures that are still possible and appear to be continuing to
be possible going into the future. The average temperature is increasing, but you still
have those cold snaps as we had in early January. Those are still possible and
represented in these climate datasets. So this chart shows the.
James Gall: You got a question from Molly. OK, Molly, go ahead.
Molly Morgan (UTC): Hi. I'm just on that last slide. I'm just curious, what would be any
downsides or risks of using of this proposal of using the 4.5 and the 8.5 together? And
then also, do you know of any other any other places that this has been done? Are
there any other examples of that?
Mike Hermanson: We don't know of any examples, although I haven't done a
cataloging of all approaches to climate change within different IRPs. Actually, this
approach was really to address risk. What we were finding was that if you use the 8.5
during January and during the winter months that you're going to possibly miss out on
that cold event. And you know from working with the Martin Luther King Junior Day
event that we had. We know those risks are real and still important to plan for. They

Appendix A
are still represented within the RCP 4.5, although as we get to the peak part, you'll
actually see the differences we're talking about are. In some instances, a difference
less than a degree, what we're finding is that you still have some of the outliers.
Extreme values still are retained in the RCP 4.5 on the cold side, and we feel that's
pretty important, especially in the Spokane area where those risks are real. It is
important.
James Gall: Another thing to add Molly to that there's two sides. There's peak and
then there's energy. And if we plan for, let's for example use the 8.5 case in the winter,
we'll have less energy expected. And what will do is that will reduce the amount of
generation we'll have to acquire in the long run, which could put us at risk of not being
able to serve those loads, at least in a cost-effective way in the future. The choices
that we make here are really going to impact what is selected in our models for new
resource generation going forward. The approach we took is planning for, like Michael
said that it's more of a risk adjusted value for both seasons that we are going to protect
our customers from both forecasts of extreme cold, or sorry, extreme heat and then
moderate cold.
Molly Morgan (UTC): OK. I'm just hearing that. So, 8.5 just at least for your service
territory doesn't account enough for what you're seeing currently for winter events.
James Gall: Correct. And you'll see that in the chart coming up.
Molly Morgan (UTC): Right. Thank you.
Mike Hermanson: This chart presents the annual heating degree days and annual
cooling degree days. You can see what's happened in actual terms and what was
modeled. Modeled values are actually decreased. They don't quite represent the most
recent period of time very well. But you know it's value. And so, we have the heating
degree days, decreasing even under the RCP 4.5 scenario. You still have that climate
change impact. You're going to have reduced heating degree days, so as we forecast
load that will decrease the amount of energy that we are planning to meet. And then
on the bottom, we have the cooling degree days and as you can see the heating
degree days are significantly greater in number. And so, we're dealing with
temperatures that our energy is heating even though we look like we're going to be a
dual peaking facility, or utility annual cooling degree days due to increase. Those
annual cooling degree days are based on the RCP 8.5. Using these model
temperatures will be, the slight decrease in energy in the winter months and increased
energy in the summer months.

Appendix A
James Gall: You have another question from Joshua.
Joshua Dennis (UTC): Hi, I wanted to ask on the Y-axis it says thousands and goes
up by the thousands. Could you explain what that means?
Mike Hermanson: Those are the annual cooling degree days and heating degree
days.
Joshua Dennis (UTC): Yes. No, not the annual cooling and heating degree days, but
why does it go up by thousands?
Mike Hermanson: Because it's the annual value.
James Gall: You're summing up all of the heating degree days and cooling degree
days.
Joshua Dennis (UTC): OK.
Mike Hermanson: So, it's for the whole year.
Tom Pardee: Those are just the average increments between the annual heating
degree days and the annual cooling degree days. In order to get it on the chart, to
show the delta, it's choosing thousands.
James Gall: It's whole numbers.
Tom Pardee: It's just that's how many fewer cooling degree days we have compared
to heating degree days. I'm just saying to show how can get heating degree days and
cooling degree days on the same chart. It's choosing the increments of 1,000, but it's
for illustration purposes.
Joshua Dennis (UTC): Oh. Thank you.
Mike Hermanson: If we just did a chart of annual heating or cooling degree days, it
might choose 1 ,000 as the top value anyway.
John Lyons: Do we want to go over what the definition of a heating and cooling
degree day is? Just for anyone as a reminder here.
Mike Hermanson: As a reminder, heating degree days is the degrees you take, you

Appendix A
go from an average value of 65 being zero and a heating degree day is how many
degrees do you need for the difference between what the temperature is outside. If it's
45 and you have your zero set at 65, you're going to have 20-degree days.
James Gall: and then you sum them up for the whole year, which is why winter is
substantially larger than summer. There's just a lot more heating degree days in total
over the course of the year than summer cooling degree days. So, if you were in
Arizona, the chart would be flipped, essentially. John has a question.
John Barber: Yeah. How fine grained is that? Is that the maximum or the minimum
temperature of a day? Or do you average it over the day, hour by hour?
Mike Hermanson: It's an average of the minimum and maximum of the temperature
for the day.
John Barber: OK.
James Gall: So, might be about 10 minutes left in this section so you might have to
speed it up.
Mike Hermanson: Yeah. OK, now we're going to move to peak load. Similarly, we are
proposing to use the RCP 4.5 for winter and summer use the RCP 8.5. The other
change that we have used is we're using the median of the minimum or maximum of
the average daily temperature for each season of all the models. We have 19 models.
We have a median and then we go and look for that whole season and we picked the
lowest value and then and the winter peak is based on a 76-year moving average and
the 76 years is based on that time where Spokane temperature data was moved to
the Spokane airport. Summer Peak is based on a 20-year moving average and this is
just the choices made on risk and also the movement of these different peak
temperatures.
Mike Hermanson: I've got four different graphs that show the actual temperature up
to 2024, and a red line which is the peak temperature that we are going to model. And
then it's a box and whisker plot showing the median, average, and the extremes of
each of the models. This is the distribution of the models, the dots are considered
outliers by Excel for whatever approach they used to determining outliers. This is the
annual high temperature for RCP 8.5. As you can see, it moves from 84 degrees to
86.76. After 20 years, you end up about the median of the last box and whisker plot.
James Gall: Fred has got a question. Go ahead.

Appendix A
Fred Heutte: Yeah. Hi everybody. It's Fred here at Northwest Energy Coalition. Just
trying to find all the right buttons here. You may end up talking about this further along
in the slides. But I just wanted to ask, this shows the outliers for the climate adjusted
record going forward. I'm wondering if you've looked at the outliers for the historical
record. You know, this is summer. But we just had the January freeze event which I've
got temperature data for a lot of weather stations. And I would say we had some record
setting temperatures for the day during that period, but not for the month. And I'm just
wondering if you've looked at whether these outliers are happening more frequently,
or they're higher, or they're about the same? If you've looked at that comparison.
Mike Hermanson: Well, what we are planning for with peak load is peak load and
we're doing on a seasonal basis. So, we are looking at the entire period from
November through February.
James Gall: Can I add something just to get to Fred's question. The historical period,
Fred, those are the hottest days on record in the historical period versus the outliers
in the forwards, you have those 19 different futures that is a value that is in those 19
futures that show up that are radically different than the rest of the data set.
Fred Heutte: OK, so if I'm following that, that means that you have the historical record
with one data series, you're taking all 19 of the different GCM or whatever to look at
the outliers in each one.
James Gall: Yeah.
Fred Heutte: So, this in effect kind of over represents what could happen.
James Gall: Exactly. That's where the top of that bar probably is, where it's
statistically, that maximum is based on the data set.
Fred Heutte: OK.
Mike Hermanson: This is an attempt to show the real challenge of working with 19
different models and the fact that they are widely distributed.
Fred Heutte: Yeah. And just to say, I appreciate you doing that because I think it does
highlight the internal models actually have some, I don't know that much about all this,
but have some common starting points way back when and have kind of diverged.
And of course, within the model each time when you run it, you're going to start with
slightly different starting conditions. That's part of doing the modeling. So, you get this

Appendix A
spread, but there is internal correlation with them a little bit. But I think what it really
says is that the future is kind of hard to predict. And looking at a lot of models like
you're doing is actually a better way to do this, even though it requires some additional
interpretation. I think this is the right way to go.
James Gall: Thanks, Fred. We got about 4-5 minutes to get through I think four more
slides, so we'll try to be quick.
Mike Hermanson: Just as a comparison, the RCP 4.5 looks like this. And it's also
peak temperature on the hot side. You can see the ending value for 4.5 is a planning
temperature of 85.72 planning, ending planning temperature for RCP 8.5 is 86.76, so
that is the fundamental difference when you get to 2045 is about a degree. Now we're
looking at the low temperature, and this is the RCP 4.5. A lot less volatility within these.
The other ones mimic the climate ones models a little more, but for this we are using
a 76-year because we want to capture a longer period of time. So, you end up with
the temperature of 5.63 average daily temperature for the 4.5. Use the 8.5 you get to
an average temperature of 6.07.
Mike Hermanson: The last thing we looked at and it's another output. These global
climate models, as you can see the historical values were 1955 or 1950 to 2005 and
the RCP, the climate change looked at data from 2006 to 2099. On the left is average
daily wind speed. Palouse location has a northeast wind direction that's predominant.
As you can see, it's essentially the same. We don't predict much change. The climate
models don't predict much change in generation. The wind speed from the north
direction again is very similar. On the far right are the opposite directions of the
predominant wind out there. You see a little more divergence and the negative values
are because that's how they're represented the different direction. You can see that
the monthly maximum temperatures are not temperatures, but wind speeds are lower.
The lower frequency direction and there's a little bit more volatility between the actuals
versus the climate models. But given the predominant directions and average wind
speed in the predominant direction, we don't see much as far as planning and changes
in wind speed, I'm not really sure how accurate predicting wind speed into the future
is. It's kind of a tangential parameter from these climate models.
James Gall: We have a question. Did you look at hourly at all to see if there's a 12 by
24 change or is this, I recall the data is daily though, right?
Mike Hermanson: The data is daily.

Appendix A
James Gall: Yes. So, no, for Andres. We can't do hourly with the climate model.
Just daily.
Andres Alvarez: OK. Thank you. Just curious to know if there was any hourly shape
differences because that will affect the benefit, right. If the hourly shifts are changing,
that could be of concern, but it seems probably unlikely.
Mike Hermanson: Just to sum up our proposed approach. Utilized the RCP 4.5 for
the winter, 8.5 for the summer, just to remind here of why we chose the 4.5 and the
8.5 looking at the description of the IPCC. We're using a combination of the latest BPA
regulated flows, one year of actuals and then the median of the selected climate
models for generation estimates and then the peak load forecast. Proposing to moving
to use moving averages of previous 20 years and 76 years. The real change would be
using seasonal peak temperatures both low and high and that's the background in the
proposed approach going forward with the IRP as it relates to climate change.
James Gall: Are there any questions before we move on to the economic forecast
and load forecast? And while you're thinking about that, feel free to contact us through
email or give us a call afterwards. We do have a question that showed up, Jason says:
using a combination of low lows and high high scenarios, does that create unrealistic
ramps between models?
James Gall: I'm thinking is that a question more of how the model transitions from one
season to the other season? Is that what you're thinking, Jason? Yes. It's a daily
model. So, I guess I don't know if there really is a ramp.
Mike Hermanson: It's monthly values and there's not really a ramp, especially as you
can see the ultimate difference was 1 degree when it was all done. It did not appear
in crunching the data that we ended up with some sort of situation, although that is in
fact somewhat what we wanted to create was a better approach to the risk profile for
summer different from winter.
James Gall: Molly had a question. Go ahead, Molly.
Molly Morgan (UTC): OK, this is not super well formed, but just thinking of various
elements. This is one approach to do the 4.5 in the winter and 8.5 in the summer.
Let's say, I think in one of the last meetings, you were asking about the loss of load
probability and that's currently at 5% and should or could that be at like 1% or 2%?
What would the effect be say if you use the RCP 8.5 year round and then also use the
loss of the probability of 1%, would that solve a similar problem or not?

Appendix A
James Gall: Maybe, so how the loss of load probability works is it will randomize both
historical and future temperatures. If you use the 8.5 scenario, you're going to have
less draws of colder temperatures, and if you're planning for a loss alone at 1%, you're
effectively you could get to the same solution. At the end of the day, what it comes
down to is how much extra capacity over expectation are you you're trying to acquire.
You could theoretically get to a similar answer there, but then it would have a different
answer if you'd probably used 4.5 and 1% loss of load probability versus 8.5 and 1%
loss of load probability.
Molly Morgan (UTC): Yeah, those would probably get you something different, right?
James Gall: Correct.
Molly Morgan (UTC): Yeah, because there's also thinking of risk in a different way,
like the risk of overbuilding.
James Gall: Yeah, I guess overbuilding. It depends. There are two sides of what we're
building. One is overbuilding of energy and then there's the overbuilding of capacity,
and those are real risks. The problem is you don't know the future and so you're trying
to come up with something reasonable and affordable and that's the greatest
challenge with resource adequacy is this has been an issue for decades, what do you
plan to? For the region, the WRAP came up with a method of 1-in-10 which means
you have one event in a 10-year period. Or is it one event in a 100-year period. It's an
expectation of what our customers expect from us. I don't know who makes that
decision. The utility has an obligation to serve, and we propose something, but at the
end of day it's up to the Commission to approve those additions. It would be nice in
the perfect world that the Commission or the legislature says this is how much you
should build, but we're not in that world. We're trying to propose something that we
think is reasonable that we're going to plan to and build resources to. It is a judgment
call at the end of the day. But I would also ask the question is loss of load probability
modeling or LOLE modeling with the WRAP, is that the right method? I'm not so sure
it is after the event we had in January because you're essentially planning not to meet
extreme events and should we be modeling for extreme event planning.
James Gall: And I said those are valid questions, but I don't know who has the right
answer. We can propose to build resources to meet a low water year and high loads,
in a cold event or a hot event. It's up to the Commission to approve those plans or
those resources that we acquire. I think we're going to have to work together on trying
to figure out what is the right amount of capacity to build.

Appendix A
Molly Morgan (UTC): Hello. Right. Because if you don't accept any such events, then
you're likely going to be overbuilt. Is the idea right?
James Gall: Yeah, I mean, can you restate that real quick just so I make sure I?
Molly Morgan (UTC): Like if you if you plan to not accept any such events, like you're
saying it could be 1-in-10 years or 1-in-100.
James Gall: Correct.
Molly Morgan (UTC): So, you extend that, maybe I don't know if you can ever say
zero, but in that situation, you are likely going to be overbuilt. So, that's the trade-off.
James Gall: Yeah, I know, building is not a bad thing. It's just what can you afford?
Molly Morgan (UTC): Yeah. That's the impact cost.
James Gall: Don't know. Yeah.
Molly Morgan (UTC): Yeah. OK. Thanks.
James Gall: Yep. Let's move to Grant's presentation.
Economic Forecast and Five-Year Forecast, Grant Forsyth
Grant Forsyth: We got about 35 minutes for a 40-minute presentation. So OK, so I'm
going to jump right in. I'm going to talk about something I've talked about many times
in these IRP meetings. We are going to talk about economic conditions of our service
territory just to make sure that everybody's on the same page about what we look like,
and we'll also talk a little bit about what I'm building into the medium-term forecast,
which incidentally is a forecast I do twice a year. It goes out approximately 5 to 6 years
depending on what time of year I start the forecast and I say preliminary in this case
because I just redid the forecast in March and I sent that to our consultants, which I'll
talk about in a minute. We're working with some consultants who have an end use
model to do the longer-term forecast. They're going to provide a presentation where
the first five years of their long-term forecast is this March forecast that I just did that
goes to 2028.
Grant Forsyth: Excuse me. We're going to talk about the structure of the service
territory here, economy, and then we'll go into the medium-term energy forecast, which

Appendix A
again I just did it this March. I usually begin these presentations with some sort of
quote. This year in an act of hubris, I put myself in there, "this presentation is 40
minutes of a finite life you will never get back." And if you give me the business, it
might be even longer. Just consider that as I go through the presentation.
Grant Forsyth: Let's talk about the service area economy. The best and most succinct
way to understand the structure of our service territory is to look at non-farm
employment. I'm in particular focused on how our metro areas that we serve look in
Washington and Idaho. That's what an MSA is. How that looks relative to the US as a
whole, I focus on our MSA areas that we serve because that's really where the bulk of
our customers are. And really, that's where the best data is collected is for metro areas,
but it gives you a flavor for how we look relative to the US and the truth is we look a
lot like the US from the metro point of view.
Grant Forsyth: We have a situation where just like the US employment is dominated
by private services. What's really important to understand is that without service sector
growth, because it's so dominant at almost 70% of employment, if services are not
growing, we don't really have very much employment growth at all.
To give you an example of what constitutes services, one of the major employers in
our service economy is healthcare. OK. Then we have private goods.
These are going to be companies, predominantly manufacturing construction.
Manufacturing construction will dominate private goods. And then, of course, the other
major employer is going to be government. It's interesting to talk about government.
always like to talk in more detail because government gets everybody worked up and
it's important to talk about how government is actually divided. It's actually pretty
interesting in terms of people working for the government, where do they work in terms
of state, local or federal. It turns out the bulk of government employment is state and
local, and most of state and local employment is actually education because it turns
out young people take enormous amounts of resources.
Grant Forsyth: Federal employment is actually pretty small. It's 10% in our region, it's
about 12% in terms of the US as a whole. When we think about government, it's
important to understand that it's mostly local government, followed by state and most
of state and local is going to be education. People have asked in the past what about
agriculture because we do serve a big Ag region. In particular the Palouse, so if you
consider agriculture, it would account for 1% to 1'/2% of employment. If you included
all types of employment, the reality is agriculture is a super important generator of
income in our service territory. But because agriculture is so focused on automation
and productivity, it has become a very small share of employment. But it is a significant
share of income. Spending a little more time talking about non-farm employment

Appendix A
growth more recently as we come out of the pandemic, it's useful to look at what's
happened since May 2021 because that's where post pandemic growth really peaked
as we began to recover from the worst parts of the shutdown.
Grant Forsyth: And what you can see is we've actually done pretty well. We've
avoided a recession everybody expected in 2023 because of higher interest rates. And
what you can see is more recently Washington, our service territories in Washington
and Idaho have really picked up employment growth, really surpassing the United
States, which actually continues to grow at a pretty good pace. One thing to remember
is if you were to divide out the Washington and Idaho side, it's really the Idaho side
that has been growing the fastest. And we're going to see that with different indicators
as well. So, let's look at population growth. The reason I like to spend some time talking
about population growth is that it drives most of our customer growth. We've had
population growth on average significantly higher than the US because of in migration.
This is a really important topic or point I want to make is that without in migration growth
our service territory would look either close to the US depending on which county it is
around half a percent, or it would actually be zero or negative. Again, depending on
the county, because the reality is most growth now is being driven by people moving
around the country and not because of babies being born. In a lot of counties that we
serve, the death rate exceeds the birth rate, so any positive population growth has to
come from people moving there. People move to the region. Historically, when our
employment growth is better than the US as a whole and that has historically reflected
the fact that housing here is relatively cheap.
Grant Forsyth: What we've seen historically is that as our employment growth slows
relative to the US, in migration slows. So, population growth slows, and we saw that
coming out of the housing bubble. OK, we get the recovery from the housing bubble
bursting. And what we can see is that in migration starts to accelerate. Our population
growth really starts to accelerate beyond the US and as we get into the pandemic
period and post pandemic period, we can see population growth starting to slow.
Again, that reflected in migration is slowing, but we're still probably going to grow faster
than the US as a whole because we still look a little bit stronger in terms of economics.
The modeling that I do tends to favor showing us having higher population growth than
the rest of the US because we're going to have higher employment growth. Now
there's one caveat, and this is something I'm going to be tracking as we move through
time is that we have gone from a service territory with relatively affordable housing to
our service territory without affordable housing. It'll be interesting to see whether or
not the employment growth that we get when it's higher than the rest of the US do we
get the same kind of push in, in migration that we used to given the fact that we no
longer have the same level of affordability, but something I'm going to have to look at,

Appendix A
it's something I'm paying attention to. But generally speaking, the outlook for customer
growth is going to track on average close to population growth. And I'm assuming at
this point in the model, based on economic assumptions that our population growth
will exceed the US, but it's totally dependent on in migration.
Grant Forsyth: Now one thing about housing, let me talk about this briefly. No
surprise, permitting for new housing is strongly connected to population growth, but
we've also underbuilt for the last decade. One of the issues is that as people continue
to move to the region and we've been under building single family homes in particular,
where are people living as they in migrate in? It's just important to point out is that
we're seeing a big emphasis on apartments. That blue bar that you see in the graph
is the number of permitted single family units, and I count townhouses and condos as
single-family units. And the red bar is really just apartment units. These are the larger
apartments that are being built in the region and what you can see is really starting in
2020 we've been absorbing a lot of our population growth through apartments. On the
single-family side, we're also seeing a larger share of single families being moved
towards duplexes and now with the Construction Monitor Service that we buy to track
these permits, they're breaking out accessory dwelling units, ADUs, and we're starting
to see more ADUs being built too as people try to take advantage of new, more lenient
policies towards higher density. OK. But going forward, we're going to see a lot more
people probably living longer in apartments than we've seen historically. OK, let me
stop. Are there any questions so far before I get on to the medium-term forecast?
James Gall: No questions.
Grant Forsyth: OK, so this has changed from previous IRP. Here we've got this
timeline we're trying to forecast over. My current medium-term forecast is the green
triangles, it covers 2024 to 2028. OK. To do that forecast, it's based on monthly
econometric models that forecast by class by schedule. I'm forecasting customers and
use per customer and to get load I multiply those forecasts together. Weather is
handled as a 20-year moving average that I update each year. When I get a new
calendar year of data. The main economic drivers are things like GDP, industrial
production, employment growth, population, and natural gas penetration. In particular,
the natural gas penetration is a variable in Washington because that's where it seems
to matter the most. I can use that retail forecast then to convert it into a native load
forecast based on historic norms. OK. And again, the current 2025 IRP forecast is the
spring 2024 forecast completed in March, but we could at some point in the future
update this when I redo the forecast in six months. So, if you look at the red triangles,
when we go beyond 2028 to 2045, this is where we shift to the long-term forecast.

Appendix A
Grant Forsyth: Historically I handled this modeling approach, but because of the
enormous policy changes that are occurring that are regulating potentially down to the
appliance level, we really needed to shift our approach. We've hired a consulting
Group called AEG who you've probably heard speak at our TAC meetings in the past,
but they are now handling the long-term component. OK, using some inputs that
provide to them and so they're essentially shifting us in the long term to an end use
modeling process. The idea is that we're going to get a better handle on how these
restrictions on gas, other types of policies that are coming down there, how they affect
load in the long run with more detail and more flexibility than I was able to provide in
the past with my own method. Now, James, just to make sure we're correct about this,
AEG is going to be giving us a presentation in the future, correct.
James Gall: Two weeks hopefully,
Grant Forsyth: OK. They will probably be there providing this discussion between the
red triangles and what they're going to do is they're taking my medium-term forecast
and an on an annual basis, that's their first five years, and then it's their model beyond
that. Do I have that correct?
James Gall: You have that right.
Grant Forsyth: Let's talk a little bit about the analytics, how I do this, it's complicated.
It's boring. It's miserable, but I'll give you a sense of what I go through to get this
medium term forecast with the main economic drivers. OK, so let's start with the GDP
forecast. I go out, I collect a whole bunch of different forecasts from different sources
for GDP growth over the next five years. I've averaged them so I get a consensus GDP
growth forecast across many different forecasters. This helps avoid systematic biases
that you may get with a single source forecast. OK, so look at the green rectangles
first so I can use that GDP forecast then to forecast industrial production growth based
on historic norms between how GDP grows and how has how US industrial production
is going to grow. OK. I get the US industrial production index, the historical numbers
from the Federal Reserve. OK, that means I've now got a forecast for industrial
production growth and that's going to inform the use per customer forecast for certain
industrial customers who have sensitivity to industrial production. What's happening
with the industrial production in the US. If we go to the bars, they're triangles above
and the kind of reddish ones, I'm also using GDP to forecast employment growth for
our region. So, what happens is that GDP growth at the national level informs what
our employment growth should look like in our service territory. But I'm also going to
go ahead and average those employment growth forecasts that I'm generating with
forecasts from S&P Connect, which used to be IHS Connect. S&P bought them a few

Appendix A
years ago. I'm essentially taking an average of my employment forecasts derived from
GDP. And GDP forecast that they derived themselves. And then what I get is an
average of employment growth. And historically, what we've seen is there's a close
association between employment growth in one year and what population growth
looks in the next year, and in particular, that's the connection between health of your
economy and in migration. OK, so what I do is I take the employment growth forecast,
generate my own population growth forecast. But then again, I averaged that with the
population growth forecast of S&P Connect. Again, trying to mitigate that bias potential
of a single source forecast and then what happens is those population growth
forecasts are the really significant driver of certain residential and commercial
forecasts and in particular of customer forecasts. In fact, on the electric side, in the
long run are historical customer growth has been pretty close to what our historical
population growth has been. They're almost the same. You can really use population
growth. The average growth you're forecasting as the proxy of customer growth, OK,
so there's that component down below and the blue boxes, you can see the other
drivers, I have a 20-year moving average of degree days. That's what DD is, and in
the case of Washington, I use my gas forecast to estimate how much gas penetration
we have in our service territory and that's actually an important driver for residential
use per customer in Washington. It seems to matter less than Idaho, so it's now in the
Washington side, not necessarily the Idaho side. And again, those weather variables
and that gas penetration inform certain residential and customer use per customer
forecast in terms of weather and again, gas penetration on the industrial side. There's
not a lot of weather sensitivity. So that's a lot of questions about that. Nothing else.
OK, I'll wait.
James Gall: [Reading question from chat] OK, if time allows, can you go over any
relationship between the employment growth, population growth and family unit size?
Grant Forsyth: Right. I've looked at this over time. We're getting population growth,
but over time it looks like we have a downward trend in household size and that's a
trend all over the US and the expectation reading all of the more recent demographic
research and analysis, the growing expectation is the household size will continue to
decline going forward. And so again, increasingly what that means is organic
population growth is going to be small, zero, or potentially negative because of deaths
exceeding births. Population growth becomes even more heavily weighted towards
end migration. Keep in mind the longer people have to rent apartments in order to find
housing, that may also curtail family size for a longer period of time, or at least cause
less of an incentive to have kids. Does that answer the question? OK. I'll assume so
unless you protest.

Appendix A
James Gall: OK, alright. No other questions so far.
Grant Forsyth: OK. Again, we could spend hours on this. I would be happy to do it,
but I won't so, let's talk about one of the big economic assumptions, because again,
this drives a lot of different things as we just discussed. This is GDP growth in the
United States. The black line is showing you historically what has happened, and the
red dotted line is the current consensus forecast that I have built into the March
forecast over the forecast period. OK. Keep in mind, in the long run GDP growth is a
sum of population growth and labor productivity growth. And if you look at the forecast
for population growth in the United States increasingly for us to return back to roughly
2% GDP growth, which is the prepandemic norm, we're going to have to make sure
that we have a pretty good productivity growth around 1'/z%. This population growth
in the United States is about 0.5%, so productivity growth isn't at least 1'/2%. It's going
to be hard to be at that roughly 2% GDP growth, but that's the consensus view, so
that's what I built in the forecast.
Grant Forsyth: The Fed's long run expectation for GDP growth has actually fallen
from 2%. It's now down to 1.8% and so I'm assuming this is what I've given to AEG.
I've asked AEG to assume in their models the Fed's long term growth rate of 1.8% and
that's what they're going to assume from 2029 to 2045. And keep in mind that 1.8%
assumes that most of that growth has to be coming from productivity growth, labor
force productivity growth, because population growth out to 2045 in the US is going to
continue to decline. OK. It's also important to recognize that increasingly, I'm not
showing a lot of industrial production growth and that's because in the long run, based
on historic norms, GDP growth in the US has to be about 1.6%, at least for the
industrial load to show any growth in the forecast that I do for our service territory.
And actually, even if you were at, say 1.7% or 1.8%, industrial load does not grow very
much at all. You really need to see it over 2% before you begin to see industrial load
pick up on our service territory. One of the outcomes of these assumptions is we're
not really showing a lot of industrial load growth. And in fact, as we're going to talk
about a little bit later, we're starting to see some customers leave larger schedules for
smaller schedules in our service territory because their load growth appears to be
falling over time and that shifts them into a different schedule for smaller firms.
Some of that might be just efficiency gains that are occurring. OK.
Grant Forsyth: Again, another big indicator is population growth. Because population
growth is really going to be a proxy for customer growth in the long run in our service
territory. What we can see here in this slide, the red is for our service territory. The
black is the US Census forecast for the US. I just thought it was interesting to compare
it and so that's what I'm assuming in the medium term and the current medium-term

Appendix A
forecast. This is what I've asked AEG to assume in the longer term so you can see
that our population growth is declining over time, but we're typically going to be ahead
of the US. Again, the assumption is that in migration is going to continue over the
forecast period. Right. The little box up above shows you a little bit of a comparison
between the last IRP, which was based on the spring 2022 forecast in the medium
term, and then where we are now with the March 2024 forecast. A little bit lower in the
longer term compared to what we had in the 2023 IRP. But again, most of that growth
is going to be happening in Idaho. OK, so that gets us to really just a picture over the
next five years of what is native load look like. Again, this is derived from my retail load
forecast and it's really kind of interesting. What we've really seen following the
pandemic has been this step up in use per customer that's occurred. It's a step up that
really occurred starting in 2022 and what that's done is pushed up our native load a
bit so that we're really reaching that 2028 level early, meaning the 2028 level that was
forecasted in the 2023 IRP we're essentially there within a couple of years and that
reflects this step up that I've built into the forecast that we're observing in the historical
data. OK, the other thing that's going to be different too is that I'm assuming a much
more aggressive declining penetration in Washington, OK. And at least in the near
term, compared to the previous 2023 IRP, industrial load is a little bit higher because
the economic assumptions are a little bit more favorable even though the long-term
outlook for industrial load is not much growth. But on a level basis, we're a little bit
higher than the 2023 IRP. Questions.
Grant Forsyth: OK, so let's get a little bit longer picture. This is something James
asked me to put in, and I think it's actually highly instructive. The black line that you
see there is our actual native load since 2005. Right now, that dotted line there is an
adjustment I'm making for a complex contract we have with a very large customer with
its own generation. I'm just making sure that we reflect the load we would have had to
provide if its generation went down and so we get a much clearer picture of what our
true obligation on native load would have been. It makes the chart much more correct
and in that sense it's just interesting to see that if you look at the last time we had a
significant step up in load was the housing building boom that burst in 2008. And you
can see there what I'm showing is the average gain and load that occurred between
that housing boom period and when it stopped. We gained about 20 average
megawatts in terms of energy. And then we really didn't change much for more than a
decade. But we get to the pandemic. We have this step up because what we think is
going on is that you have this hybrid work environment where you have people at
home longer, more frequently and working. That means they're heating and cooling
more frequently, but all of these buildings that they're not working at or only partially
working at, still have to be cooled and heated. I think what it's doing is providing a step
up in overall usage, and it shows up pretty clearly in the data. And we're also seeing

Appendix A
this, by the way, in the peak load. I've also adjusted the peak load for this step up,
which is about 40 megawatts following the worst of the pandemic.
Grant Forsyth: What you see after that is the current forecast. That's the red dotted
line. OK. The current medium-term forecast shows us stepping up again about another
20 average megawatts. Again, that reflects to some degree these restrictions on
building and in Washington, more electric load because of declining gas penetration.
You compare that against the blue line, which is really the red and blue line. There is
just what we saw in the previous graph. It's just this idea that we're going to reach that
2028 number and we show in the 2023 IRP faster than we expected. We're talking
about maybe 60 average megawatts that have been built over a relatively short period
of time. Questions.
James Gall: I just want to add one thing. This does not include any large industrial
loads coming to our service territory, whether it's a data center or an existing, we'll call
it a DSI customer. We do have a number of entities contemplating either moving their
DSI load to Avista's load and data centers have been talking to us on occasion. There
is, let's say, more risk of a step up in and this IRP then we've seen in past IRPs. We'll
probably look at a scenario where there is a step up in load and then we also may be
looking at, depending on what happens with one of the industrial customers, we may
add that load to this load forecast. Once we know whether or not they're coming.
Grant Forsyth: Right. I think James is making it very good point for us. If we're going
to see industrial load grow, it's not going to necessarily come from our existing
customers. It's because somebody steps into our service territory, which will provide
a step up in load. The other thing I would point out about that, and I think this is an
interesting policy dilemma, I serve on a tax preference Commission in Olympia and
one of the things we reviewed in 2016 is a tax preference that supports data centers,
that encourages data centers. It is a policy dilemma, I think, that I don't know if the
state has thought about encouraging the location of data centers, increasingly large
and power dependent data centers. At the same time, they're trying to electrify
transportation and electrify heating. It could pose some real challenges for us, and I
would just point that out.
Grant Forsyth: Your misery is almost over. OK. James asked me. I think again this
was a good idea to put in a slide that reminds people that we're a Washington and
Idaho electric service territory and it's important to think about the two different
jurisdictions. Washington is about 62% or 2/3, whereas Idaho is just over 1/3.
It's significant, even though they're going in different policy directions, it's interesting
to look individually. This is their retail forecast. If you wanted to convert this into native

Appendix A
load, you could adjust it for line losses. To keep things simple, it's just the retail
converted to average megawatts without any adjustments for line losses to make it
native load. You see a little bit different time path in the forecast period 2024 to 2028.
The time path for the two jurisdictions looks different, and that reflects the assumption
I'm explicitly building into the residential load forecast for electric of declining gas
penetration. And what that does is it gives you a different load growth path then what
you see in Idaho, which has no restrictions on gas. If we're going to continue to restrict
gas and gas penetration falls, my econometric model assumes that drives up use per
customer and along with customer growth that's going to continue to push up load at
a faster rate in the Washington side of our service territory compared to the Idaho side.
If you didn't have that occurring in Washington, those gas restrictions, I think the time
path between the two jurisdictions would look similar because you'd have gas
offsetting some of the pressure on use per customer on the electric side. Questions?
I think I pushed through that pretty well. Yeah, you got 4 minutes left.
OK. Good. Questions?
James Gall: [reading from chat] Yeah. We do have a question. What are the
Washington gas restrictions?
Grant Forsyth: Yes. Well, I'm quite conservative about that because it's more than I
have to point this out. I'm essentially assuming in the gas forecast for Washington that
there is no more gas growth in Washington after 2024. From 2025 on our gas
customers are constant. You think gosh, that's pretty restrictive. You might judge me
on that, but I'd also point out there's some other things coming down the pike other
than those restrictions in terms of the building code, our line loss allowance. I mean,
should say our extension allowances, our extension allowances essentially go away
in 2025 in Washington and that means it's going to be a lot more expensive to hook
up with gas. I think that's the case of the building code as well. It's not that it's restricting
gas as it's more of making it more expensive to put gas in right to how the credits work
for getting a building permit. I think at the end of day, what you're saying is, is the net
between the two stays constant. I don't see a lot of growth now. It may turn out that
gas is still valuable to people, and they're going to, growth might not be constant in the
future, but until I start to see how consumers are going to respond to what's a pretty
dramatic change in the ability and cost of getting gas, I'm going to treat it pretty
conservatively. And that means that if you hold gas customers constant over the
forecast horizon, gas penetration starts to fall and that pushes up use for customer in
the forecast on the residential side.
James Gall: Well, we got two minutes left. To prepare people for the next meeting.
We're going to be talking about the next part of the load forecast. AEG will be doing

Appendix A
an end use modeling and what you're going to find there is it is a combination model
of gas and electric where they're forecasting out the number of customers that are
viable in the service territory and looking at how they're going to be choosing gas
versus electric going forward. And I wanted to bring up climate change because when
we did a study on this over the winter to prepare for this. We found that, as you know,
warming temperatures occur, that's going to make it less and less cost effective to
electrify, meaning that if you have a lot of load out there or cold temperatures, you're
going to have to look at the economics of switching. If you're not heating a lot in the
future, switching may not be as cost effective because of the upfront costs we're
finding in that future. That will be something to look for in the next presentation by AEG
on the load forecast. Just how that tradeoff between gas and electric is going to be in
the future? Also, the economics of energy efficiency does that that changes out in the
future. It'll be interesting presentation. This is a new idea for Avista that look at end
use modeling, and it'll also tie into the EV forecast and the solar forecast that we saw
at the DPAG meeting last week as well. We're at 10 o'clock, and I know many of you
have to go, but appreciate the time coming today, asking great questions. If you do
have other questions or comments, please email me or John or the IRP email address.
There's also the Teams site. Don't forget about that. There is data out there. There's
a chat feature if you want to send messages to us. Again, thank you for your time
today and we'll see you in two weeks and have a great day.

A endix A
Vop
2025 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 5 Agenda
Tuesday, April 23, 2024
Virtual Meeting — 8:30 am to 10:00 am PTZ
Topic Staff
Introductions John Lyons
Long Run Load Forecast AEG
Load Forecast Comparison Avista Staff
Review Planned Scenario Analysis James Gall

���r r/ISTA
2025 IRP TAC 5 Introductions
John Lyons, Ph.D.
Technical Advisory Committee Meeting No. 5
April 23, 2024

Appendix A
Today's Agenda
Introductions, John Lyons
Long Run Load Forecast, AEG
Load Forecast Comparison, Avista Staff
Review Planned Scenario Analysis, James Gall
2

Appendix A
Remaining 2025 Electric IRP TAC Schedule
• TAC 6: May 7, 2024: 8:30 to 10:00 (PTZ)
o Conservation Potential Assessment (AEG)
o Demand Response Potential Assessment (AEG)
• TAC 7: May 21 , 2024: 8:30 to 10:00 (PTZ)
o Variable Energy Resource Study
o Portfolio/Market Scenarios
• TAC 8: June 4, 2024: 8:30 to 10:00 (PTZ)
o Load & Resource Balance and Methodology
o Loss of Load Probability Study
o New Resources Options Costs and Assumptions
• TAC 9: June 18, 2024: 8:30 to 10:00 (PTZ)
o IRP Generation Option Transmission Planning Studies
o Distribution System Planning within the IRP & DPAG update
• Technical Modeling Workshop: June 25, 2024: 9:00 am to 12:OOpm (PTZ)
o PRiSM Model Tour
o ARAM Model Tour
o New Resource Cost Model

Appendix A
Remainina 2025 Electric IRP TAC Schedule
• TAC 10: July 16, 2024: 8:30 to 10:00 (PTZ)
o Preferred Resource Strategy Results
o Washington Customer Benefit Indicator Impacts
o Resiliency Metrics
• TAC 11 : July 30, 2024: 8:30 to 10:00 (PTZ)
o Preferred Resource Strategy Results
o Portfolio Scenario Analysis
o LOLP Study Results
• TAC 12: August 13, 2024: 8:30 to 10:00 (PTZ)
o Preferred Resource Strategy Results (continued)
o Portfolio Scenario Analysis (continued)
o LOLP Study Results (continued)
o QF Avoided Cost
• September 2, 2024- Draft IRP Released to TAC.
• Virtual Public Meeting- Natural Gas & Electric IRP (September 2024)
o Recorded presentation
o Daytime comment and question session (12pm to 1 pm- PST)
o Evening comment and question session (6pm to 7pm- PST)

AEG
APPLIED ENERGY GROUP
Avista Energy Electric
Forecasting
Prepared for Avista Energy TAC Meeting 4/23/2024
Confidentiality—The information contained in this presentation is proprietary and confidential. Use of this information is limited to the intended recipient and its employees and may not be disclosed to third parties.

Appendix A
Background
AEG has worked with Avista for multiple Conservation Potential Assessments going
0 back to 2010
As part of the CPA, AEG creates a baseline projection at the segments and end use
level, which provides granular insight on peak impacts and changes in individual
technology classes
Now Avista is using AEG's LoadMAPTM end use model directly to inform its official
-,0, load 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

Appendix A MajorModelingInputs and Sources
O
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)
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 3

Appendix A
Forecast Process C)
SegmentationF ININ F 0- 11wq
Market Characterization Run Baseline Projection Create Hourly Forecast
• use load shapes
e End Use and Technology List e Customer Forecast e Aggregate energy by shape
* ALLocate electric Loads & calibrate e Stock Turnover 9 Apply hourly shape throughout
e Purchase Decisions forecast period
L - oil 001110 - will"
Residential Electricity Projection By End Use
Residential Electric Use by Segment,2021 R,,id-tial Electric Intensityby End U—nd Segment 5,000 I I
■Cooling
LI-Mobile Home OOD 4,500 I{ ,lull
Ll-Mwe-Family 4% D0D .coorne 4,000 ■Space Heating3,500 ■Water Heating
3,000 Interior Lighting
"-*We •_ ■ t'i�1ine GWh 2,500 ■E#erior Lighting
Feaft/I 4RRIOMe: 2,000
aao .rGnneiareom ■Appliances
1,500mwp r
■Electron'ics
1,000
Mobile Home �1 500 ■Miscellaneous +
6% -e Famiy g amila Mwn ramilg rnoone xone Lil®e r r ar ■ II
3% - - a Generation ■T
(500)2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045
Applied Energy Group,Inc. appliedenergygroup.com 4

Appendix A
Existing vs New Buildin
Modeling tracks existing building stock Example WA Residential Intensity Comparison
separately from new code-compliant 14,000
buildings
12,000
Buildings also undergo renovation at a ■Cooling
rate consistent with the DOE's National 10,000
■Space Heating
Energy Modeling System, converting them
into code-compliant structures 8,000 ■Water Heating
Interior Lighting
Presence of equipment in new buildings kWh perHH 6,000
■Exterior Lighting
is adjusted to comply with energy codes
4,000 ■Appliances
where applicable
■Electronics
For example, all new residential 21000
structures are assumed to use electric ■Miscellaneous
heat pumps for space heating Existing New Generation
(2,000)
Applied Energy Group, Inc. I appliedenergygroup.com 5

Appendix A
System Total Load Forecast
Washington + Idaho Combined
Customer growth and electrification from 14,000
natural gas systems combine for a projected
53% increase in electric loads over the 12,000
forecast period, or 1 .6% annually
10,000
Growth from electrification is roughly equal
to growth from customer increases (N2,400 8,000
GWh each) GWh
6,000
Includes:
Projected cooling and heating degree days according to 4,000
climate trends in Avista's territory
Market efficiency impacts (such as trends toward LED
lighting as baseline), which are saving over 1,000 GWh in 2,000
the forecast period compared to minimum codes &
standards
0
Solar and EV projections from the DER study in Washington 2021 2024 2027 2030 2033 2036 2039 2042 2045
(Avista projections for Idaho)
■Industrial ■Commercial ■Residential
Applied Energy Group, Inc. I appliedenergygroup.com 6

Appendix A
Washington Sector- Level Forecasts C)WA Residential is the fastest growing sector, at 1 .97% per year, driven by space heating and EV
growth
Commercial EV charging also adds over 1 ,000 GWh per year by 2045
Industrial loads have continued to trend downward and no new load increases are anticipated
Residential Electricity Projection By End Use Commercial Electricity Projection By End Use Industrial Electricity Projection By End Use
5,000
■Cooling 3,500 700
4,500 ■Cooling
■Space Heating 3,000 600
4,000 ■Space Heating
■Water Heating — ■Cooling
3,500 2,500 Ventilation 500
■3,000 Interior Lighting ■water Heating Space Heating
2,000 400 Ventilation
2,500 Interior Lighting
■Exterior Lighting GWh Interior Lighting
GWh 2,000 GWh 1,500 ■Exterior Lighting 300 ■Exterior Lighting
■Appliances ■Refrigeration
1,500 1,000 200 ■Motors
■Electronics ■Food Preparation
1,000 ■Process
■Office Equipment ■Miscellaneous
500 ■Miscellaneous 100
■Miscellaneous
- - �Generation - _
(500)
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045 2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045 �Generation 2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045 2047
(500)
Applied Energy Group, Inc. appliedenergygroup.com 7

Appendix A
Idaho Sector- Level Forecasts C)
• ID load growth is not as fast as WA, mainly due to lower electrification and much less Ev.
• ID is projected to see greater increase in customers than WA however, so there is still significant
growth in both the Residential and Commercial sectors
Residential Electricity Projection By End Use Commercial Electricity Projection By End Use Industrial Electricity Projection By End Use
2,500
■Cooling 1,400 450
■Space Heating 1,200 ■Cooling 400
2,000 ■Space Heating
■Water Heating 350 ■Cooling
1,000 Ventilation
1,500 Interior Lighting 300 ■Space Heating
161000
■Water Heating
800 250 Ventilation
■Exterior Lighting Interior Lighting GWh
GWh 1,000 1111000-0.008000 GWh 600 ■Exterior Lighting 200 Interior Lighting
■Exterior Lighting
■Appliances ■Refrigeration 150
500 400 ■Motors
■Electronics ■Food Preparation
100 ■Process
■Miscellaneous 200 ■Office Equipment 50 ■Miscellaneous
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045 0 Miscellaneous
Generation - _
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045 C Generation
(500) (200) 2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045 2047
Applied Energy Group, Inc. I appliedenergygroup.com 8

Appendix A
Peak Forecasts
WA Total System Peak w/o DSM
Winter system peaks are projected to be 2W0 qD
higher than summer by around 2030+, 1800
however this projection is very sensitive to 16001400
assumptions on when EVs will be charging. 1200
M W 1000
AEG used an annual charging shape 800
600
provided by Cadeo and developed in the 400
DER study. 200
0
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045 2047
Total System Peak Contribution by State EWA Total Summer Peak 0WATotal WinterPeak
3,000
ID Total System Peak w/o DSM
2,500
900
2,000 800
M W 1,500 700
600
1,000 ■ID 500
M W 400
500 ■WA
300
0 200
m m Ne M M 100
Ojai a, a a a a a a a a a
a s a s a s a s a s a s
0
E �_ E �_ E �_ E �_ E �_ E c 2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045 2047
E E E E E E
"' "' "' "' "' "' ■ID Total Summer Peak ■ID Total Winter Peak
2021 2025 2030 2035 2040 2045
Applied Energy Group, Inc. I appliedenergygroup.com 9

Appendix A
Electrification Decision Modeling
Washington Residential Gas Heating Market Transformation
16°,0o0
0
Gas customers were modeled the same way as 140,000 .Au Source Heat Pump
(ENERGY STAR 6.1)-
Boiler
the electric market, with the option to replace 120,000 ■Air-Source Heat Pump
(ENERGY STAR 6.1)-
existing gas space or water heating equipment Furnace
300,000 Dual-Fuel Heat Pump-
with electric alternatives, using purchase decision AFU E 96
Households 80,000 ■Dual-Fuel Heat Pump-
Logic copied from the US DOE's National Energy AFUE80%
Modeling System. 60,000 ■Gas Boiler
40,000
Conversion costs include the possibility of a panel 20,000
upgrade and associated labor. The model o
a a a compares the lifetime cost of ownership including
N N N N N N N N N N N N N N N N N N N N N N N N N N r
up front costs and associated lifetime fuel costs.
Idaho Residential Gas Heating Market Transformation
As data on customer electrification is not readily 140,000
available*, electrification purchases were seeded ■Air-SourceHeat Pump
6.1)-
120,000 (ENERGY STAR 6.1)-
Boiler
with a value '/a that of dual-fuel heat pump ■Air-Source Heat Pump
100,000 (ENERGY STAR 6.1)-
installations, which do have documented market Furnace
Dual-Fuel Heat Pump-
B° AFUE 96%
shares for WA and ID.
Households ■Dual-Fuel Heat Pump-
60,000 AFU E 80%
■Gas Boiler
40,000
20,000
0
a a a
N N N N N N N N N M M M M M M M M M < V V V a V V R
O O O 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
Applied Energy Group, Inc. I appliedenergygroup.com 10

Appendix A
Electrification Projection
Stock share converted by 2045
Residential
49 Washington
• •
Space Heating - Dual-Fuel Heat Pump 29,422 (20.0%) 19,424 (16.7%)
Space Heating - Full Electric ASHP 6,242 (4.3%) 1 ,578 (1 .4%)
Water Heater - HPWH 1 ,611 (1 .7%) 256 (0.4%)
Washington
Space Heating - Dual-Fuel Heat Pump 515 (6.7%) 760 (8.9%)
Space Heating - Full Electric ASHP 134 (1 .8%) 46 (0.5%)
Water Heater - HPWH 712 (8.3%) 678 (6.7%)
Applied Energy Group, Inc. I appliedenergygroup.com

w
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Thank
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Phone: [phone] APPLIED ENERGY GROUP

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2025 IRP Load Forecast
James Gall & Mike Hermanson
Technical Advisory Committee Meeting No. 5
April 23, 2024

Appendix A
Transition End Use Model to Load Forecast
Energy Peak
• Starts with AEG's forecast w/ & w/o DSM • Estimate 2024 weather adjusted peak load
• Add energy losses (T&D) using historical and future weather data for
• Add large industrial loads each month
• Escalate loads using AEG's end use
model's peak growth factors
• Add large industrial loads
• Demand response and/or managed loads
not included
The PRISM model will include a load forecast without DSM and the model will select
cost effective programs and may adjust this estimate to ensure the amount of selected
energy efficiency arrives at a similar net load forecast as presented today.
2 .

Appendix A
Energy Forecast
1 ,600
1 .47% AAGR
1,400
0.91 % AAGR
1,200
3 1 ,000 1 .69% AAGR
0.94% AAGR
M 800
c�
600 1 .07% AAGR
Q ____ 0.85% AAGR
400
WA- 25 IRP --- WA- 23 IRP
200 ID- 25 IRP ——— ID- 23 IRP
—System- 25 I RP ——— System- 23 IRP
Actual- 5yr Forecast
0
Ln Cfl ti 00 O O — N CO I Ln Cfl I— 00 O O N M 't Ln O ti 00 M O N M1:T Ln
V— V— V— — — N N N N N N N N N N CO CO CO M CO CO M CO M CO :t It ItIcT 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
N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N
3
Note: Includes 67 aMW of energy efficiency w/losses: -60 aMW (WA) & -7 aMW (ID)

Appendix A
Peak Distribution
2024 Peak Value Summer Months - Modeled for Weather Years 1890-2045 2024 Peak Value Winter Months - Modeled for Weather Years 1890-2045
25 20
Average Peak Value 1789 MW
Average Peak Value 1878 MW
18
20 16
2023 Peak Demand-1857 MW 14
2024 Peak Demand-1981 MW
15 12
U T
C U
v 7 10
0/ Q
L
10 u
8
6
5 4
et 4
ry ry1 0
ry00 Op1 0;�1 On'1 Ot�'1 ryc�'1
O°j• ^O, ,y0' y^, ^N' Off.' ,�^�' h• O' �o' ^' 0' 0' oi' O^ O• �. 'Y' ^O �.O �.O ^^ ^^ ^,� ^q� ^q�' ^O ^g ^oi ^0 NO NO NO NO N N ti tiry
h o 0 0 0 0 � �"�' ,�`�` ,�^ ^o � o0 0`' ,�^ mo ary oa a`O aw o• o• ti' h' ,�' �,• ^' ,�' y. ,�' o• ^• ,�' y. ,�'
.
^O O
Load and Temperature Load and Temperature
2002 MW 93 OF 2226 MW -17 OF
1589 MW 77 OF 1588 MW 28 OF
1791 MW 82 OF 1892 MW 3 OF
4

Appendix A
Peak Forecast ( 1 -in =2 weather event)
3,000
2,500
2,000
1,500 ••
1,000
——— 2023 IRP Summer ——— 2023 IRP Winter
...... Actual Summer 2025 IRP Summer
2025 IRP Winter ...... Actual Winter
500
0
O N M "t '0 (O 1-- O O O N M 't M O rl- M O O N M I- M
N N N N N N N N N N CO M CO CO CO CO CO CO CO CO ' '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
N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N
5
Note: Historical peak values include curtailed loads

Appendix A
2025 Electric IRP Portfolio Proposed Scenario List
Sensitivity Study Study
(2030
1 Preferred Resource Strategy Deterministic X X
Low NG Prices
High NG Prices
2 Alternative Lowest Reasonable Cost
3 Baseline: Least Cost Reliable Portfolio Deterministic X X
Low NG Prices
High NG Prices
4 Clean Resource Portfolio by 2045 Deterministic X X
Low NG Prices
High NG Prices
5 Low Growth (Low Load Growth)
6 High Growth (High Load Growth)
7 80% Washington Building Electrification by 2045
8 80% Washington Building Electrification by 2045 &
High Transportation Electrification Scenario
9 Extreme Building/Transportation Electrification for X
Washington & Idaho w/o new Natural Gas CTs
10 Maximum Washington Customer Benefits
11 Least Cost+ 500 MW Nuclear in 2040 Deterministic X
Low NG Prices
High NG Prices
12 WRAP PRM X X
13 Least Cost+ 0% LOLP X X
14 Power to Gas Unavailable X
15 Minimal Viable CETA Target
16 Maximum Viable CETA Target
17 Preferred Resource Strategy w/CCA repealed No CCA Forecast
18 Unconstrained Cost Preferred Resource Strategy
19 High QCC on Demand Response (w/minimum X
selection)
20 Data Center in 2030 X
21 Nuclear Cost Sensitivity
22 RCP 8.5 Weather X X
23 80% Washington Building Electrification by 2045 & X
High Transportation Electrification Scenario with
RCP 8.5 Weather
Avoided Cost Portfolios
A No Supply-Side Resource Additions
B Clean Capacity by 2045
2025 Electric IRP Scenario Listj Page 1

Appendix A
Scenario Description:
1- Preferred Resource Strategy: Using the expected case load, resource, and stochastic price
forecast, the model will determine the least cost resource strategy meeting each state's energy
and capacity requirements. Portfolio will also track Customer Benefit Indicators in Washington
and use Social Cost of Greenhouse Gas (SCGHG), Non-Energy Impacts, and Named
Community Fund (NCIF) spending for Washington's portfolio optimization. Idaho's optimization
will focus on least cost to meet energy and capacity requirements. Portfolio uses planning margin
requirement to ensure 5% Loss of Load Probability (LOLP) in 2030. CETA targets are shown in
Figure 1.
2- Alternative Lowest Reasonable Cost: Required study to determine CETA cost cap impacts.
This scenario assumes no CETA clean energy requirements, no NCIF, but includes SCGHG for
resource selection [in Washington] while meeting physical monthly energy/capacity requirements.
3- Baseline: Least Cost Reliable Portfolio: Determines the least cost portfolio to meet energy and
capacity requirements based on economic decisions w/o SCGHG or CETA; same as the
`Alternative Lowest Cost Alternative' scenario w/o SCGHG prices for Washington. The portfolio
will also be used to develop avoided costs as it separates portfolio costs by renewable and
capacity premiums; quantifies the impacts of SCGHG.
4- Clean Resource Portfolio by 2045: Determines the portfolio to eliminate all greenhouse gas
emitting generation resources in the portfolio by 2045. The resulting portfolio must meet all
capacity and energy requirements.
5- Low Growth (Low Load Growth): Studies the portfolio effects of loads not materializing due to
lower growth than forecasted.
6- High Growth (High Load Growth): Studies the portfolio effects of higher load levels
materializing due to higher growth than forecasted.
7- 80%Washington Building Electrification by 2045: Determines the least cost portfolio of
converting 80% of Washington State natural gas residential and commercial demand to electric
through heat/water conversions to heat pump and resistance technologies by 2045.
8- 80%Washington Building Electrification by 2045 & High Transportation Electrification
Scenario: Determines the least cost portfolio of converting 80% of Washington State natural gas
demand to electric through heat/water conversions to heat pump and resistance technologies by
2045 along with a higher-than-expected electric transportation forecast.
9- Extreme Building/Transportation Electrification w/o new Natural Gas CTs: Determines the
least cost portfolio of converting 80% of Washington & Idaho natural gas demand to electric
through heat/water conversions to heat pump and resistance technologies by 2045 along with a
higher-than-expected electric transportation forecast for both states. This scenario also assumes
all natural gas resources are retired by 2045.
10- Maximum Washington Customer Benefits: Washington State required scenario to understand
the portfolio and cost impacts of improving Customer Benefit Indicators. This portfolio will exclude
non-Washington sited resources and resources with air emissions. The objective will select
resources to lower energy burden through additional energy efficiency and community solar for
named communities. Higher named community penetration of roof-top solar and electric vehicles
from the Distributed Energy Resource Study will also be considered.
11- Least Cost+ 500 MW Nuclear in 2040: Uses the Preferred Resource Strategy assumptions with
the addition of up to 500 MW of nuclear generation beginning in 2040.
12- WRAP PRM: Solves for the least cost portfolio meeting capacity, energy, and state policies using
the Planning Reserve Margin currently required in the WRAP.
13- Least Cost+ 0% LOLP: Solves for the least cost portfolio meeting capacity, energy, and state
policies, but acquires generation to ensure the loss of load probability (LOLP) is zero rather than
5%.
14- Power to Gas Unavailable: Similar portfolio design as the "PRS" scenario without the option of
using power to gas fuels such as Ammonia or Hydrogen.
2025 Electric IRP Scenario Listl Page 2

Appendix A
15- Minimal Viable CETA Target: Uses the same portfolio design as the"PRS" scenario except the
CETA targets for clean energy use the minimal viable targets from Figure 1.
16- Maximum Viable CETA Target: Uses the same portfolio design as the"PRS" scenario except
the CETA targets for clean energy use the maximum viable targets from Figure 1.
17- Preferred Resource Strategy w/CCA repealed: This portfolio uses the No CCA market price
forecast and estimates the portfolio if the CCA is repealed by voters in November 2024.
18- Unconstrained Cost Preferred Resource Strategy: In the event the PRS scenario is
constrained by the 2% cost cap, this portfolio illustrates the cost to comply with 2045 CETA
regardless of cost.
19- High QCC on Demand Response (w/minimum selection): This portfolio will be optimized
using a higher QCC for demand response programs than used in the PRS scenario. If the
portfolio does not result in higher demand response, the lower cost program options will be
included in the portfolio.
20- Data Center: Add 100 MW of load in 2030 due to a new data center load.
21- Nuclear Cost Sensitivity: Determine cost of nuclear to be selected in PRS (if not already
selected)
22- RCP 8.5 Weather: Use RCP 8.5 climate future for the load forecast
23- 80%Washington Building Electrification by 2045 with RCP 8.5 Weather: Determines the
least cost portfolio of converting 80% of Washington State natural gas residential and commercial
demand to electric through heat/water conversions to heat pump and resistance technologies by
2045 includes RCP 8.5 weather for the load forecast.
Avoided Costs Portfolios:
No Supply-Side Resource Additions: This "portfolio" is only used to estimate the capacity premium of
the avoided cost calculation; uses same EE selections as `PRS' scenario; uses same assumptions as
`baseline' scenario except uses market purchases to meet demand instead of acquiring new resources.
Clean Capacity by 2045: This portfolio is similar to the `baseline' scenario except it does not allow for
new natural gas generation, does not require the model to satisfy monthly energy targets and assumes
Coyote Springs 2 is not available in Washington in 2045. The portfolio is used to determine the clean
capacity credit for avoided cost calculations only.
2025 Electric IRP Scenario Listj Page 3

Appendix A
Figure 1: CETA Target Scenarios
0 0 0
0 0 0
0 0 0
100% o 0 0 0
■Minimal Viable Targets
95% ■Expected Targets N
0
CD
CO ■Maximum Viable Targets o o
O 90% Cq 00
W 00
J o CO
lfi
o �
CU 85% o o m N
o o 00 CO
ry o 0 0
80% o 00 ro ro
0
L
00
O o `�°
LO
75% o CO M r
( o LO
CU
o
70% o
0
4--
0 o
+� 65% v> `n U> w
C� N N
O
60%
0-
55%
50%
2026 2027 2028 2029 2030-33 2034-37 2038-41 2042-44 2045
2025 Electric IRP Scenario Listj Page 4

Appendix A
Fifth TAC Meeting for the 2025 Electric IRP, April 23, 2024, Meeting Notes
Attendees:
Sofya Atitsogbe, WUTC; John Barber, Avista; Amber Blackstock, Avista; Shawn
Bonfield, Avista; Annette Brandon, Avista; Molly Brewer, WUTC; Kate Brouns,
Renewable NW; Michael Brutocao, Avista; Katie Chamberlain, Renewable NW; Josie
Cummings, Avista; Stefan de Villiers, PCU; Mike Dillon, Avista; Chris Drake, Avista;
Jean Marie Dreyer, WA Public Counsel; Michael Eldred, IPUC; Ryan Finesilver,
Avista; Damon Fisher, Avista; Grant Forsyth, Avista; James Gall, Avista; Bill Garry,
Customer; Konstantine Geranios, WUTC; Amanda Ghering; Avista; John Gross,
Avista; Leona Haley, Avista; Kyle Hausam, Avista; Lori Hermanson, Avista; Mike
Hermanson, Avista; Andy Hudson, Applied Energy Group; Fred Heutte, NW Energy
Coalition; Allison Jacobs, PSE; Clint Kalich, Avista; Mary Kulas; Erik Lee, Avista;
Kimberly Loskot, IPUC; John Lyons, Avista; Patrick Mahr, Avista; Jaime Majure,
Avista; James McDougall, Avista; Ian McGetrick, Idaho Power; Tomas Morrissey,
NWPCC; Fong Nguyen, AEG; Kevin Nordt; Michael Ott, IPUC; Tom Pardee, Avista;
John Rothlin, Avista; Ryan Sherlock, Avangrid; Amanda Silvestri, BPA; Nathan South;
Darrell Soyars, Avista; April Spacek, Avista; Dean Spratt, Avista; Victoria Stephens,
IPUC; Lisa Stites, Grant County PUD; Charlee Thompson, NW Energy Coalition;
David Thompson, Avista; Kenneth Walter, AEG; Jared Webley, Avista; Bill Will,
WASEIA; Kelly Xu, PSE; Yao Yin, IPUC; Cole Youngers, Avista
Introduction, John Lyons
John Lyons: Welcome to the fifth TAC meeting for Avista's Electric IRP for 2025.
Glad you're able to join us and we're getting good feedback on having these more
often shorter TAC meetings. So, we aren't showing off as much as the same time.
Today is going to be a big change for us because we're going from our traditional
forecast. Grant would have presented last time where he did our economic and the
short-term forecast, but now for the long run forecast, AEG has been doing that. We're
having them do for us, so they will go through that. Then we'll talk about our load
forecast comparison and the changes between the two. And we are going to finish up
with the scenario analyses that we started talking about last time. We have at least
one addition in there and if you've got any other changes, we'll talk about those. We
have the upcoming meetings every two weeks. We do have the Fourth of July week
off. It is out there, but that will get cancelled. We won't have that meeting, but next time
we'll also be a very AEG focused meeting with the conservation potential assessment
and the demand response potential assessment. I also still need to send out the
Technical Modeling Workshop meeting because that is a little bit off the schedule, and

Appendix A
you can see the rest of those coming through into August. Alright, James, is there
anything you'd like to say before we get started?
Lonq Run Load Forecast, AEG
James Gall: I just wanted to introduce AEG and Ken Walter, and I wanted to thank
him for presenting to us today the work that he and his team have done on our load
forecast. It's definitely a new methodology that we're approaching, and I see Ken has
his camera on and. Are you ready to go?
Ken Walter: Yeah, I think I am. I was actually seeing if anybody else from my team
had managed to jump on here. You guys like a nice early start, but it looks like I'll be
Speaking for AEG today, which is fine.
James Gall: Yeah. Alright. Well, we'll turn it over to you.
Ken Walter: Alright. And then our second technical check of course is can folks see
the screen that I'm presenting?
James Gall: We can.
Ken Walter: Ken Walter: OK, great, right.
James Gall: We're good and can all be watching the chat, and Lori will be as well for
any questions on the chat. Anybody feel free to raise your hand and then I'll call on
you. That way, Ken doesn't have to monitor that.
Ken Walter: Thanks, James. Appreciate it. Alright, with that intro for anybody who
doesn't know me on the call already, my name is Ken Walter, I'm senior manager with
Applied Energy Group. I lead our market assessment division, which is pretty much all
things potential study, market research, and in this case specifically baseline
forecasting. Just a little bit of background, we have been working with Avista for
multiple CPAs going back all the way to 2010, and always as part of those CPAs, we
do develop a baseline projection. Now normally the process would be, we would
develop a projection, compare it to the forecast that Grant would give us and then look
for any differences in assumptions there might be driving those gaps. And that's really
only used for the CPA calculations, and it's not used by Avista for full load forecasting.
But there are advantages in using a full end use model for forecasting, which is why
we've undertaken this joint effort with Avista where you can really explicitly put in things
like building code changes, changes in standards to equipment and rather than having
to do some kind of trending from the past, you actually have that in as an explicit built

Appendix A
in effect that's going into the forecast. It affects future energy loads and of course, as
we get further down the line in the CPA, it affects potential as well.
Ken Walter: Major modeling inputs and sources are the same as what we would
normally use in the normal CPA process. It starts with Avista's foundational data that
is actual power sales by individual schedules that we can allocate into our modeling
sectors. It is current and forecasted customers. Those still come straight from Avista
and from Grant's forecast. New to this part is actually including the retail price forecast
because customer behavior is sensitive to that. And adding that enhancement to the
way that we're modeling was an important step this time around. The second piece is
as we are allocating all of that energy down into the different technologies and end
uses, we need data to break that up and that starts with survey data. Avista has a
residential customer survey from 2013. We combine that with survey information from
the NEA residential and Commercial building stock assessments. You see, I've noted
we are still using [Residential Building Stock Assessments] RBSA 2016. The RBSA
2022 data was just released a couple of weeks ago. It was not in time to be part of this
particular buildup, so that'll be part of the next CPA. Also, a lot of information from the
US Energy Administration. They have their own survey information, the RECS data,
which as of 2020 is down to the state level. On very detailed, there's also CBECS 2018
data that was just released last year. And again, we start as tight as we can to Avista
data and then expand from there to gap fill as needed or to break things into more
specific pieces.
Ken Walter: Then we need options for how things are going to change over time, and
we need the technical details on how pieces of equipment use energy so that technical
data on end use equipment costs and energy consumption comes. Again, we start as
local as possible. RTF workbooks, Northwest Power and Conservation Council's
Power Plan workbooks. We expand out from there to US DOE sources, Energy Star
technical data sheets and other information from the EIA, including their Annual
Energy Outlook, which is a national energy model that they update every year, and we
take a lot of their input information and in some cases even their same calculation
methodology, which I'll talk about in a little bit. Another huge input and a big part of
why we do it this way is state and federal energy codes and standards. Keeping track
of the separate realities of Washington State Energy Code, Idaho Building Codes and
Energy Codes. And of course, federal energy standards, which are constantly under
update. We have an engineering team that spends a long time keeping up with all of
their changing rules and what's going to happen in the future. The final thing that we
want to incorporate is the actual market trends and effects. There are cases where
you have something like LED lighting, which technically is above the federal minimum
standard of lighting but is one of the most common purchases that people are making

Appendix A
in the current years. We include things like RTF market, baseline assumptions on
different equipment classes and as mentioned, the Annual Energy Outlook, which
does include purchase decision trends that we can seed our model and then let things
like what's going on with retail prices or local weather influence decisions from there.
It takes a lot of data to build these up.
Ken Walter: The process, and I'll be focusing just on this baseline forecast for this. I
won't be talking about the CPA portions specifically, but it still looks a lot like it does
for our standard CPA process. We start with market characterization. This is for a
singular base year, something that we have a complete calendar year of data. We
could look at actual customer consumption and use per household or per commercial
building, breaking that up into different segments that have different classes of energy
use. Single family homes and multifamily homes don't use energy the same way.
Ken Walter: We have a low-income segment for each housing type. On the residential
side and on the commercial side, we break things down into different businesses
because again, your restaurant, your hospital and your office building don't have the
same kind of end use loads. They don't have the same kind of schedules, and that's
critical. Once we get to the third block on here. Once we have all of those energy loads
calibrated down and actually shared out, made sure that it's matching the billing data
by the kWh, then we can run a baseline projection first on an annual basis. That's the
way our models are originally set up and this can track customer forecasts, stock
turning over, you have vintage units that maybe a little out of date. They turn over into
at least minimum efficiency, and if we have one of those market trends, they may go
above that keeping track of all the stock that's actually present in each of those options
and running everything through a purchase decision model to try and predict what
customers are going to be doing just on their own. Those annual values, and this is a
big enhancement for this effort, now with Avista is to turn those annual values into an
hourly forecast, which is what Avista needs for its planning purposes. To do this, every
end use, every piece of technology, is assigned to an end use load shape and in some
cases those are even specific to different building types, and different technologies.
Even heat pumps versus electric resistance heat for example, aggregating all of these
disassociated energy loads to their individual shapes and then calibrating that again,
back to an actual year, we have 2021 and 2022 actual hourly loads from Avista. We
can calibrate the model output for those two years and then apply those factors to all
future years so that we actually get hourly shaped loads all the way into 2045-2047
that are shaped correctly to what Avista has seen on its system in the past. Since
we're tracking individual loads as space heating load or cooling load or whatever it is
growing differently because of the different end use as being calculated. You can see
how that might change the hourly shape on the year for Avista's system into the future,

Appendix A
and we'll take a look at some of those results in a minute. Any questions that we've
gotten to so far that are burning in people's minds?
James Gall: You have no questions in the chat yet.
Ken Walter: OK, great. A couple of the finer details before we see results. One of the
things we do have to keep track of is existing versus new building stock or at least
code compliant which we call new. New construction does include a certain amount of
renovation of existing, but new construction is just easier to say. The important things
here is that we're adjusting all of the new buildings or good compliance to conform with
the energy codes in the respective states. That includes upgrading our values and
changing those in our simulations. It also includes presence of equipment where we're
expecting less gas in Washington and more electric heat. But of course, it's going to
be heat pumps. There are a lot of factors influencing up and down use per household
or use per commercial structure. All new residential structures are assumed to be
using electric heat pumps in Washington. Still a good presence of them in Idaho, but
of course it's not mandatory. All of those things are being kept track of as the model
runs through and we have a difference in the stock between the two.
Ken Walter: Then we get to results which have a very interesting uptick. We'll talk
about what's actually driving all of that. This look is total consumption year over year,
total GW hours for Washington and Idaho combined. There are a lot of things
contributing to this growth. First, there is customer growth and that is provided by
Avista. There is also electrification going on and that is something that we are modeling
explicitly. We have modeled the gas system and the electric system, and the gas
customers are given the opportunity, not required, but allowed through economic
purchase decisions to electrify if it looks attractive from the customer perspective or at
least relative to other options. We're growing by 53% out to 2047 or about 1.6%
annual. The total electrification growth and the total growth just because of customer
increases are about a 50/50 split. It's about 2,400 GW hours for each by the end. This
is inclusive of projected cooling and heating degree days. This is a climate trend
inclusive forecast. It also does include, as I mentioned, market efficiency impacts. So,
this is naturally occurring purchases of efficient equipment LED being the most
obvious one, but including some other things as well, some higher efficiency heat
pumps or things that are seen in past purchase data and expected to continue. Those
are saving about 1,000 GW hours in this forecast period, so if you can imagine that
green line being another inch taller on the right, that's what it would be without those
market baseline assumptions.

Appendix A
Ken Walter: We're also including solar and EV projections in Idaho. Those are again
from Grant's projection, based on trends that they've seen in their customers on the
Washington side. There is the concurrent DER study that has been going on for Avista.
We took the same solar and EV projections for Washington that were part of that study,
and a lot of that Bell Curve is also inclusive of EVs. They have some interesting
implications. Looking at the sector level for Washington overall, across both states and
all sectors, Washington residential is the fastest growing place. It's almost 2% a year
and that is space heating growth as people are bringing on heat pumps from
electrification and EV growth. If you look down at the bottom left chart, you can see
that gray wedge a little more than doubling in size, EVs are a significant piece of that
gray miscellaneous category. Commercial EV charging is also coming on and that's
adding over 1 ,000 GW hours by 2045, so it is a not insignificant load.
Ken Walter: Industrial loads are continuing to trend downward. This is just in keeping
with past industrial, there's no anticipated large new loads coming online there. Same
perspective for Idaho. Although customer growth is actually going to be, or is projected
to be, a little bit larger in Idaho. The actual load is not growing as fast because there's
much less electrification and much less EV that are expected to come on in Idaho at
this time. You do still see some pretty good growth, but that is mostly from customer
increases.
Ken Walter: Let's look at peaks. This is a very interesting one. What you'll see in the
trend is if you look right around 2030, that is the parity point where winter system peaks
outpace summer and that is as more of these electric heat pumps are coming online.
They are more peak efficient than electric resistance, but they are still contributing to
greater winter electric loads, especially around the coldest parts of the year. There is
also a significant contribution to peak in both seasons from these EVs. When people
charge has a lot of sensitivity around where the peak actually hits. There's a lot of
vehicles out there. If they're all plugged in at the same time, that's a lot of load. We are
currently using an annual charging shape across the year that was provided by
CADEO with part of the DER Study. Obviously, there are a lot of assumptions that are
based into that, probably one of the main things to mention is that it does not assume
that people are trying to avoid a peak hour. It's not a time of use shape, and that's
something that can definitely be explored in scenarios like James was mentioning
earlier. That's one thing I will say about this is the exact shape or magnitude of these
peaks is very sensitive to where that EV load lands could be a lot higher. This is
actually not assuming they're all coincident, but it could also be lower than this if they
were all shifted completely away from the peak hour.

Appendix A
Ken Walter: I mentioned electrification and I'm sure some people were curious about
a little more detail on how we're modeling that. This is completely focused on the
electric forecast, but I want it to mention the gas modeling that we're doing so that we
could contribute these inputs to the electric forecast and have an understanding of
where the gas customers may be coming over. We have gas models set up the same
way as we do the electric. And as I mentioned, they're given the option basically
alongside various efficiencies of gas equipment. There is an electrification option that
uses no gas but has an annual cost of the electricity for whatever model. That would
be whether that's a heat pump, water heater or an electric heat pump heating system.
We offered both dual fuel heat pump replacements, so gas backup system and a full
electrification option which was much less economically attractive. We're using the
purchase decision logic that is copied from that Annual Energy Outlook. The National
Energy Modeling system, which basically just evaluates relative to one another the
recognized attractiveness. It then can be calibrated to existing purchases that have
been seen in the market. It does its own shuffling from there to look as things change
into the future. How does that change? It uses those calibration factors again to say,
people are already doing some of this or very little of this compared to how attractive
it is and it uses those terms into the future. If you look over on the right, you can see
up in Washington, we have a lot more expansion, but if you notice it's the two green
lines, actually the dual fuels are significantly more present than full electrification. The
gas backup systems are just less expensive and there's a lot more attractiveness there
and more purchase data just in the background information that we have, they are
pretty well present.
Ken Walter: There is some weakness in seeding these just because it is very difficult
to get information on what people replaced gas with. Electric, there's a lot of surveys
that you can identify who has heat pumps now, but things like RSA and Rex don't ask
what you replaced. So, for right now we are seeding full electrification away from gas
with a value that's about 1/4 of the existing dual fuel purchases, which those are well
documented. It seems to provide a pretty good picture that matches assumptions for
Washington and Idaho. That is another assumption that could be updated, but it's
working pretty well and giving a fairly sensible result at the moment, but just wanted
to mention where that information is coming from. And if anybody likes numbers,
because we're all people who like numbers around here, this is the total share of gas
customer stock that gets electrified by 2045. In our current modeling, in residential, it's
a hair shy of 30,000 dual fuel heat pumps go in. In Washington, a little shy of 20,000
in Idaho, full electric is obviously significantly less, but much stronger in Washington.
A little over 6,000 units, around 1 ,500 in Idaho and then heat pump, water heaters
replacing gas systems about 1 ,600 in Washington, they gain a big boost from being
focused on in the code. That's not including anything from new construction code, but

Appendix A
it's just there's a lot of trend towards them in Washington, whereas in Idaho, there's
only 256 units. It's not a very attractive option in the C&I space, it's much lower, it's
just it's not as strongly competitive in C&I. There's not a lot of economic drivers and
really not a lot of past purchase data that suggests directive, so dual fuel heat pumps
is a few hundred, 515 in Washington, actually a few more in Idaho. Again, that's just
related to the seed data. I was a little bit surprised, but there are a few more dual fuel
heat pumps that already exist in Idaho than in the Washington data. Could be a source
bias, but that's what we're running with. And then for full electrification, very small 134
in Washington, just 46 systems in Idaho. And then for water heaters, 712 in
Washington and 678 in Idaho. So, pretty similar, but also just small numbers all around
in C&I. And that's everything I've got prepared slide wise, but I'm happy to field
questions if there are any at the time.
James Gall: You have nothing in the chat yet or hands raised, but I did want to
mention one thing because you mentioned on the EV shape and then you know we're
using what we call a non-mitigated load shape for EVs. When we look at our demand
response options in the next TAC meeting that you'll provide, that will help us put an
option out there to see what it costs to try to manage those EV shapes. That will be
coming in the next TAC meeting. But I'm just going to pause a little bit for any questions
that people have before we go to the comparison to the last IRP. You got off easy,
Ken. I don't know if I'll get that treatment, but a question, we got one. I'll go ahead. It's
in the chat. I'll read it out. Why do we use Grant's forecast for short term instead of this
forecast? That's a good question. I don't know. Grant, do you want to take that one if
you're online?
Grant Forsyth: Yeah, this is Grant. Because Grant doesn't want two different
forecasts in the short term.
James Gall: That's a good answer, Grant, but yeah.
Ken Walter: It's a very good answer, actually, and neither do we.
James Gall: Grant's forecast is used for the company's financial planning. And having
two forecasts does create issues. We have another question. Chat from Michael Ott.
I'll read it. Is the dual fuel heat pump more common in more extreme winter climates
compared to milder climates?
Ken Walter: We were really only looking at the data specific to Washington and Idaho,
so I didn't actually compare it to some of the milder states or more southern states.
That's a pretty interesting question we could take a look at. They're not huge. They're

Appendix A
less than around 5, plus or minus percent of purchases kind of anywhere we saw, but
I could take a look and see what some of the other states look like.
James Gall: And then we have another question. How do we handle the transition
between the two forecasts? So, between Grant's five year and the long term.
Ken Walter: Is that a question for me or for you well?
James Gall: I think it might be for you.
Ken Walter: We are calibrating our model to grants forecast. Once we've run out of
Grant's stuff to calibrate to, our model is just off on its own from there, but because
we've spent those first few years calibrating, it's really starting in lockstep and just
carrying those trends forward.
James Gall: Thank you. Let's pause a little bit again for any more thoughts that come
up. We have a hand up, Kate, go ahead.
Kate Brouns: Hey, thank you. I just said I'd speak this in case it was a little more
complicated, but you mentioned using a customer survey from 2013 and I can't recall
what that survey was exactly used for but was hoping you could speak to. Does that
feel like it's still relevant or does it need to be redone or is that informed by other
surveys to feel more updated?
Ken Walter: Yeah. I'd say at this point we've shifted to mostly using our BSA data and
Rex data with an eye on the old GENPOP survey just because it is a little bit more out
of date and not to put too many people on the spot. But we did just send a proposal
over to Kim Boynton on the CPA side and recommended a new market research
survey. Although many of the utilities here are in RBSA territory, we have sometimes
suggested that every once in a while it's good to do your own. Take the temperature
of your own customers, especially because you can ask questions that RSA doesn't.
It could be very useful for you. It's still nice to get a look at how Avista customers, at
least at that time, were different from the basic RSA population and we still apply some
of those trends and shifts just because two groups are not the same. But yeah, we've
mostly moved to more recent sources. And then if Avista was to do another survey,
that would immediately become our top priority source again.
Ken Walter: Alright. I see another one in the chat. I can actually look at the chat right
now. Benefits of a couple of screens. Can we explain why Idaho expects a total system
winter peak before Washington? If you just look at the first couple of years, you can

Appendix A
actually see that in Idaho the winter and summer peaks are just closer together to
begin with. So, it doesn't take very much growth in space heating for it to outpace the
summer peak. One thing I should mention as we're electrifying systems, we are
accounting for people who already have cooling. That's another thing that's going on
is we may be bringing over a heat pump, but it's not just adding cooling load to the
summer side where deducting people who already had essential AC or a room AC
depending on what kind of heat pump came over. That difference can be there as well.
James Gall: OK. I think we're close. I don't see any more hands or questions. Ken,
thank you very much and I will now.
Ken Walter: No. Yeah, absolutely. And if questions do pop up, feel free to pass them
through James. He'll hand them off to me.
James Gall: OK, alright. There's one more from Yao. We got a new one. Yes, the
short-term forecast doesn't take into account of any use, correct?
Grant Forsyth: Yeah.
James Gall: So that would be yes and no.
Ken Walter: That's correct.
James Gall: I would argue.
Ken Walter: Well, yeah, it takes into account historical trends and Grant can tell me if
I'm putting too many words in his mouth and on the very short term, that's usually
enough or you're not going to see enough disparity between the end use forecast and
the short term. It's really the long term that the end use really starts to see things that
the short term can't see.
Grant Forsyth: Yeah, this is Grant. Yao, my model is a time series forecast and so
end-use trends are going to be embedded in the data. Historically, and hopefully I don't
have this wrong, Ken, it hasn't been that hard to match the short term forecast with
what you guys are doing in terms of your modeling approach.
Ken Walter: Correct. Yeah, we're talking like 10t" of a percent adjustments at most.
Forsyth, Grant: Right. So, it's really just making sure from a policy point of view that
the forecast we're using to make financial decisions isn't different than that first five

Appendix A
years in the IRP. We want consistency there and it's pretty acceptable I think because
again it's not that far off from what AG's models would produce on its own and which
means that transitioning to the longer term is, is again not a problem. OK.
James Gall: Alright. Anything else? OK.
Grant Forsyth: Thanks Yao.
Load Forecast Comparison, Avista Staff
James Gall- All right, so the goal, the next slide deck is to really go through, how does
this forecast compared to our previous IRP? And then also we have to make some
adjustments to this forecast to be useful in the IRP and we have to take an account
losses and some other weather adjustments. I'm going to go through these slides to
kind of walk you through how we take AEG's forecast to, to how we would include
these loads into our resource planning model, like in and in Grant. Please add in as a
necessary. I'll need your help as much as possible if there's certain questions.
James Gall: We're going to cover two tracks on how we transition this end use model
to our actual load forecast. And the first part, is two different energy forecasts. We
have an energy forecast and we have a peak load forecast. On the energy forecast
side, we start with AEG's forecast, and we do a forecast with and without expected
DSM or energy efficiency. We then have to add losses to that load forecast because
that forecast that Ken had just gone through does not include line losses from the
transmission and distribution system. We add that to the forecast and then we also
have to add large industrial loads that AEG is not modeling. Historically, we've had
two large industrial loads and now we have a third one now that we're accounting for.
We agreed to take on a former customer, that was, we'll call it a market customer.
They're going to become an Avista load starting in July or August and it's
approximately 30 average megawatts, and a little bit higher than that for peak. We
have a higher load forecast from an energy perspective from that need for the peak
side. The forecast that AEG has done is using a load shape we can describe, but that
load shape doesn't necessarily represent the temperatures that we've seen
historically, or we expect to see in the future. What we need to do is adjust those
temperatures to account for what our temperature forecast will be to create what we
call a one-in-two forecast. We're going to demonstrate how that looks here in a little
bit. Then we take that new load forecast that we're going to calculate, we call it a
baseline and apply the AEG forecast for load growth at the time of peak. So that peak
forecast you show, before Ken, we will take the percent change of those loads and
apply that to what we call it our adjusted peak load from 2024. Then we add our losses,

Appendix A
actually we started with losses already then included in our baseline amount, and then
we add large industrial loads.
James Gall: And then just as a note, we're not including demand response or any
managed loads at that time just to make sure that's clear. We calculate a base year
based on what we think a 1-in-2 temperature is for a peak and that's for 2024. We
apply AEG Peak load forecast growth rates to those historical weather and future
weather periods and then we take these forecasts and put them into our PRiSM model
to help us choose resources. Now we do have to have two forecasts. We have one
forecast that's with DSM or energy efficiency and one that's without. And the reason
why we do that is we want to look at how much energy efficiency is cost effective in
our model. We'll actually start with a load forecast that excludes future energy
efficiency and we see what is selected by our model and we are then trying to match
up the amount of energy efficiency selected versus how much we think was in the
original forecast. It's possible that they will align, but it's also possible they won't. What
we're trying to end up with in our load forecast is the forecast you're going to see today
that is net of energy efficiency and then what we select is energy efficiency that's cost
effective and would be effectively added to the forecast without energy efficiency. That
probably doesn't make a lot of sense, but I'll try to walk through that on the next slide.
James Gall: Looking at our energy forecast, I have it broken out between our two
states and our system. This yellow line shows our actual forecast for five years and
then the historical periods before that you can see we have a little bit of weather
variation, then it starts to slow growth, and then we get a much stronger growth and
that solid black line. We're at about 1.47% annual average growth rate (AAGR) when
you include the losses in industrial customers. That's compared to our previous
forecasts of around 0.91%. But you can see we are on a higher level than our previous
forecast at the last IRP. We don't have loads broken out by state historically, but going
into the future you can see that Washington is substantially higher than our previous
forecast, mostly due to the amount of EVs and electrification that we're assuming.
Idaho is a little bit closer in the amount forecast compared to last IRP. The big
difference between the Idaho and the Washington side is the amount of EVs added
and electrification is substantially higher than the previous IRP. The Idaho
assumptions on electrification is higher, but the EV assumption is the same. Back on
energy efficiency, these forecasts that you have in the solid lines, they do include
energy efficiency estimates, that's around 60 average megawatts in Washington and
around 7 average megawatts and Idaho. Again, this is the forecast our model will try
to align to after we readjust it when we enter in our loads into our PRISM model.
Effectively it would add the 60 average megawatts in Washington and 7 average
megawatts of Idaho to these forecasts and then try to figure out if those are the right

Appendix A
energy efficiency measures. Are they cost effective? If they are perfectly aligned, we'll
end up back at these forecasts. If they're not aligned, we'll adjust our forecast without
energy efficiency so that they align. At the end of the day, these lines that you see will
be what we're trying to add resources to, OK. Are there any questions or no questions?
Alright, I confused you all enough that you were afraid to ask questions. That's good
right now. Just joking. OK.
James Gall: We'll move on to how we deal with this base here. And Mike, please jump
in if you I'm saying anything incorrect. All right, we have to start with a base year to
adjust for weather and we want to do a forecast that is a 1-in-2 peak. What we mean
by that is we look at our historical years of data and our forecasted years of
temperatures and we're looking for what is the average coldest day, what is the
average hottest day. And we're trying to find that temperature and then what would
our peak be at that temperature? These distributions you see here are the historical,
back on the winter side is on the right, summer is on the left, and these temperatures
actually go back to 1890 and then they have forecasts of temperatures through 2045.
You can see in the red it's kind of that 1-in-2 area that is our, call it our 1-in-2 peak
value we're trying to start with and then as a comparison we're showing the last two
peak events in each season. So, 2023, we had a much warmer summer peak event
than the average. You can see that in yellow and then this last January you can see
where that lines up when we had a higher or much colder day than we did on average.
So again, we're trying to take this data and apply historical temperatures, future
temperatures and come up with what we see as a 1-in-2 event or 1-in-2 temperature
for summer when we do our forecast. We're using what periods of time, Mike, to the
summer. Yeah. The summer period is June to September. Yeah. I mean, what years
we're going back 20 years, rolling 20-years data and then winter is 76 rolling years.
So, what that means is when we have a rolling temperature going forward, as we
include a change in the temperature forecast, we're changing that baseline
temperature over time and what that does is it creates a trend in the summer of higher
loads and then the winter would trend to lower loads given the same economic
conditions, the same number of customers. How does that look when you transition
this to the full data set? We have and solid black or blue, I can't quite tell, that is the
winter peak and then in red is the summer peak. When we adjust for the temperatures,
winter is still slightly higher than summer. They do crossover briefly there in 2036 and
then the winter stays higher continually. You can see these peaks are much higher
than our previous forecast from the last IRP. Two reasons for that. One is the new
industrial load that's included and then the second reason is these events we saw in
2023 and 2024 were much higher than what we had seen in the past. This higher
winter and summer loads are now embedded into this forecast to make it more
accurate. This 1-in-2 event that is causing our peak forecast to be higher and what to

Appendix A
allude to what we'll probably see in a future TAC is our resource need is going to come
sooner because of these higher loads.
James Gall: In our last IRP, we had a resource deficit year of around 2035. We expect
that to be much earlier, but we haven't completed that work yet to see when our
resource deficit will be. But at the end of the day, our peak loads are going to be higher.
This says, look at history really quick, you can see in the winter we've had actually
pretty mild winter peak loads and we were getting a lot of questions. Are you really
summer peaking? Because your summers are consistently higher than winter over the
last few years and the reason for that was we just never got a real winter cold event.
But the last two winners have changed that, and it's definitely demonstrated that winter
is still a concern. It's just a matter of temperature, but the summer temperatures have
been over the last say, 5 to 7 years been more consistently on the hotter side then
winters have been consistently on the colder side, at least on a peak event. Fred, you
had your hand up. Do you have a question?
Fred Heutte: Well, yeah, actually, I was going to wait and see your next slides
because the slide deck that John sent around said that would, what does it say here?
It says winter and summer charts, so peak load by temperature will be added in the
final slide deck actually. I'm actually hoping you'll show that because I think it's pretty
important stuff to look at.
James Gall: Yeah, that's the slide right here that we added.
Fred Heutte: Ah, OK.
James Gall: Yao has a question too. I'll read it off. So, Yao is asking, do we know how
much of the difference between the 2023 IRP load and 2025 IRP load is due to
methodological change, Grant's versus AEG? Yeah. The base year values that we
start with is the same methodology. In both Grant's method and this method, we use
the historical data, and we used a future data set to come up with a 1-in-2 peak value.
The difference between the two methods has to do with how we grow the loads over
time. In the past we grew loads based on GDP forecasting. Grant, please jump in if
there's more than GDP. There's also an EV forecast. There's a solar component and
electrification component that we're done independently, but is there anything besides
GDP Grant that we included?
Grant Forsyth: Other than the things you listed, GDP was the economic driver over
time in addition to EV accumulation and electrification were going to be the other two

Appendix A
big ones and solar accumulation. So, it was kind of unaffected, but the economic driver
is GDP growth.
James Gall: OK. The AEG forecast uses an end use decision-based forecast, but
they all do both resolve the number of customers that are expected to come online.
Back to you Fred.
Fred Heutte: Yeah. Now I actually have a question. What we saw in the January
freeze period, mid-January, was Avista and I think many other utilities experienced
what I would call a demand surge which was above projected levels. I'm not pointing
fingers here at all. I think this is a really important thing to understand. I'll note that,
among other things I've seen, the CAISO said that they had to adjust their demand
forecast in the market because the conditions in the Northwest were basically outside
of the historical data that they had been using. Likewise, SPP on the Monday which
was the 151", I guess they saw a demand surge that was not anticipated in their models
for their region. Which is through the upper Midwest down toward Texas. I think we've
seen this in the last couple of big extreme weather events, cold and heat. And I'm just,
not to answer right now, but just to think, I'm sort of putting on my thinking cap on this
is. Is there something going on that is new that we, when you get these extreme
conditions, the people are using the equipment, heating or cooling equipment a lot
more? Is there something kind of a nonlinearity happening at the end of the distribution
that we ought to be paying more attention to in terms of peak? Because then the
implication is, is there a way to do some load management? Figure out what to do in
markets. How the WRAP is going to affect this? Those are all pretty important issues
now, so really any thoughts you have. I guess my question is, have you looked in more
detail at these kinds of events to see if there's something structurally new going on?
James Gall: I think Grant has a theory and I'll let him respond to that.
Grant Forsyth: Yeah. Fred, this is Grant. One of the things we're seeing in our service
territory is this odd outcome from hybrid work. What's happening is that you have a lot
of businesses now in our service territory with hybrid workers. You have some people
working at home, some people working in the offices, but what that means in effect is
you have more people working from home on average than pre-pandemic. So, they're
going to use more energy during the day than they would have in the past, but you're
also still partially using those commercial buildings. They still have to be heated and
cooled and so when I look at our peak load data and I put in a control variable for really
the 2021-2022 period going forward, what we're seeing is a step up that's occurred in
peak load of about 40 megawatts. My theory is that this hybrid work environment has

Appendix A
stepped up heating and cooling because now we're using homes more frequently. But
those businesses still have to be heated and cooled.
Fred Heutte: Yeah. That actually is a good point. I hadn't thought of that, and at the
same time I also have to observe, though, that the January event was both during a
holiday weekend when those businesses would be either closed or curtailed and then
it can take you to the following week, at least here in Oregon, especially with our ice
storm, another whole series of issues. I think that makes a lot of sense that there's one
element to look at and then, we lived through here in Portland, probably not something
that you all have never experienced. But we had 15-degree weather with 50 mile an
hour wind here. Now that is not a very West side kind of weather pattern and I think
everybody cranked up all the heating stuff that they had that may be less of an issue
for where you are because I think people are more used to these cold waves. Anyway,
thanks. That's a very good point about load, the spread on load because of working at
home.
James Gall: I'm going to add a couple things to that and maybe explain the variance.
That variance that you might be talking about was the cold weather event we had in
December of 2023. And it was nearly the same temperature as we saw in Spokane
between the two events, but the load in 2024 was much higher. But there were a
couple things that were different going on. One was a Saturday and 2024, it was our
peak day. So, you were seeing what Grant was talking about, heating and buildings
that are not being occupied likely and at certain businesses and also homes. But in
2023, that peak event happened when schools were out. Typically, when schools are
out, there's less load overall on the system, at least in theory. It's possible that if you
would adjust for schools, whether it's universities or primary, you could come up with
the difference in that load from that point of view. We haven't quantified that. But that
was also a big difference between the two events.
Fred Heutte: Yeah. Appreciate it. Thanks. This is a really useful stuff.
James Gall: Yep. OK. That's all we have on peak and energy forecasts. We will be
sharing this data shortly. It'll be out on the Teams site. We'll post our monthly forecast
for both peak and energy, hopefully by the end of the week or next week. Any other
questions or on chat? No questions yet, OK? It might give them a minute.
Review Planned Scenario Analysis, James Gall
James Gall: OK. While we're waiting for that, I'm going to bring up our load or scenario
Word document and we'll go through that. We are running at time, aren't we? We had
until, yeah, we're doing good. Yeah. OK, so I'm going to zoom in. Hopefully you can

Appendix A
read this. We did not get through this in the last TAC meeting as much as we would
have liked, but we do want to cover what the scenarios are.
James Gall: This is really not meant to be something I read through, but we've been
sharing this list over the last I think, month or so. We did get a few comments on
additional scenarios to be looking at, but I want to walk you through how this is oriented
in case there was some confusion. So how this works is we have a list of scenarios
that we plan on running and what I call these are scenarios or portfolio scenarios,
which means that we will be either adjusting the resources selected in our portfolio or
it will change assumptions such as load that we'll be planning to. So right now, we
have 23 portfolio scenarios and then in the market price sensitivity category, this is
where we would adjust the market prices that we use to evaluate the resource options.
For example, we do 300 simulations of future market prices that is used for all of these
scenarios and then scenarios that will be testing a higher or lower gas price which then
correlates to a higher or lower electric price forecast will also be using, we call it interior
deterministic forecast for electric prices. For the Preferred Resource Strategy, we'll
take that portfolio and test it. How well it performs and our stochastic price forecast,
already deterministic price forecasts, which will be similar and then we'll test it against
low and high prices. And the other scenarios you see here that also are being tested
with low and high prices, you can see how well those scenarios, those portfolios,
compare against the PRS with different low and high price sensitivity. This column
really represents the sensitivity of that portfolio to external forces in the market.
James Gall: The LP 2030 and 2045 columns. These represent the cases where we'll
run a resource adequacy, we'll call it a test, against the portfolio. Our model that we
use to select resources, it's a monthly time step model. There's no model out there
that can optimize our portfolio on an hourly basis over thousands of potential futures.
So, we have to set a time step and a planning margin to calculate what we think would
solve our portfolio in extreme cases. And then we have to test that in a model that
does move around loads at a more extreme basis, or temperatures, or hydro
conditions. These are the portfolios we'll be testing these cases against and what
years will be testing them against these resource adequacy studies. They take about
three days to run one portfolio, so we can't necessarily run all of them, but we'll try to
run as many as we can. We may not be able to get through all of this list, but our
intention is to get through this list of portfolios with the resource adequacy test. We are
going to be running a resource adequacy test for this where we call it the 2030 baseline
and what we'll be doing is looking at the load forecast. We just shared our existing
portfolio and use that resource adequacy test to come up with our planning margin
that we'll be using in this IRP and that planning margin will be different than what was

Appendix A
being discussed in the WRAP right now. But that is the intention and we'll be sharing
that at the TAC meeting, I think in about a month.
James Gall: Moving down, we have a list of the scenarios and the assumptions in the
scenarios and what makes them different. Lastly, down below for CETA, there are
some scenarios regarding CETA compliance targets. I call these out in the chart
because in our CEIP conditions, we were asked to test different CETA target goals. I
wanted to share these to see if these make sense for the scenarios, we test CETA
against because there was a condition that we had to look at a minimal viable target
and the columns in blue is what we're calling the minimal viable target that may comply
with law and then the ones in orange are the ones we've planned to and our expected
case. And then since we have a minimal viable target for also going to be showing in
green a maximum viable target and we can then look at what is the cost of compliance
of these three different measures, because that was requested of us in our CEIP
process.
James Gall: Yeah. Yao has a question? Yao, go ahead? She asked if do LOLP
studies, generate LOLP values for 2030 and 2045? So, what they will do is tell us how
well the portfolio performed. If we use the historical 5% loss of load probability metric,
that metric will tell us, did our portfolio exceed or comply with that 5%? I'm not saying
we're going to be using 5% at this time, but it will test whether or not that portfolio will
do that. The second thing it can help us identify, at least in the 2030 study that we start
off with, is it will help us identify our planning margin. We can identify how many
additional resources we need to acquire or what our resource compared to load metric
is to hit that 5% loss of load probability. It's really has two pieces. One is to help us
identify planning margin and two, whether or not our portfolio is reliable or not.
Hopefully that answered the question.
James Gall: OK, the last time we sent out this list, we had 19 scenarios. We did add
#20 which was a data center scenario where we would test adding a data center to
our service territory. We also added a nuclear cost sensitivity scenario, and this is to
represent at what cost would nuclear be cost effective if it's not already selected in our
PRS? And the reason why we added this one is we were asked by a lot in public, all
of the CEIP public meeting process, we got a lot of questions on nuclear. Why we're
not looking at nuclear and the answer is we are looking at it, but it has really come
down to cost. So, we thought it'd be good to identify the cost nuclear would be cost
effective because at this point in time there's really only one large project that's been
completed in the last 10 years. And there's been a lot of small modular reactors talked
about, but none of them actually have been built yet to see what they costs are or if
you had multiple sets of units what the cost looked like.

Appendix A
James Gall: Another one that we will be adding is an RCP 8.5 weather scenario and
what this represents, as we talked about in the last TAC meeting, we're going to be
using the RCP 4.5 weather future for winter and RCP 8.5 for summer and that is a
warmer, RCP 8.5 refers to a warmer forecast versus the 8.5. I'm sorry, the 4.5, which
is a slightly warmer forecast compared to history. We'll be testing our portfolio against
the 8.5 weather scenario.
James Gall: Another one that we've added as requested by Commission staff in
Washington is to do some combinations of forecasts and we're going to call this 80%
building electrification by 2045. What that means is that when Ken shared how many
existing customers would be transitioning to electrification, this would increase that
electrification transition from I think he had 20% by 2045 to 80% and then we'd be
adding to that a high transportation electrification forecast, so higher EV option and
then also add warmer temperatures. Add those three together for that forecast. We
have a total of 23 forecasts. Fred, go ahead.
Fred Heutte: I just have to reach for the right buttons here. So just to say very briefly
on the nuclear, recent analysis for the IRPs for Avista, excuse me, Avista, Puget and
PacifiCorp, both are in Washington State, of course have shown very, very high cost
for nuclear. The analyst this has been done by, you know, very respected engineering
firms, Burns & McDonnell and Black & Veatch, showing capital costs in the $8 to
$10,000 per kilowatt range, but also, and this is pretty important, O&M costs that are
really high, somewhere between $100 and $200 a kilowatt year. I tend to think it's
going to be toward the higher end of that, but even if it's the lower end, if you add it up
over the lifetime of the plant, that adds a lot of cost. So just to point that out. A question
I actually have is about the next item, the climate load growth issue, which one is it
there they have 2022 1 guess. So if you could say a little bit more about data sources
for that and how you're going to profile what the weather will be from these climate
models, which is a lot of work to be able to use that because the models have really,
the global models have really big areas that they're covering. Downscaling is a
complicated thing to do. So, if you could talk a little bit more about what data you're
planning to use, that would be helpful.
James Gall: Yeah. Those forecasts come from, I don't know if you were, I think you
were at the last TAC meeting we had two weeks ago. We covered that. But Mike, you
want to just give him the source again?
Fred Heutte: Yeah, just to refresh on that, because I don't recall all the details.
mean to do it not in detail, just a general sense of it.

Appendix A
Mike Hermanson: The baseline is from the study done by the RMJOC 2, which is
Army Corps of Engineers, Bureau of Reclamation, and BPA. They use 10 global
climate models to go down and model, and train to end up with stream flows. We're
using the temperatures from the 10 global climate models. You get a max and a
minimum every day, and so we are using the median value of the 10 climate models
and doing the seasonal high and the seasonal low for the peak calculation.
Fred Heutte: Yeah. OK, that's great. I'm just to observe and I presume you're in
contact with the people at the Power Council, who now have quite a bit of experience
dealing with the downscale data. I'm pleased to see this, that I guess is my response.
James Gall: Yeah, we're using the same data set. The difference, I guess between
the Power Council and Avista is the Power Council is using three of those ten models
and we're using all of them and doing a median approach.
Fred Heutte: Yeah, I guess the issue for me is really about the downscaling. We don't
need to cover it right now, but something I'm interested in knowing a little bit more
about.
James Gall: Yeah. We've seen in the gas IRP process for some other locations in
Oregon, the downscaling of that data was a little bit counterintuitive, and we have a
new approach for that on the gas side. And I think when we plan on talking about that,
is at least three weeks out, that is TAC 5. Probably, I think it's early June, so about a
month and 1/2. We've seen the downscaling of the Spokane area has not been,
would say, counterintuitive to maybe some other areas. So, we're fairly certain it's
reasonable and actually, yeah.
Fred Heutte: So, like Ashland, yeah.
James Gall: Roseburg. Lagrande. Yeah. An issue there was that those locations were
on the edge of the RMJOC study area. We were provided another data source that
covered the whole United States, and could down get down scaled values for
wherever. I think that added to a little bit of data source for those locations.
Fred Heutte: Alright, thanks a lot.
James Gall: Yes, I just want to check with anybody. Do we want to have me go
through a description of some of these other scenarios that we didn't cover? Are there
questions on certain ones? I want to be the greatest use of our time. We have 20

Appendix A
minutes left, because what I'm really seeking is do we need to add any additional
scenarios that you have in mind? Are there scenarios on here you think we shouldn't
be looking at? I just want to gauge the group here where you want to take this next 20
minutes because I don't think me talking about every scenario might be productive.
OK. We could end early because I think the goal here is to nail down a list of portfolio
options. We're going to be evaluating as soon as possible, so we talked about, I think
the last TAC meeting by, I can't remember. I keep changing the dates on when we
need to finalize portfolios, but John, what do you want to have not from two meetings
ago. That would be about there now. Yeah, we're getting close. Yeah, that's your hand
up. Go ahead Molly.
Molly Morgan (UTC): Hey, could you just remind me what the maximum Washington
customer benefit scenario is all about?
James Gall: I would love to do that one because that is probably the biggest
challenging portfolio that we have to model. I'm going to go down here to the listing of
it. In the Washington IRP rules, we're required to do what's called a maximum
Washington customer benefit scenario. We covered a little bit of this, maybe three
TAC meetings ago, but the idea is to look at our Customer Benefit Indicators that we're
improving in our CEIP and try to optimize or to maximize their score. If the lack of a
better term is, how do we make those Customer Benefit Indicators look the best? For
example, if you have an indicator of energy burden, what portfolio could we do that
lowers energy burden the most? We're thinking of this properly as kind of at the
extremes. There are not a lot of CEIP Customer Benefit Indicators that the IRP really
looks at is, most of them are say on the customer delivery side. But we're trying to look
at how to maximize those. So, one of them is that energy burden, selecting resources
that lower the energy burden as much as possible. Another one is looking at air
emitting resources, trying to minimize air emissions from our resources. Another one
is to locate resources in Washington State or in our service territory because we have
a CBI that is focusing on trying to add resources in the local service territory for job
growth. We also look at additional energy efficiency that helps with the energy burden
as well as rooftop solar. It's rooftop community solar. Solar energy and efficiency help
the energy burden and then EVs are kind of a debatable one, but you could argue that
we'll be looking at a higher EV potential. So, our distributed, sorry distribution energy
resource study that we are going through the DPAG process has two forecasts for
EVs and solar. One is the amount of solar and EVs expected, but we also have a case
that if there are areas in Named Communities that are lagging in potential EV or solar
adoption, what would it look like if they were higher? So, we're adopting those
forecasts in this scenario as well. At the end of the day, this scenario is pushing the
envelope on things that we could do to maximize Customer Benefit Indicators, but

Appendix A
without taking into account cost. So, this model or this portfolio won't be looking at
costs, they'll be just focused on the extremes of those Customer Benefit Indicators.
Molly Morgan (UTC): OK. And in the second sentence, this says this portfolio will
exclude should that be included or what? Why does that say exclude?
James Gall: Exclude non-Washington sited resources, I guess. Maybe it should be a
period after that, but yeah.
Molly Morgan (UTC): Period. Yeah, because the other ones, he said, are included.
So yeah, maybe just clarity there.
James Gall: Yes.
Molly Morgan (UTC): Right.
James Gall: So, we're excluding non-Washington air emitting resources as well. For
example, here's the example of that. Obviously, we're trying to minimize carbon
emitting resources in Washington from CETA, but there are non-carbon emitting
generation sources that have for example NOx emissions. So, if you're trying and we
have NOx emissions for example, as CBI, so this scenario would exclude a NOx
emitting resource from selection. That way it would show because if you have, for
example we had ammonia turbines in our last IRP, that still has NOx. Our CBI for NOx
emissions declined but it didn't go to zero. So, in this scenario that NOx emission CBI
would go to zero, but at a higher cost.
Molly Morgan (UTC): Got it. And just to follow up on, OK, thank you. This scenario
would show kind of a combination of maximizing all of these CBIs at once. OK.
James Gall: Correct. All CBIs to the greatest extent possible, ignoring cost.
Molly Morgan (UTC): Got it.
James Gall: Yeah, that's a couple of questions. One of them? What are the
Washington CCA assumptions used in these portfolios? And I'll let you answer that,
and I'll give you the other. OK. Lori, you have to make sure I can get these right. For
Washington, we get free allowances for the CCA compliance. So, for our plants, at
least through 2031, we don't include any CCA costs after 2031. The law basically does
not say how emissions will be allocated. We will get some free allowances. We may
have to auction them back. We don't know essentially what happens after 2031, so

Appendix A
any generator in the State of Washington, or imports into the State of Washington, in
our modeling will have a portion of the CCA cost if it's out of state that's attributed to
Washington, it will have a CCA cost adder. Any resource in the State of Washington
after 2031 will have a CCA price adder on its dispatch.
James Gall: We also have resources that in our model, from a price forecasting point
of view, have carbon emissions that are in state and don't get free allowances. There's
a couple of those plants. So, the price forecast essentially does not include a CCA
adder for inside of the state generators until 2031. But before 2031, there is a price
adder for importing into the state. So, what we've done in our price forecasting is we've
created two prices. We have an import into Washington price, and we have an Avista
located price that does not include that carbon emission until you actually import it into
the state. So, effectively before 2031, there's no carbon pricing impacting our plant
dispatch unless it's being imported into the State of Washington. Hopefully that
answers it.
Avista: In her second question, what is the WRAP assumption used in these portfolios
given the fact that this will not enter into binding phase until summer of 2027?
James Gall: Yeah, good question. We are not going to be using WRAP planning
margins in any of these portfolios except for the number 12. So, #12, we'll use the
WRAP planning margin beginning in 2027, but all the rest of the portfolios, unless
they're a resource adequacy portfolio, will use a planning margin that we will be
identifying through our resource adequacy modeling that we will share in about a
month. What about QCCs? QCCs we will be using WRAP QCCs. For those of you
don't know what QCC is, it's a qualifying capacity credit. For each resource in the
WRAP, that's included in the WRAP footprint, is given a percentage of its capacity that
qualifies towards meeting the monthly peak value. We'll be using those QCC values
for all our resources and will be using the same accounting methodology that WRAP
uses as well, but we will not be using the WRAP planning margin except for scenario
#12. We will be calculating our own planning margin based on the WRAP accounting.
James Gall: Are there any portfolios you don't see on this list that you feel that we
should be looking at? If something does come to mind, please let us know.
Let's create a deadline by the end of the week to get us the new portfolios that you're
considering, the reason why we need to start to cut this off is one for load forecasting.
We're working with AEG on doing any adjustments to the load forecast for these
scenarios, so we'll have to make sure we can make this a manageable request for
them to do some work on the load forecasting side. And we also have to be able to
build the assumptions into our models for selecting resources. So, if something comes

Appendix A
to mind before the end of week, let us know and then we'll let you know if that's
something we can do or if it'll have to be for the next IRP depending on how challenging
the request is correct. That's a hand up, go ahead Fred.
Fred Heutte: Yeah. The one that I'm thinking about that might be worth doing
is something about a high gas price sensitivity. I'm thinking about why this would
matter. It might change the relative mix of resources. It would perhaps have a little bit
of an incremental effect on demand. Depressed demand from pricing effects and also
might change market dispatch across the western market. I can't recall exactly what
your gas projection is, but the prospect of quite a bit higher gas prices for a variety of
reasons; eventual decline in shale gas, LNG exports, it's at least worth a look, I think.
James Gall: Yep, we will. We do have that on the list that's in our market price
sensitivity now. It's I guess a question of if it's high enough for you, but we will be
modeling a higher forecast, I think it's the 751h percentile of our forecast. We have an
expected forecast, and we have 300 different prices that create that distribution and
it's I believe this 75th percentile. I think it's about $2.00 higher on average than our
expected case.
Fred Heutte: OK, so now I guess I've been looking right at it and didn't quite figure it
out. But you know, in these scenarios, all have sensitivities that represent that. OK,
now I got it.
James Gall: Any other questions? Alright. We have a deadline by the end of the week
for any new ideas. And again, if you have any ideas on anything IRP related, feel free
to send John or myself an email or give us a call. Our next TAC meeting will be in two
weeks, and we'll cover energy efficiency, demand response potential and anything
else for the order. I'm getting a lot of head nods. We thank you for participating today.
We appreciate the questions again, like to thank AEG for the good work on the load
forecast. We've been working on that project for at least nine months now and we'll
see how this works going in the future. Thank you again. Have a great day and for
those of you that will be on the gas TAC meeting tomorrow, we'll see you tomorrow.
OK.
Dean Spratt: Thanks everyone.

A endix A
I ,1
IF
2025 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 6 Agenda
Tuesday, May 7, 2024
Virtual Meeting — 8:30 am to 10:00 am PTZ
Topic Staff
Introductions John Lyons
Conservation Potential Assessment AEG
Demand Response Potential Assessment AEG
Microsoft Teams meeting
Join on your computer, mobile app or room device
Click here to join the meeting
Meeting ID: 264 797 739 040
Passcode: MLVkp8
Download Teams I Join on the web
Or call in (audio only)
[phone]„525313571# United States, Spokane
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���r r/ISTA
2025 IRP TAC 6 Introductions
John Lyons, Ph.D.
Technical Advisory Committee Meeting No. 6
May 7, 2024

Appendix A
Today's Agenda
Introductions, John Lyons
Conservation Potential Assessment, AEG
Demand Response Potential Assessment, AEG
2

Appendix A
Remaining 2025 Electric IRP TAC Schedule
• TAC 7: May 21 , 2024: 8:30 to 10:00 (PTZ)
o Variable Energy Resource Study
o Portfolio/Market Scenarios
• TAC 8: June 4, 2024: 8:30 to 10:00 (PTZ)
o Load & Resource Balance and Methodology
o Loss of Load Probability Study
o New Resources Options Costs and Assumptions
• TAC 9: June 18, 2024: 8:30 to 10:00 (PTZ)
o IRP Generation Option Transmission Planning Studies
o Distribution System Planning within the IRP & DPAG update
• Technical Modeling Workshop: June 25, 2024: 9:00 am to 12:OOpm (PTZ)
o PRiSM Model Tour
o ARAM Model Tour
o New Resource Cost Model

Appendix A
Remaining 2025 Electric IRP TAC Schedule
• TAC 10: July 16, 2024: 8:30 to 10:00 (PTZ)
o Preferred Resource Strategy Results
o Washington Customer Benefit Indicator Impacts
o Resiliency Metrics
• TAC 11 : July 30, 2024: 8:30 to 10:00 (PTZ)
o Preferred Resource Strategy Results
o Portfolio Scenario Analysis
o LOLP Study Results
• TAC 12: August 13, 2024: 8:30 to 10:00 (PTZ)
o Preferred Resource Strategy Results (continued)
o Portfolio Scenario Analysis (continued)
o LOLP Study Results (continued)
o QF Avoided Cost
• September 2, 2024- Draft IRP Released to TAC.
• Virtual Public Meeting- Natural Gas & Electric IRP (September 2024)
o Recorded presentation
o Daytime comment and question session (12pm to 1 pm- PST)
o Evening comment and question session (6pm to 7pm- PST) ins

AEG
APPLIED ENERGY GROUP
Avista Energy
Electric CPA Draft Results
Prepared for Avista Energy TAC Meeting 5/7/2024
Confidentiality—The information contained in this presentation is proprietary and confidential. Use of this information is limited to the intended recipient and its employees and may not be disclosed to third parties.

Appendix A
CPA Objectives
Assess a broad set of technologies to identify
Long-term energy efficiency and demand
response potential in Avista's Washington and
Idaho service territories to support:
Integrated Resource Planning
Portfolio target-setting
Program development
Provide information on costs and seasonal
impacts of conservation to compare to
a
supply-side alternatives
Understand differences in energy
consumption and energy efficiency
opportunities by income level
Ensure transparency into methods,
assumptions, and results
Applied Energy Group, Inc. I appliedenergygroup.com 2

Appendix A
EE ModelingApproach
Residential Electricity Projection By End Use
7,000
■cooling
6,000 ■Space Heating
5,000 •Water Heating
q 000 Interior Lighting
GWh 3,000 ■Exterior Lighting
NE1&O__.w�O : '
Appliances
,000Electroncs
1,000
■Miscellaneo05
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045 1 Generation Potential
(1,000)
Estimation
Residential Electric Intensity by End Use and Segment
*Identify • Technical
16,000 � ■Cooling
14,000 ■5paceHea6ng Demand-Side • Achievable Tech.
12, Water Heating
lo'coo ■ ■ 1otenOrlighbng Resources Economic screen in
kWh/HH 8,000 ■FMerior Hghriog IRP
61000 III■ •Appliances
4,000 �� �11r .necrroni� • EE equipment Cumulative Electric Savings,selected years
2,000 ■ ■ -F ■Miscellare°Ia *Baseline
Ge°eraH°e
• EE measures ss%
I2o"1 Projection • Emergingtech. 30'9
Single Family Multi-Family Mobile LI-Sngle LI-Muhi- LI-Mobile
Home Family Family Home 259/o
• Utility forecasts 20°9
of
Residential Electric Use by Segment,2021 • Standards and Baseline 15%
building codes 10°�
LI-Mobile Home ■,
LI-Multi-Family 3% _ 5% --' --I
7% Market 0%
•
Characterization 2023 2024 2027 2032 2042
LI-Single ■Technical Achievable Potential ■Technical Potential
Family Baseline studies
e23%
• Utility data
Mobile Home Secondary data
7%
Multi-Family
4%
Applied Energy Group,Inc. I appliedenergygroup.com 3

Appendix A MajorModelingInputs and Sources
O
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)
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 4

Appendix A
Forecast Update - DOE HPWH Standard
New efficiency requirements take effect in 2029
Forecast shown at the time of the previous
TAC meeting (April 23rd) did not include the -
new water heater standard published on
C
April 30t" n Reduces consumption gro • •
4-J • . by
U e Red u ces Pea k growth •
Ordinarily, forecast assumptions would CO Summer and
already be frozen for this cycle, however Qe Delays - overtake
this standard has a huge impact on both by about
baseline and a major savings measure _ Moves
within the CPA baseline instead of CPA
Water Heater Size Efficiency
Requirement
20 to <55 Gallons UEF 2.3 (CCE Tier 1 )
> 55gallons UEF 2.5 (CCE Tier 2)
Applied Energy Group, Inc. I appliedenergygroup.com 5

Appendix A
Baseline Forecast - Updated
Washington + Idaho Combined
Customer growth and electrification from
natural gas systems combine for a projected 12,000
30% increase in electric loads over the
forecast period, or 1 .12% annually 10,000
Growth from electrification is —2,400 GWh 8,000
Includes: ■ Residential
Projected cooling and heating degree days GWh 6,000 ■ Commercial
according to climate trends in Avista's territory ■ Industrial
Market efficiency impacts (such as trends toward 4,000
LED lighting as baseline), which are saving over
1 ,400 GWh in the forecast period compared to
minimum codes & standards 2,000
Solar and EV projections from the DER study in
Washington (Avista projections for Idaho) -
DOE H PW H standard starting i 2029 otiti oti�' oti�' oti� o�ti o o'5� T
n ti ti ti ti ti T tio ti ti ti T
Applied Energy Group, Inc. I appliedenergygroup.com 6

Appendix A
Levels of Savings Estimates
NW Power Council Methodology
This study develops two sets of estimates:
Technical potential (TP): upper bound on potential, assuming all of
the most energy efficiency opportunities are adopted without
consideration of cost or customer willingness to participate.
This may include emerging or very expensive ultra-high efficiency
technologies
Technical Achievable Potential (TAP) is a subset of TP that accounts
for customer preference and likelihood to adopt through both utility- Technical
and non-utility driven mechanisms, but does not consider costAchievable
-
effectiveness
In addition to these estimates, the study produces cost data for the Total
Resource Cost (TRC) and Utility Cost Test (UCT) perspectives that can be
used by Avista's IRP process to select energy efficiency measures in
competition with other resources (see next slide)
Applied Energy Group, Inc. I appliedenergygroup.com 7

Appendix A
Potential Estimates
Achievability
All potential "ramps up" over time — all ramp rates are based on Measures examples
those found within the NWPCC's 2021 Power Plan over 85% Achievability:
Max Achievability • All Lighting
NWPCC 2021 Plan allows some measures max achievability to Washers/Dryers
reach up to 100% of technical potential Dishwashers
Previous Power Plans assumed a maximum achievability of 85%
Refrigerators/Freez
AEG has aligned assumptions with the 2021 Plan and measures
such as lighting reach ers
greater than 85% Circulation Pumps
Note that Council ramp rates are agnostic to delivery to Thermostats
acquisition mechanism and include potential that may be C&I Fans
realized through utility DSM programs, regional initiatives and
market transformation, or enhanced codes and standards
Applied Energy Group,Inc. I appliedenergygroup.com 8

Appendix A
Residential Electric
Draft Results

Appendix A
Residential EE Potential
6,000
5,000
Draft results indicate energy savings of 4,000
1 .0% of baseline consumption per year Consumption 3,000
are Technically Achievable. (GWh) 2,000
76 GWh (8.6 aMW) in next biennial period 1,000
(2026-2027) 0
2021 2024 2027 2030 2033 2036 2039 2042
604 GWh (69.0 a MW) by 2035 LoadMAP Reference Baseline Technical Achievable Potential
890 GWh (101 .6 a M W) by 2045 Technical Potential
160
Top measures in 2045 include. 140
120
Heat Pump Water Heaters 100
Incremental
ENERGY STAR 7.0 Windows Savings 80
Level 2 Electric Vehicle Chargers (GWh) 6040
20
0
2026 2029 2032 2035 2038 2041 2044
Technical Achievable Potential Technical Potential
Applied Energy Group,Inc. I appliedenergygroup.com 10

Appendix A
Residential EE Potential
WA and ID
1,600
Selected Years
Reference Baseline 4,215 4,224 4,234 4,590 5,432 1,400 -
Washington 2,798 Z804 2,810 3,063 3,670 1,200 -
Idaho 1,417 1,421 1,424 1,527 1,763
Cumulative Savings (GWh) 1,000 —
Technical Achievable Potential 35 76 125 604 890
Washington 23 50 83 413 617 Cumulative 800 — -
GWh
Idaho 12 26 42 191 274
Technical Potential 96 198 307 1,035 1,462 600 — -
Energy Savings (% of Baseline) 400 — —
Technical Achievable Potential 0.8% 1.8% 3.0% 13.2% 16.4%
Washington 0.8% 1.8% 3.0916 13.5916 16.8% 200 — — -
Idaho 0.8916 1.8916 3.0% 12.5916 15.5%
Technical Potential 2.3% 4.7% 7.3% 22.6% 26.9% 0
Incremental Savings (GWh) 2026 2027 2028 2035 2045
Technical Achievable Potential 35 42 51 83 25
Washington 23 28 34 58 17 Technical Achievable Potential Technical Potential
Idaho 12 14 17 25 8
Technical Potential 96 103 113 124 34
Applied Energy Group, Inc. I appliedenergygroup.com 11

Appendix A
Residential EE Technical Achievable Potential
Top Measures Summary (ID & WA Combined) Rank Measure I Technology 2045 %of Total .
1 Windows-High Efficiency(ENERGY STAR 7.0) 88,239 9.9% $0.43
2045 Technical Achievable Savings by End Use 2 Water Heater(<=55 Gal)-NEEATier 5 Heat Pump(CCE 62,528 7.0% $0.07
3.5)
Cooling 3 Electric Vehicles-Level 2 51,493 5.8% $0.16
Miscellaneous 8% 4 Windows-High Efficiency(Triple Pane)-U-0.17 35,246 4.0% $0.56
0
5 Ducting-Repair and Sealing 33,947 3.8% $0.14
6 Insulation-Wall Sheathing-R-19 29,879 3.4% $0.22
7 Advanced New Construction Designs 28,923 3.2% $0.15
Electronics 8 Engine Block Heater Controls 27,356 3.1% $0.08
0
9 Home Energy Reports 25,919 2.9% $0.05
10 Insulation -Ducting-R-8 Ducts(Retrofit up to code) 25,355 2.8% $0.19
Appliances Space Heating 11 Building Shell-Air Sealing(Infiltration Control) 25,229 2.8% $0.59
9% 43% 12 TVs-ENERGY STAR(9.0) 24,637 2.8% $0.00
Exterior Lighting Ir"41
HeatinWaterter 13Clothes Dryer-UCEF 2.62/CEF 3.93-ENERGY STAR23,742 2.7% $0.24
0% 1.1/2028 Standard
g
13% 14 Air-Source Heat Pump-SEER 16.0/HSPF 9.2 1 SEER2 21,888 2.5% $0.48
Interior Lighting 15.2/HSPF2 7.8(ENERGY STAR 6.1)
3%
15 HVAC-Maintenance and Tune-Up 21,227 2.4% $0.50
16 Clothes Washer-CEE Tier 2 21,070 2.4% $0.03
17 Ducting-Repair and Sealing-Aerosol 19,136 2.1% $0.75
18 Home Energy Management System(HEMS) 16,881 1.9% $0.30
19 Linear Lighting-LED 2035(152 Lm/W system) 16,063 1.8% -$0.15
20 Insulation -Floor Upgrade-R-30 14,834 1.7% $0.49
Total of Top 20 Measures 613,591 68.9%
Total Cumulative Savings 890,281 100.0%
Applied Energy Group, Inc. I appliedenergygroup.com 12

Appendix A
Residential Supply Curve
A large portion of Technical Achievable Potential is very costly
1 ,000,000
900,000
800,000
700,000
600,000
Cumulative MWh by 2045 500,000
400,000
300,000
200,000
100,000
$0 $1JO $200 $300 $400 $500 $600 $700 $800 $900 $1 ,000 $1 ,100
TRC $/MWh
Applied Energy Group,Inc. I appliedenergygroup.com 13

Appendix A
Residential EE Technical Achievable Potential
Major drivers and Changes from prior study 0
o Higher tiers of Heat Pump Water Heaters have been added since the prior study, which provides some opportunity
•o even above the new federal standard
Large growth of Electric Vehicles, particularly in Washington give more opportunity for EV Charger savings.
Efficient Windows have higher ENERGY STAR requirement. AEG also updated base assumptions using latest
Residential Energy Consumption Survey data.
Connected Thermostats have lower savings than prior study due to lowered savings and lifetime assumptions in RTF
l workbooks.
Updated the applicability of several measures to reflect new market data available (ie, RECS 2020), reduce
overlapping applications, and better reflect market balance between competing non-equipment measures
Applied Energy Group, Inc. I appliedenergygroup.com

Appendix A
Commercial Electric
Draft Results

Appendix A
Commercial EE Potential
4,500
4,000
3,500
3,000 —
Commercial Technical Achievable 2,500
potential is slightly higher than Consumption 2,000
(GWh) 1,500
Residential, roughly 1 .1 % of 1,000
baseline per year 500
0
84 GWh (9.5 a M W) in next biennial 2021 2024 2027 2030 2033 2036 2039 2042
LoadMAP Reference Baseline Technical Achievable Potential
period (2026-2027) Technical Potential
527 GWh (60.1 aMW) by 2035 90
943 GWh (107.6 aMW) by 2045 80
70
Top measures in 2045 include: 60
Incremental 50
LED fixture replacements bundled Savings 40
(GWh)
with controls 30
20 - - - - -
Level 2 EV Chargers in WA 10 - - -° -
HVAC System upgrades
2026 2029 2032 2035 2038 2041 2044
Technical Achievable Potential Technical Potential
Applied Energy Group, Inc. I appliedenergygroup.com 16

Appendix A
Commercial EE Potential
WA and ID
Selected Years
Reference Baseline 3,086 3,097 3,112 3,403 4,274
Washington 2,049 2,056 2,066 2,305 3,034 1,000 —
Idaho 1,037 1,041 1,046 1,099 1,240
Cumulative Savings (GWh) 800 —
Technical Achievable Potential 40 84 132 527 943
Washington 28 59 94 374 687 Cumulative 600 — —
Idaho 12 24 38 153 256 GWh
Technical Potential 76 151 229 708 1,118
Energy Savings (% of Baseline) 400 — -
Technical Achievable Potential 1.3% 2.7% 4.2% 15.5% 22.1%
Washington 1.4% 2.9% 4.5% 16.2% 22.6% 200
Idaho 1.1% 2.3% 3.7% 13.9% 20.6%
Technical Potential 2.5% 4.9% 7.4% 20.8% 26.2% o
Incremental Savings (GWh) 2026 2027 2028 2035 2045
Technical Achievable Potential 40 44 50 63 36
Washington 28 31 35 45 27
Technical Achievable Potential Technical Potential
Idaho 12 13 14 18 9
Technical Potential 76 76 80 69 37
Applied Energy Group, Inc. I appliedenergygroup.com 17

Appendix A
Commercial Technical Achievable EE Potential
Top Measures Summary (ID & WA Combined) , C)
Rank Measure/Technology 2045 %of Total TRC
1 Linear Lighting-LED Fixture w/Embedded Controls 176,027 18.7% $0.00
2045 Technical Achievable Savings by End Use 2 Electric Vehicle Chargers-Level 157,586 16.7% $0.31
Miscellaneous 3 Air-Source Heat Pump-IEER 20.3/COP 3.7 42,489 4.5% $0.42
Office 1% Cooling 4 Server-ENERGY STAR(4.0) 32,087 3.4% $0.06
Equipment 3% Space Heating 5 High-Bay Lighting-LED Fixtures w/Embedded Controls 32,048 3.4% $0.00
17% 0° 6 HVAC-Energy Recovery Ventilator 31,766 3.4% $0.65
7 Ventilation-Variable Speed Control 31,620 3.4% $4.32
Food Preparation Ventilation 8 Office Equipment-Advanced Power Strips 31,544 3.3% $0.97
1% 9% 9 Water Heater-Pipe Insulation 31,097 3.3% $0.08
Refrigeration 10 Strategic Energy Management 30,256 3.2% $0.18
7% - 11 HVAC-Dedicated Outdoor Air System(DOAS) 29,384 3.1% $7.26
Water Heating
7% 12 Desktop Computer-ENERGY STAR(8.0) 27,107 2.9% $0.09
Exterior Lighting 13 Refrigeration-Economizer Addition 26,547 2.8% $0.10
7% 14 Water Heater-Solar System 19,713 2.1% $0.23
15 Ductless Mini Split Heat Pump 17,208 1.8% $0.41
16 Retrocommissioning 11,752 1.2% $0.19
17 Refrigeration-High Efficiency Compressor 8,700 0.9% $4.03
Interior Lighting 18 Lodging-Guest Room Controls 8,615 0.9% $0.17
° 19 Grocery Display Case-LED Lighting 7,416 0.8/ $3.98
20 Area Lighting-LED Fixtures w/Embedded Controls 7,297 0.8% $0.00
Total of Top 20 Measures 760,259 80.6%
Total Cumulative Savings 942,676 100.0%
Applied Energy Group, Inc. I appliedenergygroup.com 18

Appendix A
Commercial SupplyCurve
A large portion of Technical Achievable Potential is very costly
1 ,000,000
900,000
800,000
700,000
600,000
Cumulative MWh by 2045 500,000
400,000
300,000
200,000
100,000
$0 $100 $200 $300 $400 $500 $600 $700 $800 $900 $1 ,000
TRC $/MWh
Applied Energy Group,Inc. I appliedenergygroup.com 19

Appendix A
Commercial Technical Achievable EE Potential
Major drivers and Changes from prior study 43
' Updated lighting baseline to latest RTF market assumptions, actually
— increased available LED market
Commercial EV fleets are a new modeling aspect, assumptions from DER
study have a large population and RTF workbooks give valuable savings
Updated applicability of shell and controls measures to latest market data
and to avoid overlapping applications
Applied Energy Group, Inc. I appliedenergygroup.com

ti
� riasaa�� i
s�=�sa�sss
i

Appendix A
DR StudyApproach
Data Collection
• Characterize Develop list of Characterize Estimate
• the Market DR Options the Options Potential
• • L -.A
Align with EE Segmentation by Program Categories Develop Program Technical
Potential Study Customer Class • Conventional DLC Assumptions Achievable
• Market Profiles • Residential • Smart/Interactive • Impacts Potential
Secondary Sources • General Service DLC • Participation • Potential for all
Curtailment programs
• Industry or • Large General Technology
regional reports Service • Energy Storage • Costs regardless of cost
• Previous studies • Extra-Large General • Time-Varying and without
g Y� g Incentives consideration of
Service Rates/Behavioral dual participation
• Ancillary Services Achievable
Potential
• Integrated program
options without
participant overlap
Applied Energy Group, Inc. I appliedenergygroup.com 22

Appendix A
All Program
Conventional DLC Central AC
Water Heating
Grid-Interactive Water Heating
Smart/interactive DLC Smart Thermostats (Cooling/Heating)
Smart Appliances
Third Party Curtailment Emergency Curtailment
Battery Storage
Energy Storage Thermal Storage
Behavioral
Time-of-Use
Time-Varying Rates/Behavioral Electric Vehicle Time-of-Use
Electric Vehicle V1 G Telematics
Variable Peak Pricing
Peak Time Rebate
Applied Energy Group, Inc. I appliedenergygroup.com 23

Appendix A
Current and Future DR Programs
Current Inarograms include:
• Electric Vehicle TOU
• Electric Vehicle V1 G Telematics
• Third Party Contracts (one large industrial customer for 30 MW)
DR Pilot P rograms beginning in June 2024:
• Time-of-Use Opt-in
Applied Energy Group, Inc. appliedenergygroup.com 24
• Peak Time Rebate
Pilot Programs will run for two years starting in 2024
- � • For DR potential, AEG ramps up pilot programs to steady state participation once
� � � pilot period has commenced

Appendix A
Advanced Metering Infrastructure (AMI ) Assumptions
Some of the options require AMI
• DLC Options- No AMI Metering Required
• Dynamic Rates- require AMI for billing
Washington
• Assume 100% throughout study for all sectors
Idaho starting AMI rollout March 2027
• 36-month deployment schedule
Applied Energy Group, Inc. appliedenergygroup.com 25

Appendix A
Assumptions and Updates
rE
Program Impact and Cost
Smart Thermostat - Heating assumptions based on
Grid-Interactive Water NWPCC 2021 Power Plan
Program will piggyback off Heaters Dynamic Rates assumptions and DR program
Cooling Program
results from surrounding
utilities
Shared Admin, Development, and Split results across water heater PTR- Residential and General Diverged from these where
O&M Costs type- ER and HP Service appropriate
• Per-customer impacts reflect AEG- VPP- Large and Extra-Large General • Customization for Avista's service
estimated grid-interactive water Services territory
heater peak kW EV TOU - General Service and Large • Where NWPCC program
General Service information wasn't available
TOU - Residential and General
Service
Applied Energy Group, Inc. jappliedenergygroup.com 26

1*fir
DR ProgrAppendix A
Calculating DR Potential
am Impact
Per- Eligible Participation Equipment
Applied Energy Group, Inc. appliedenergygroup.com 27
Customer participants Rate Saturation
Peak Impact

Draft DR Results

Appendix A
Summer DR Potential - Technical Achievable C)
14 2045 Summer Potential
Summer TAP 2026 • 50
1 1 I 14
122 45
•• 40
Baseline Forecast(Summer MW) 1,802 1,792 1,769 1,958 2,215 1,986
Battery Energy Storage 0.0 0.0 0.0 0.1 0.1 5.5 35
Behavioral 1.1 1.8 2.2 3.4 3.8 4.4 30
CTA-2045 HPWH 0.0 0.0 0.1 3.5 8.5 1.0 3: 25
CTA-2045 ERWH 0.1 0.2 0.5 4.9 2.4 5.3 20
DLC Central AC 1.2 3.7 8.7 14.3 17.4 15.4 15
V1 G Telematics 0.9 2.8 4.7 16.4 44.5 29.3 10
DLC Smart Appliances 0.3 0.9 2.2 3.5 4.0 3.7 5
DLC Smart Thermostats-Cooling 2.3 7.0 16.6 27.4 33.4 30.7 _ _ ` _ `_
0 oil
DLC Smart Thermostats-Heating - - - - - - 6 � _ _ _ _ ;; 6 v
DLC Water Heating0.3 0.8 1.9 3.0 3.5 2.4 0 > C.
° ° a Q v f0 0 FU m ° m o 2 a � ° •�i f0
" L c a o v = W o .� o a, ° = W o o E
Ln U = N y
Electric Vehicle TOU Opt-in 0.1 0.2 0.4 2.7 8.9 4.7 o m Uw a o o E n?n U a rq ;; ; o o E ` o
Thermal Energy Storage 0.0 0.1 0.3 0.7 0.7 0.8 W o M 0 3 a a W o 0 3 W M a a � 1, °;
Third Party Contracts 7.9 12.5 17.0 24.1 26.6 29.1 w o E a. 2 a2 u E o f0 -2 E a w 2
J W H U W E t H W
t :EV s u t
Time-of-Use Opt-in 0.2 0.5 0.9 4.5 5.1 10.3 m ca ~
Time-of-Use Opt-out 7.4 6.9 6.6 2.7 3.1 39.6 E b E > W
LA U LA U
V 2 U w
Variable Peak Pricing Rates 0.6 1.8 4.1 7.6 8.4 5.4 o W o W
Peak Time Rebate 0.3 0.8 2.3 12.5 14.3 15.5
Residential C&I
Applied Energy Group, Inc. jappliedenergygroup.com 29

Appendix A
Winter DR Potential - Technical Achievable
1 2045 Winter Potential
WinterTAP 2026 2027 20281 1 from 50
2022
CPA 45
Baseline Forecast(Winter MW) 1,819 1,835 1,817 1,963 2,375 1,936 40
Battery Energy Storage 0.0 0.0 0.0 0.1 0.1 5.5 35
Behavioral 1.4 2.3 2.9 4.7 5.5 4.2 30
CTA-2045 HPWH 0.0 0.0 0.1 5.5 13.2 2.6 25
CTA-2045 ERWH 0.1 0.5 1.1 11.4 5.6 5.7
20
DLC Central AC - - - - - -
V1 G Telematics 0.9 2.8 4.7 16.4 44.5 29.3 15
DLC Smart Appliances 0.3 0.9 2.2 3.5 4.0 3.7 10
DLC Smart Thermostats-Cooling - - - - - - 5
DLC Smart Thermostats-Heating 0.8 2.5 6.0 10.9 14.6 5.8 0
w N GO d0 2 2 C w w C a 2 = w C
DLC Water Heating 0.3 0.8 1.9 3.0 3.5 2.4 g° `o � � � � � � � " u
to w c c �
Electric Vehicle TOU Opt-in 0.1 0.2 0.4 2.7 8.9 4.7 r a = _ ,=n uwi o % a = = o Ln N o o
>. w a v v N w w > a v v v w w
Thermal Energy Storage - - - - - - w m N N w ;; o o N N w a
*' 3 Q Q 9 Y N " 3 9 w
Third Party Contracts 5.8 9.3 12.6 16.8 21.0 29.6 LU H E J E a w z cn E J � E a a v w
Time-of-Use Opt-in 0.2 0.6 1.2 6.2 7.2 9.9 :rj r ~ .2 t ~ w U t
m o F- w m a � w
Time-of-Use Opt-out 9.6 9.0 8.5 3.6 4.3 38.3 CO
u COr v u
Variable Peak Pricing Rates 0.4 1.3 3.0 5.3 6.6 5.5 w W v
J LU J LU
Peak Time Rebate 0.3 1.0 2.9 16.0 18.9 14.8 0 0
Residential C&I
Applied Energy Group, Inc. jappliedenergygroup.com 30

Appendix A
Summer DR Potential
1
WA Summer DR Potential by Year ID Summer DR Potential by Year
120 120
100 Residential 3 100 — Residential
80 i General Service go — General Service
c60 ■Large General Service C 60 ■ Large General Service
■ Extra Large General Service ■ Extra Large General Service
40 40
w �
L
a 20 a 20
LL I r.MMK-L
2026 2027 2028 2035 2045 2026 2027 2028 2035 2045
Applied Energy Group, Inc. appliedenergygroup.com 31

Appendix A
Winter DR Potential
WA Winter DR Potential by Year ID Winter DR Potential by Year
120 120
100 Residential 100 Residential
80 General Service �; 80 — General Service
d ■Large General Service d ■Large General Service
0 60 c 60 —
d CL
■Extra Large General Service d ■Extra Large General Service
40 40
w d
's
Q 20 a 20
2026 2027 2028 2035 2045 2026 2027 2028 2035 2045
Applied Energy Group, Inc. appliedenergygroup.com 32

Appendix A
Developing Demand Response Resource Costs
C. DR Programs have both upfront and ongoing costs according to the table below
0 DR costs are amortized over 10 years to allow programs time to fully ramp up
0 Levelized costs are presented in $/kW-year
CostsOne-Time Fixed Costs One-Time Variable Ongoing Costs
Program Development Equipment Costs Administrative Costs
Costs ($/program) ($/participant) (shared costs)
Marketing Costs O&M Costs
($/participant) ($/participant)
Incentives
($/participant or $/kW)
Applied Energy Group, Inc. jappliedenergygroup.com 33

Appendix A
Example : Residential Grid - Interactive Electric
Resistance Water Heaters iD
Development $/program $34,000
Administrative $/program/yr $40,800
O&M $/participant/yr $0
Marketing $/new participant $60
Equipment $/new participant $170
Incentive $/program/yr $24
Applied Energy Group, Inc. jappliedenergygroup.com 34

Appendix A
Program Levelized Costs by State
kW-year -
n 2025-2035 13
2025-2035 Program Levelized $/kW-year by State
Washington Idaho $1,800
$1,600
Battery Energy Storage $2,446.83 $6,046.75 $1,400
Behavioral $128.84 $150.75 $1,200
DLC Central AC $169.62 $169.82 $1,000� ■Washington
DLC Smart Appliances $442.50 $446.16 $800 ■Idaho
DLC Smart Thermostats - Cooling $364.56 $363.45 $600
DLC Smart Thermostats - Heating $26.47 $26.57 $400
DLC Water Heating $660.70 $200
CTA-2045 HPWH $1,263.36 $0 " ��
y c� ea on on 2 = L c 43J c a
CTA-2045 ERWH $455.26 o o Q et Q aCU
o o E O O
EV V1G Telematics $442.49 LnLn z
o O c v �,
Electric Vehicle TOU Opt-in $70.05 $1,585.73 ( m " a M M o ?� " �; E
0
Thermal Energy Storage $944.90 $954.97 W E o o > z W a o M Q, M
J v o > > E _E
Third Party Contracts $108.54 $108.67 W
M p L v H H
Time-of-Use Opt-Out $524.41 $918.04
Variable Peak Pricing Rates $24.98 $26.09 E E W
N
Time-of-Use Opt-In $235.01 $431.20 0 0
Peak Time Rebate $100.15 $114.20
Applied Energy Group, Inc. I appliedenergygroup.com 35

Appendix A
Next Steps
AEG still working on Industrial modeling, planned
to wrap up by May 10 th
Working IRP Inputs for EE and DR due to Avista by
May 171h
Applied Energy Group, Inc. I appliedenergygroup.com 36

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Appendix A
Avista 2025 Electric IRP TAC 6 Meeting Notes May 7, 2024
Attendees:
Sofya Atitsogbe, UTC; Shawn Bonfield, Avista; Kim Boynton, Avista; Annette Brandon,
Avista; Terrence Browne, Avista; Kate Brouns, Renewable NW; Michael Brutocao,
Avista; Logan Calen, City of Spokane; Katie Chamberlain, Renewable NW; Kelly
Dengel, Avista; Joshua Dennis, UTC; Mike Dillon, Avista; Michele Drake, Avista; Jean
Marie Dreyer, Public Counsel; Michael Eldred, IPUC; Ryan Finesilver, Avista; Grant
Forsyth, Avista; James Gall; Avista; Bill Garry; Konstantine Geranios, UTC; Amanda
Ghering, Avista; Michael Gump, Avista; Leona Haley, Avista; Tom Handy, Whitman
County Commission; Lori Hermanson, Avista; Mike Hermanson, Avista; Andy Hudson,
Applied Energy Group; Rachelle Humphrey, Avista; Erin Heuvel, Avista; Dave
Lockhart, CHC Hydro; Kimberly Loskot, IPUC; John Lyons, Avista; Patrick Maher,
Avista; Joel Nightingale, UTC; Tomas Morrissey, NWPCC; Fuong Nguyen, Applied
Energy Group; Austin Oglesby, Avista; Tom Pardee, Avista; Meghan Pinch, Avista;
Nathan South; Dean Spratt, Avista; Victoria Stephens, IPUC; Lisa Stites, Grant County
PUD; Darrell Soyars, Avista; Briana Stockdale, Avista; Kenneth Walter, Applied
Energy Group; Bill Will, WASEIA; Tommy Williams, Applied Energy Group; Yao Yin,
IPUC; Renee Zimmerman, Avista.
Introductions, John Lyons
John Lyons: [Recording not started immediately] Conservation Potential Assessment
and the Demand Response Potential Assessment, we will be going over those today.
If you have any questions on those or if there were any follow-ups from last week,
probably could get those answered too. For upcoming meetings, next one, again it'll
be in two weeks on May 21 st we'll get into the variable energy resource study and
portfolio market scenarios, and then we go on from there. The June meetings, I still
need to schedule the June 25t" and send that meeting request out. So, you'll be seeing
that coming out soon. And then the last ones there, we will skip the Fourth of July.
That one is off. And then we'll wrap up with this side of it on August 13t" and then in
September, we'll release the draft IRP and have the public meetings. We'll have
prerecorded videos on that and then we'll have discussion times. There will be a
daytime and an evening time to give people an opportunity to discuss. James, did you
have anything else you wanted to add?
James Gall: Yeah. Just going to follow up on last meeting. You might recall,
we discussed the load forecast. We do we owe the TAC our final load forecast. We'll
try to get that out next week. We've been revising it a few times with AEG as they're
wrapping up their analysis, so we'll have our final load forecast out,
could be Friday or could be Monday next week. Look for that on that Teams site. We

Appendix A
have been updating the Teams site with other information, all of the current TAC
presentations are out there on the Teams site as well as we have been posting the
final and the draft TAC presentations out there too. And then if we're ready for AEG to
get started and Ken, are you out there? You're not hearing.
Andy Hudson: Hey, James, this is Andy. Unfortunately, Ken is stuck in traffic right
now. There's an accident on the highway where he is.
James Gall: OK.
Andy Hudson: I was thinking that maybe we could do demand response first as an
alternative because I think we have.
James Gall: Yeah. That works for me.
Andy Hudson: Tommy, on the line here.
James Gall: OK, let's do that.
Andy Hudson: Let me confirm that.
Tommy Williams: Yeah. Andy, would you like to present the slides, or would you like
me to pull it up?
James Gall: I would rather have you pull it up and that way I can follow the chat and
interrupt you if any questions come up.
Tommy Williams: Sure, that sounds good.
James Gall: Alright. In all seriousness though, if you do have a question in the chat,
go ahead and put it on there. I'll watch the chat and try to interrupt Tommy at a pause.
If you want to ask your question, or have a comment or reply, you can definitely raise
your hand as well. Go ahead, Tommy, whenever you're ready. I see your screen.
Demand Response, AEG
Tommy Williams: OK. Let me just get down to the demand response section.
All this Ken will cover when he gets in, but we're just going to go ahead and start with
the demand response section, which we pull a lot from the EE [energy efficiency]
study. When we start discussing this, it's usually better fit. Once you know they go first,

Appendix A
but in lieu of that, I will start and give you a sense of how we calculate the demand
response potential for the Avista territory. The process we go through and then which
programs we're going to be analyzing potential for, and what they look like in the Avista
territory from 2025 through 2045, a 20-year span there. OK.
Tommy Williams: An initial approach to the study. First, we have a data collection
stage where we align with the EE side and that's through either market profiles, a
survey, day-to-day to come up with saturations, baselines, things of that nature, and
just make sure we're in tandem with that study so there's no surprises and everything's
in alignment. The next stage is we characterize the market. This is when, for the EE
side, they break it out by residential, commercial and industrial. That's slightly different
than what we do for the demand response potential study. We break it out by
residential, general service, large general service and extra-large general service.
These are broken out by schedules and obviously the largest schedule fits into the
extra-large general service and so forth. There are some industrial customers in the
large general service and some in the extra-large general service sections. But I just
wanted to break that down for you.
Tommy Williams: For the list of demand response options, we have six or so different
categories. First is traditional DLC options. These involve switches for the utility to be
able to control the end use on the customer side just through an on and off switch. It's
more of the conventional method that we've seen over the past 10-20 years, but we
also have smart interactive DLC. These are thermostats, things of that nature,
curtailment structures. This is for some of the larger customers, so large and extra-
large service customers would fit into this category where they elect to provide a
certain amount of megawatts or kilowatts that typically a larger customers will fit into
this category and they will elect to provide those services when called upon. Energy
storage technologies is both thermal and battery. We'll get into that a little bit later.
Tommy Williams: There was a new battery storage forecast that came out and we're
relying on that to inform what the potential might look like and it dropped quite a bit on
the battery side. We can discuss that in a bit. Also, time varying rates and behavioral,
this is time of use, peak time rebates available, peak pricing and behavioral programs.
And then ancillary services, we won't go over these in this discussion, but some of the
programs that weren't an ancillary service through their end use technology can elect
to be on these programs. And it's really a subset of the parent program that can go on
these ancillary type programs. We model them, we just won't discuss them in this
presentation. Then we develop program assumptions. These are typically impacts
from around the country of similar programs. We also used the Northwest Power
Council assumptions to supplement anything that we can't figure out using other

Appendix A
programs from around the country. But mostly we take impacts, participation rates, the
technology that each program uses, costs and incentives of those programs. And then
there's two different types of potential that we run. It's technical and achievable
potential. This what we'll be discussing here. It's where every program is standalone
and they're not interactive, so each program is run by itself in a vacuum, whereas the
achievable potential, we haven't run this for Avista yet, but it will come this week once
we get everything settled with the TCP potential. But this is where the programs are
allowed to overlap. If two different programs, such as DLC — central AC and a smart
thermostat program. They don't pull from the same customer pool. They can't overlap.
Same customers can't be on both programs, so that's the difference.
Tommy Williams: OK, moving on. Again, I discussed most of these already, so I won't
spend too much time on them, but this is the full gamut of programs that we're looking
at. Big hitters, I would say, are smart thermostats. Would interactive water heating?
Emergency curtailment capacity building shouldn't be here anymore for this third-party
curtailment program. We're only running on the largest customers now. We removed
general service, which was a capacity bidding type program from this. It's only just
emergency curtailment and in this case the largest customers. And then the whole
bunch of time varying rates and behavioral.
Tommy Williams: OK, so current and future demand response programs. There are
three programs that are currently being run in the Avista territory. One is electric
vehicle time of use. Second is electric vehicle V1 G telematics. This is where the utility
can control the time, which vehicles are being charged, but the vehicle cannot give
back to the grid in this case. And then one large industrial customer for 30 megawatts
is on a third-party contract program at the moment. Allowing all three of these to grow
throughout the time frame. For DR pilot programs, this is starting two in June of this
year. One is a time of use opt in and the other is a peak time rebate program we
discussed with Avista and they're going to run these for two years starting this year in
June. Once that period is over, we have our traditional ramp rates, these ramp up to
fully fledged programs at the end of this cycle. But they keep them low up until that
point. It's small, intermittent potential for these time-of-use opt in and peak time rebate,
but then they ramp up to fully fledged programs. A lot of these costs are, for instance
the time used opt in, you'll notice that some of the costs associated with this are low
in Washington, because those are sunk costs that have already been incurred by
Avista. That is one assumption that we made in this, that those costs have already
been incurred. We won't see those when we look at levelized costs for each of these
programs. However, for Idaho, those costs have not been incurred yet, so there's a
there's a larger upfront cost to get that program up and running. However, we do
assume that they have any cost that went into one program that can be transferred

Appendix A
over to the next. We assume that those are already sunk as well, so it's just a couple
of development costs that are with Idaho on that one. Hopefully that made sense.
James Gall: Hey, Tommy.
Tommy Williams: Yes, please.
James Gall: This is James. I just wanted to bring up on these current programs and
the pilots. These are all in Washington State and we don't offer any of these programs
in Idaho yet.
Tommy Williams: Thank you.
James Gall: Thanks for summarizing these. I'll let you.
Tommy Williams: Yes, that's correct. The pilot programs are Washington only.
However, the potential, we do assume that Idaho will pick them up once AMI gets
rolled out. I believe that's next slide beginning in March of 2027. These programs do
require AMI, so dynamic rates we need them for billing and is required. Idaho AMI is
not expected to be rolled out until March of 2027. These programs begin in, I think the
assumption is they begin in 2028. Once this process has begun for AMI. And that'll be
on a 36-month deployment schedule. OK, a couple of assumptions and then we get
into the meat of that. For smart thermostats, heating program will pick it back off the
cooling program, they share costs for creating interactive water heaters of the potential
split out between electric resistance and heat pumps. Heat pumps have a lower
potential per customer. However, electric resistance are also expected to with a new.
Water heater forecast heat pumps are expected to take over the market by 2045. I'm
sure the team will get into that a little bit more. But that's just the expectation going
forward. So electric resistance, the potential overall for this program is lower than
expected because of the heat pump saturations by 2045.
Tommy Williams: OK, so dynamic rates, we kind of went through these a bit, but
there's four of them and these are the classes that each are expected to use these
types of programs. Peak time rebate is residential general service. Variable peak
pricing, we model this as large and extra-large service so they're not overlapping.
Electric vehicle time of use — general Service, large general service. Time of use is
residential and general service, so customers have the choice between PTR and TOU.
For residential and general service, as I mentioned before, we mostly base impacts
and cost assumptions on the Northwest Power Council with supplemental information
from programs around the country trying to get as close to Washington and Idaho as

Appendix A
possible for those program assumptions and that we diverge from them where
appropriate.
Tommy Williams: And then just to give you a sense of how we calculate potential for
demand response programs, there's really four elements. We have our per customer
peak impact. As I mentioned, for water heaters that's lower end electric resistor, higher
electric resistance, lower and heat pumps. We feed those into a model where the
impact is multiplied by the eligible participants, which is a function of the participation
rate of the total number of participants that can be on a certain program and the
saturation of the equipment in the territory. So, imagine all of these four components
multiply together to get the number of participants that are on this rate per year
multiplied by the expected impact per customer.
James Gall: We have a question in the chat.
Tommy Williams: Yes.
James Gall: Alright, so this is for time of use. Do residential and general service use
the same on-peak and off-peak hours?
Tommy Williams: Yes, I believe it would be. It depends how we how we want to set
that up and maybe that's a question for Leona on how that program might be set up.
If you have an answer.
Leona Haley: Yeah, I certainly do. Thanks, Tommy and James. This is Leona.
I'm a program manager on the Energy Solutions side of the house and our pilot
programs are using the same hours for residential and general service.
Tommy Williams: Yeah. Thanks Leona. OK, so this is the.
Leona Haley: Thanks.
Tommy Williams: As long as there are no more questions, we'll get into the results.
The initial results of the technical, achievable potential, and so some of the biggest as
you can see on the right, this is from the previous CPA cycle. All the grayed-out
numbers are reflections of what we expected in 2045 in the last cycle versus what
we're expecting in 2045 on this new cycle. And we can see a lot of the differences right
off the bat. Battery energy storage is essentially next to nothing. These are all in
megawatts, so by 2045 we're expecting just over 0.1 megawatts for better energy
storage and that's solely due to a new forecast that came out for better energy storage.

Appendix A
We assume that forecast is accurate, but they still will not pay for those batteries to be
installed for those customers. This is going to be a, you own it, you can be on the
program type of a thing. If we wanted to drive this up with incentives for paid batteries
for solar customers, that's the original assumption, that it would be a percentage of
solar customers that can be incentivized to purchase batteries. But right now, we're
just using the battery storage forecast. Some options in the future that we could toggle.
Tommy Williams: Behavioral is pretty similar. Heat pump water heater and to the left
resistance water heater. We can see that left resistance goes up to nearly five
megawatts by 2035 and then it decreases to 2.4. This is because of the residential
saturation assumptions that are made because of the new heat pump water heater
saturation forecast, and these are expected by 2045 to completely take over the
market and residential. That's why this increases so much. Unfortunately heat pumps
don't offer the same potential per unit as an electric resistance water heater, it's still
nearly nine megawatts by 2045, so it's no slouch, but if it were electric resistance, it
would be a bigger number here. Just wanted to summarize that for you.
Tommy Williams: For AC, this is pretty similar to previous years. I think it is just a
larger customer forecast in residential, so more customers equal more potential there.
V1 G telematics, this is a huge increase, and it's really due to further assumptions we
made about this program. For this program, we're assuming 90% of a customer's EV
load is available for this type of program, and by 2045 we also have a new EV forecast
from the same folks that brought us the battery storage forecast. With that, there's
more electric vehicles in the system by 2045, so that's an additional increase. There
are the ones I wanted to point out here for the summer. Potential or a doubling of EVs,
or you opt in. This was due to let me get my notes here. That's just electric vehicles
because the new EV forecast. That's why they're so high. And then let's see any other
ones that I wanted to point out. TOU opt in, this is because there's lowered impacts
and lower participation rate in general service. Then we saw in the previous
assumption and then this was a huge drop because we, whoops, we made some
changes to the assumptions for TOU opt out. The way this program works is you have
an initial starting steady state participation and then it goes down over time because
customers are expected to opt out of this and go back to the standard rate. We lowered
the potential participation rate at the beginning, from I think 74 to 20, so that it took a
big drop from the previous year, previous cycle, and I just wanted to present why that
is. I think that's all I have on that.
James Gall: They tell me we have another question.
Tommy Williams: Yes, please.

Appendix A
James Gall: That's related to storage and batteries, but it says does battery energy
storage include using residential EV batteries for demand smoothing?
Tommy Williams: No, it does not.
Tommy Williams: Yeah, this is specifically for solar batteries. We can develop this
further as things come out. I don't think we have a good idea of what the potential for
EV batteries is at the moment. So, it remains to be seen. I would love to include that
and that's something that is exciting for the future, to have a vehicle to grid option and
to pull that resource from a vehicle. I think that's the way of the future, but no, this does
not include that at the moment.
James Gall: OK. I just wanted to remind the TAC one thing on the energy storage
forecast. The DPAG, or distribution planning group, did a presentation. Actually, AEG
and CADEO did a presentation on our future forecast for electric vehicles, solar and
energy storage and that study was conducted and completed about a month ago. It
was used to estimate the amount of energy storage you see here in the electric
vehicles. That's how it's all connected together.
Tommy Williams: Correct.
James Gall: OK. No more questions so far. Good, keep going.
Tommy Williams: Good, very good. OK, winter looks fairly similar to summer.
The main difference here is that there's heating options and a thermal energy storage.
Summer, it's really just smart thermostats. Heating is the big difference, and with that
there was an increased heating saturation due to air source heat pumps coming
online. There are expected to be a lot more of those than what we saw from the
previous cycle. That's why we're seeing that big jump. Other than that, it's pretty similar
to what we saw in the summer impacts. Just want to run down here. OK. Yeah, pretty
similar to what we saw for summer. That's the main thing, is that there's heating and
in winter. Just wanted to give you a quick look at what we're seeing by sector here for
summer and winter and by state. We can't really stack this potential because these
are standalone results, and when we do the integrated case, which we will in the future,
then we'll be able to stack these up and see what it would look like if all these programs
were run at once. But we can't really show that, so, we break these out by sector and
the different programs essentially at this point. But residential is the big driver of most
of this potential. Large and extra-large annual service, these are mostly third-party
contracts that are making up this. And electric vehicles, those are the two main

Appendix A
programs that make up these two bars here. Residential, we have time varying rates,
everything goes into this and there's a lot more customers. So that's why we're seeing
so much potential. Similar story with Idaho.
Tommy Williams: And very similar to summer is winter. Not much to say there and
then I wanted to get into costs. Do your programs have both upfront and ongoing
costs? Up front, costs are to filament costs. And then there's also one time cost that
go with equipment. Customers need equipment to run these types of programs,
otherwise there won't be eligible. That makes up our eligibility list for each of these
programs, and there's also marketing costs, costs it takes to get a customer onto the
program, ongoing costs, there's administrative, operating costs and incentives to keep
a customer on a program. You keep them doing what they're supposed to be doing.
OK. An example, resistance water heaters pulled this out. This is for residential, this
would be for Washington only. Just another thing, Washington is the only state right
now that has a rollout of interactive water heaters, DLC, water heaters is what we use
that in Idaho because they don't, there's not an expectation for grid and interactive
water heaters to be rolled out in that state yet, so we're running a DLC water heating
program for that for now. This is a Washington only. We expect development costs of
about $34,000 for the residential sector administrative, this $150,000 is assumed for
a full-time employee for a whole program. The whole program includes residential
general service, any other classes that we're running these, and also the heat pump
water heaters. We break that $150,000 out depending upon the allocation of what
each full-time employee will do for each section of that program. Just this $40,000, is
a piece of that for marketing $60.00 to bring a new customer onto this program
equipment, $150 to hook up that grid Interactive system onto a typical water heater.
It's a module and a $24.00 incentive per year for a customer beyond the program. All
that being said, these costs go into the model, and we output them all to that 20-year
time frame. So, what we do to oops, levelized it back to a single year value. We take
a levelized cost per kW you per year and bring that back using a discount rate to a
single year value. Per kilowatt saved for each of these programs so we can see that
battery energy storage, there's the amount of kilowatts, potential kilowatts, saved for
that program is so low that each of the kilowatts that the cost per kilowatt blows it out
of proportion. It's way up here as you can see on the top here. Some of the lowest
costs contributors are Washington for EV TOU opt in. There's a lot more vehicles
expected to be in Washington rather than Idaho, so when we see a large number over
here and a low number over here, that essentially tells us that the amount of customers
are much more prevalent that can be on that program in a certain state rather than the
other. But that's why we break it out by state year two. Let's see, anything else to bring
up?

Appendix A
James Gall: Yeah. Question Tommy on the DLC smart thermostats, there's a cooling
that has a very high cost and a heating that has a very low cost.
Tommy Williams: Yeah, some good. Yeah.
James Gall: Are you assuming that the reason why the heating is such a low cost is
because you're activating the cooling program? Can you kind of talk about that
interaction?
Tommy Williams: Yes. I mentioned before that the heating program piggybacks off
the cooling program. The heating customers are a subset of the cooling customers
and so we assume a lot of the costs that go into the cooling are here rather than in the
heating program. That's really the difference there.
James Gall: Thank you.
Tommy Williams: Yeah. OK. I think that's all I really wanted to say. Is Ken on by
chance? Still in traffic?
Andy Hudson: I'm not sure, I guess if he's not chiming in, he's probably not on yet.
Looks like Fuong has joined us, though. I think he could get started on the
presentation.
Tommy Williams: Sure.
Andy Hudson: Do you want to keep sharing this slide deck, Tommy?
Tommy Williams: Now I will. I would love to.
Andy Hudson: Yeah. Great. Thanks.
Fuong Nguyen: Right. I just got on.
Tommy Williams: You're a little light on the you can speak up.
Fuong Nguyen: Oh, really? Better.
Tommy Williams: Still a little light.
Fuong Nguyen: OK.

Appendix A
Tommy Williams: Is either sharing the same thing.
Any Hudson: Yeah, I can't hear very well.
Fuong Nguyen: OK. I'll try to call back in.
Tommy Williams: OK.
Sofya Atitsogbe (UTC): Hi, this is Sofya at the chalkboard with Washington Utilities
Transportation Commission. Maybe on the DR slides, you could talk more about the
equipment cost.
Tommy Williams: Sure.
Sofya Atitsogbe (UTC): Yeah, it shows.
Tommy Williams: Anything in particular on that?
Sofya Atitsogbe (UTC): It showed $170 on one of your slides.
Tommy Williams: Oh, sure. Yeah.
Sofya Atitsogbe (UTC): For new participant, yes.
Tommy Williams: You want me to talk about that?
Sofya Atitsogbe (UTC): Could you please tell me what kind of costs are included in
that?
Tommy Williams: Sure. I'm just pulling up the input generator here, which goes into
the cost a little bit. More specifically, give me one sec.
Leona Haley: Tommy, this is Leona. I think I might be able to help with that too.
Tommy Williams: Yeah, go ahead.
Leona Haley: The customer has their water heater, and they want to participate, so
Avista would send the customer a communication module to plug into their water
heater. There's that cost. And then there's other cost, too, to the communication pieces

Appendix A
and then when we did get some of those costs, I believe from the Bonneville study
and then I'll.
Tommy Williams: That's right, yeah.
Sofya Atitsogbe (UTC): I haven't seen the Excel sheets, but my colleagues are telling
me that in Washington, the water heaters that are sold in Washington are all CTA-
2045 ready. So, my assumption is that they don't require any more equipment.
Leona Haley: Yeah. Sofya, a good point. They are ready, but they do require a
communication module to communicate with the utility.
Sofya Atitsogbe (UTC): Got it. So, this requirement for the equipment doesn't satisfy
the requirement to communicate with the utility.
Leona Haley: Correct.
Sofya Atitsogbe (UTC): OK. Thank you.
James Gall: Alright. Are there any other DR questions? This is a good way to fill time
if you have any questions on DR or any other topic while we're waiting unless he's
back.
Fuong Nguyen: Yeah, I'm back. Does this sound any better?
James Gall: We can hear you much better.
Tommy Williams: Much better.
Fuong Nguyen: OK, great. I don't know if Tommy had already covered this slide on
the CPA objectives. The CPA is set to, or what we want to achieve, is to assess the
technologies and identify the long-term energy efficiency and demand response, which
Tommy already addressed. The potential for Washington and Idaho to support the
IRP, planning and setting targets for the portfolio as well as developing their energy
efficiency programs. We also need to provide the information on cost and impacts of
the conservation to compare to the supply side alternatives in the model, as well as
understand the differences in the energy consumption and the energy efficiency
opportunities. By modeling the different income levels in residential and as always, we
the transparency of our modeling methodology and the assumptions that go into the
model, as well as the results coming out of it.

Appendix A
Fuong Nguyen: We talked to this slide in the previous TAC meeting of our modeling
approach. It's a four-step approach where we begin by characterizing the market and
setting the base control totals and segmenting the market. And characterizing the
energy use in the base year, we segment the market and disaggregate the usage for
each sector and segment in the business territory. Previously, we presented the
baseline projection which includes utility failure. We compared to the utility forecast
which includes no standards and building codes in that forecast. And then for the
potential, we identified the measure resources. We identify energy efficiency
equipment that can replace the baseline equipment and measures that can also save
energy as well as a new energy technologies that may come down the line. Then what
we're going to show here today is the potential estimation where we apply the ramp
rates and come up with the technical and achievable technical potential which goes
into the IRP for the economic screen.
Fuong Nguyen: Any questions so far? OK. And I think this is also a slide from the
previous presentation which describes the inputs into the model and the sources that
we use. I won't spend too much time here, but we prioritized the Avista data, sales and
customer accounts, and retail price forecast. We also use survey data to show what
the equipment is in the territory. And we also thought back on secondary sources,
such as the US EIA data from Recs and Cpex and Max, and then to characterize the
measures and the equipment and end uses. We rely on the RTF workbooks, the
Council workbooks, US DOE data, and Energy Star data sheets, things like that.
We also take into account the energy codes and standards that are present in each of
the different states for Avista, and we look at market trends from RTF such as the
lighting, RTF light workbooks, and things like that. So. a couple weeks ago, we showed
the load forecast for Avista, but in the interim, there was a new water heater standard
published on April 30t" for water heaters. Usually, we freeze any standards at a point
in time, so that we're not constantly updating the model and the forecast as we're doing
this study. But since this standard has such a huge impact on both the baseline and
the savings for the CPA, we decided to update the models with this. The new standard,
the efficiency requirement here showing the table on the right is for water heaters less
than 55 gallons will have to be a Tier 1 heat pump water heater, and for water heaters
greater than 55 gallons, it's a Tier 2 requirement. The impacts that we're showing in
the call out there, it reduces the energy consumption in 2045 by 297 GW hours and
the peak growth by 29 megawatts in the summer and 52 MW megawatts in the winter.
It's a pretty significant impact. It also delays the winter peak taking over the summer
by about 10 years. It delays that and it moves the big part of this, it moves to the water
heating savings from the baseline or into the baseline instead of the CPA. I'll pause
here, if anybody had any questions.

Appendix A
Sofya Atitsogbe (UTC): Hi, this is Sofia at the UTC again. Can you please explain
again, so this update delays the winter peak, overtaken by the summer peak by about
10 years, is that right?
Fuong Nguyen: Yes. In previous forecasts, the peak it becomes, winter earlier in the
previous forecast because the water heating mostly hits the winter peak. It moves it,
the water heating usage is lower because of the standard. So, the peak isn't hit in the
winter as much as it was before.
Sofya Atitsogbe (UTC): Got it. Thank you.
James Gall: And finally, we have a question in chat. Is the 10-year delay just for
Washington or does that also apply for Idaho?
Fuong Nguyen: I do not know off the top of my head. I think we were looking at both
combined. I have to go back and check on the separate states when that happens in
nature or state.
James Gall: Thank you. OK. Before you move on, I just wanted to remind the TAC on
peak forecasting. AEG does a peak forecast for us that is based on a specific weather
methodology, and we do a second round of their peak forecast, adjusting for our
weather forecast. The final load forecast which we will be sending out soon may have
slightly different results than what you see here, but I think it is pretty consistent where
we are going to be seeing a very similar peak in the winter and summer forecast
amount going forward. So, there's definitely been some changes since the last TAC
meeting and look for that soon. But go ahead Fuong.
Fuong Nguyen: Thanks James. Yeah, and here is the updated baseline forecast for
Washington, Idaho, combined. The customer growth, electrification of natural gas
systems combined for a 30% increase in electric loads over the period from 2021 to
2045. It's about 1.1% each year. Which is 2,400 GWh from the electrification. The
forecast provides the assumptions in the forecast includes the projected pulling, hitting
degree days and climate trends, market efficiency impacts from LEDs and other things
like that. We also include solar and EV projections from the recently completed DRDR
study for Washington, which is what you see, that tail end of the growth is mostly
electric vehicles and as we mentioned before, it's the heat pump water heater standard
in 2029.
Kenneth Walter: Alright. And I think this is my turn to step in. Sorry folks, this is Ken.

Appendix A
Walter with AEG I was a bit late to the game this morning courtesy of a couple of
accidents on the freeway on the way in. It is surprisingly difficult to speak to a
PowerPoint deck from inside a car and bumper to bumper traffic, so I apologize that I
didn't get a chance to introduce myself at the top of the call, but I'll do my best to help
out on things now. The next piece will actually cover the draft working efficiency
potential that we've been able to put together for Avista starting first with just a quick
review of the level of savings estimates that we do. This is in accordance with
Northwest Power Council's methodology, similar to what's used in the 2021 Power
Plan. For Avista, specifically on the electric side, we develop only two levels of
potential. First being technical, which is a hypothetical upper bound on all savings
potential, assuming the most efficient energy efficiency opportunities are put in
throughout all of Avista's territory with no consideration of how expensive they are or
even really worrying about customer willingness to participate. Every piece of
equipment at turnover is put in, so this is bypassing the Council's ramp rates entirely.
That is pretty pie in the sky. It includes extremely expensive and emerging
technologies. Much more useful data point is the achievable potential which does a
little bit of a sanity check to remove things that are like $1,000,000 a MW hour or
something of that level. But also most importantly, this is where we apply the Power
Council ramp rates so that what we are able to pass along to this process is something
that has a sensible schedule of potential adoption still consistent with Council
methodology, but importantly the technical achievable potential is there for every
measure and is still not doing a cost filter. We're not outright rejecting technologies,
but we may not be choosing like the V REF Seer 24 central air conditioners because
something like a Seer 16 is just a more appropriate dollars per MW hour. That's more
in the realm of something the IRP would find potentially attractive. The idea is not to
have measures drop out entirely unnecessarily. In addition to the technical achievable
potential, what we provide to Avista for their planning process are the Ievelized costs
from both the total resource cost and utility costs test perspectives. And that way the
IRP can look at on an hourly basis and throughout the forecast period what resources
are available at what cost and make a sensible selection at a very granular level using
the data that we were able to give them. Any questions on these levels before we start
looking at results? OK, cool. Yes.
Atitsogbe, Sofya (UTC): Hi. Sorry, are you going to be going into the total resource
cost methodology? I'm particularly interested in nonenergy impacts because I heard
that staff comments were noted and then this time around you were doing something
differently.
Kenneth Walter: I think that comment may be in the gas conversation, but at any rate,
yeah, in either one of these, we are careful to include all NEI that RTF quantifies first.

Appendix A
Sofya Atitsogbe (UTC): So that would be on the gas?
Kenneth Walter: That would be anything that's dollar quantifiable, whether that's
water savings, detergent savings in the case of DHCP. There's some avoided wood
smoke. All of these are documented through our study, so anything the RTF has
already quantified and then obviously in Washington, we also have the 10% adder for
conservation.
Sofya Atitsogbe (UTC): OK. Thank you.
James Gall: Sofya, it's James. We do have a second round of NEI that get put on
these levelized costs that comes after what AEG does and that is the same study that
we're relying on from the last IRP. I don't know if Kim has anything to add to that, but
because I'm kind of speaking out of turn there. But there is another round in this. If I
recall correctly, it's mostly focused on the low income. Kim, if you had anything to add
or not.
Kim Boynton: Yeah. Nope, you're getting it.
James Gall: OK. And we will provide when we send out our PRiSM document. It will
have every single program, what the savings potential is, what the levelized cost is,
what the additional NEI value is for every single program. So, you'll be able to look at
those.
Sofya Atitsogbe (UTC): Great. Sounds good. Thank you.
James Gall: You're welcome.
Kenneth Walter: All right. And this is just a note on the ramp rates that I was referring
to earlier. We do still take those from the Northwest Power Council's 2021 Power Plan.
Those ramps themselves are still consistent with what was used in the 7th Power plan,
aside from some assignments. There are only a few curves that are assigned to each
measure based on what's deemed inappropriate rollout and we are remaining with the
assignments that the Council has used the maximum achievability for these measures
ramps up over time. But all of them are designed to reach usually about 85% of
technical potential. However, some have gone up to 90% or even 100%, is a partial
list on the right for measures that are actually above that 85% threshold that the
Council has reevaluated, and we have aligned our assumptions with that. It's really
important to note that the Council's ramp rates, and really the design of the

Appendix A
conservation potential assessments, are agnostic to the delivery of programs and
explicitly are intended per the Council to include potential that might be realized not
just through utility programs, but also through regional initiatives, market
transformation, especially in the long term or some future codes and standards that
are not available on the books yet. As we mentioned, we've explicitly modeled things
that are actual law now, but the Council ramp rates may include savings in those four
years that are possibly going to be achieved through codes and standards as well.
Especially when we start looking at top measures and you may hear some
commentary from Avista, there may be things that make more sense for a different
initiative than for Avista's own programs. But that is intentional and that is consistent
with Council's methodology.
Kenneth Walter: OK. Let's look at a couple of sectors of draft results, starting with the
residential sector. The graph on the top right, just to orient, that is consumption. Total
residential consumption across both states in these different scenarios, the dark red
line on top represents that baseline. That counterfactual, if program stopped running,
and then the other two lines are our technical achievable. That's the purple and then
under technical potential scenario that is the lowest we estimate residential
consumption could go under a technical potential scenario. And then the bottom chart,
you can see year over year savings from both of those scenarios and that curved
shape that you see is a pretty consistent result of the Councils ramp rates which tend
to be a bit front loaded and then peter off as the markets get exhausted towards the
end of the market. Draft results as we have them now are showing about 1% per year
savings as technically achievable, that's 76 GWh in the biennium period or 8.6 aMW.
And then you can see we've also got the totals across the 10- and 20-year marks
getting all the way up to 890 GW hours by 2045.
Kenneth Walter: And a little preview of top measures. Heat pump water heaters are
still in the conversation for technical achievable, which is a pretty interesting result.
Also, big right now are Energy Star windows, which have received an enhanced
definition yet again, so level setting the remaining market for that, moving that goalpost
forward and keeping consistent with RTF workbooks. Also, EV chargers, as we
mentioned earlier in the baseline slides, we have incorporated the CADEO research
into EV growth and projections, especially in Washington and also the RTF has
updated their information on those chargers which has increased the savings
opportunity from those upgrades. We can talk about that a little bit more on the top
measure slide.
Kenneth Walter: The next slide, we're sticking with still this high-level view. Here you
can get a little breakdown between the two states, but we are showing cumulative total

Appendix A
savings again for technical achievable and technical potential on the right side and
then also on the left where you get the state split. You can just see that Washington
versus Idaho; these are pretty proportionate to their base loads. You can see
Washington has a much higher base load and significantly higher technical achievable
potential. I meant to correct that chart. I apologize, the percentages there have a row
lock issue. They are actually very similar percentage across the states. I will update
that slide deck so that it can be send it out to folks who'd like to see it. Focus on
technical achievable by itself is about 16% of savings and technical potential about
26.9%.
Kenneth Walter: And if we can go to the top measures slide. Alright, this is where we
start getting into the details of what's actually driving these savings levels that we're
seeing on the left. You can see a quick breakdown by the different end uses of where
technical, achievable potential is coming from and on the right is the list of more
detailed measures. As mentioned, windows, water heaters and electric vehicles are
the top three here, but also included on this chart, for putting these measures in
context, we've included the levelized cost of energy. This is the 20-year average value
there and the reason to do that is really to make the point that not all of these measures
are going to be cost effective or pass the IRP necessarily. You can see some of them
are actually very expensive and we'll put them in a little bit more context graphically
on the next slide, but there's still some good stuff here that is likely to pass the IRP.
You can see the number 2 measure there. This represents heat pump water heaters
that are above this new federal standard and that you can see over 62,000 MWh there
that are showing only about 7 cents a kWh in TRC costs. That is likely to be pretty
attractive in the IRP. We'll see how it lands. It may even become more attractive
depending on how it impacts peak values. That'll be something James will tell us later
when he gets it into his model.
Kenneth Walter: In contrast, looking at the two windows measures at 43 cents a kWh
and 56 cents a kWh, those are much higher costs than Avista's avoided costs and
pretty unlikely to pass through the IRP. Just pointing out that this is still an interim step
and has yet to go through cost effectiveness testing, but it is still an interesting
representation of where there's a lot of kilowatt hours in Avista's territory. And this is
really the illustration to drive that home. What we're showing here is a supply curve,
as you go out towards the right savings get more expensive and as you go up the left
side that is in order to get the next bar. If you want to move higher on the total savings
you've acquired, then you have to move further right into more expensive territory. The
green line that we've placed there is an approximation of where the IRP has stopped
finding things cost effective past this point. You can see out of the almost 900,000
MWh that we've identified of technical achievable potential only about 300,000 MWh

Appendix A
of that comes in under that $0.10 a kWh or $100 a MWh mark. This is pretty well
expected. We draw a big net with these CPAs and there tend to be some very
expensive things out there, but this is a good context for what we're actually looking at
here.
Kenneth Walter: Some notable changes from prior CPAs: #1 the big heat pump water
heater change has been pretty impressive. A lot of moving parts, as we've already
been talking about, there are higher tiers that NEEA and RTF have added to their
analysis. So, there is additional savings in those, but we are still competing with that
new federal standard. Without it, the heat pump water heater potential would be three
to four times bigger than it is. But those savings have really been rolled into baseline
impacts now. The EV chargers were barely a blip on the radar in the previous study,
and as mentioned, this is part of the big growth that's been forecast by CADEO and
also increased forecast just even from Avista's internal estimates. And RTF revised its
workbooks and where there was previously very little savings opportunity between two
different levels of chargers. They have increased those savings estimates substantially
from their analysis and we've incorporated into this.
Kenneth Walter: I already mentioned that energy efficient windows have a higher
Energy Star requirement and we have updated our market-based assumption in
keeping with RTF workbooks and the 2020 residential Energy Consumption Survey
data for the State of Washington which provides a little bit more accurate estimate of
the remaining market for this new, way higher efficiency window.
Kenneth Walter: Connected thermostats took a big hit. I didn't dwell on them too much
on the previous slide, but they were previously a number one or two measure technical
achievable for Avista. RTF has cut the savings by a third and cut the lifetime in half
which really brought them down in this analysis. And then there's just been some
bookkeeping and house cleaning applicability of several measures reflecting new
remaining market data available. I already mentioned the Rex 2020 data making sure
that we didn't have overlapping applications. For example, connected thermostats are
in competition with home energy management systems. A single customer can't install
both and we want to make sure that's reflected in our applicability and just making sure
that we have a good balance in our market. Were there any questions on residential
potential before I move on to commercial?
Kenneth Walter: OK, great. On commercial, we've got the same views here. This is
consumption under the different scenarios in the top right annual savings year over
year in the bottom right, slightly higher technical achievable potential as a percent of
baseline. It's 1.1% a year or 84 GWh in the biennial period. Gets all the way up to 943

Appendix A
GWh by 2045. And in commercial, although you do see those level 2 EV chargers
coming in, in the Washington side where we see, predicting a lot of fleet growth. The
bigger story, and maybe surprising to some folks depending on how long you've been
keeping track of these, we still are showing a lot of available LED fixture replacement
potential. Specifically, in our modeling, we're including this as a bundled measure that
replaces conventional lighting with an LED fixture and bundled controls at the same
time. I can talk a little bit more about what that looks like when we get to our top
measures slide. And then there are some various HVAC system upgrades that I just
kind of lumped into one bullet here individually, not all of them are huge, but collectively
there's a pretty good source there.
Kenneth Walter: We can look at the data slide. And again, same slide here to get
some split, although I'm not going to dwell on it because again, I need to correct that
table and I apologize that that version didn't go out before this call. But again, a good
look at how total savings is growing over time. On the right there, you can see that
same 943 technical achievable GWh and 2045 compared to over 1,000 of technical
potential, that's about 22% of the baseline and 26% for technical. Right and top
measures, which is the more interesting conversation than totals. There you see in
that pie chart on the left side there is plenty of lighting which I know a lot of us have
been talking about in the industry over the last few years. There's a big story that
lighting is transforming. LED is becoming the way of the land we have updated to the
newest workbooks from RTF, as far as their market baseline assumptions for lighting
and LED lighting. This is incorporating all of that and in a couple of lighting categories,
particularly high bay, but also insert some early years for linear. Did relax actually what
they thought was going to be happening in terms of LED market penetration in both of
those cases, it's still getting up into the 90 plus percent by the end of the 20-year
period. But it opens the door for a little bit more opportunity in the early years and in
high bay actually just doesn't get as high as it did period. It's actually expanded the
opportunity there a little bit as well as having higher efficiencies predicted by DOE
starting in 2035. For the set last 10 years of the study, we have even higher LED
efficiency than we had previously. Again, this is with embedded controls at time of
replacement, which gives a really nice boost to savings for very little extra cost. And
that's inclusive of this as well. So, they are saving more than a standard LED fixture
replacement would. You can see a little more detail on some of the HVAC measures I
mentioned, #3 there with air source heat pump upgrades and #6 energy recovery
ventilators in the HVAC system. Again, you can see both of those though are pretty
expensive $0.42 and $0.65 per kWh respectively, so they may be a strong savings
available source, but they're also fairly expensive and we don't expect them to pass
the IRP. I think I saw a question pop up in the chat.

Appendix A
James Gall: Yeah. I'll read it for you. Has to do with LED fixtures. The question is
does LED fixture replacement only exist for commercial customers and not residential?
Kenneth Walter: We have some LED bulb replacement, and the residential side is
very little. If you were to flip back to that slide, it's a pretty small slice in terms of what
we're talking about here. These are the big 4 and 8-foot linear lighting fixtures that
have embedded controls in the unit. We have not seen that in the residential space
and it's also worth pointing out that there's very little linear lighting in residential. It is a
low single digit percentage of lighting that's available there. So, not a lot of resource if
they were to be found or tried to implement there. People's garage shop lights are not
a huge source of energy savings there. All right. Here's the same supply curve.
Looking at the commercial potential again, that green line representing where the IRP
has previously stopped selecting, and again you can see only about half the savings
here on the commercial side are below that level. Again, this isn't final. This is an
approximation. We'll see what James's model picks when it gets that detailed hourly
impacts and costs, but it's a good level set for what we might expect to come through
the IRP filter.
Kenneth Walter: Couple of notes on some commercial changes since the last one.
I've already discussed the lighting baseline, making sure that we are using RTF latest
assumptions. Commercial EV fleets are having a very big impact. We did not include
commercial EV at all in the previous study, so that is an enhancement just overall. And
then having those big fleet growth assumptions from Cadeo. And then again, just like
in residential, we always make sure that we're taking the time to make sure that
applicability of building shell and controls measures are updated to the best data that
we have available. We want to avoid overlapping implications, or even just overstating
as buildings have been renovated over the last couple of years, making sure that we're
applying things appropriately to older building shells and not overstating the
opportunities there overall. Actually, the commercial technical achievable potential is
a little bit higher than it was in the previous study, however. Right.
Tommy Williams: That's it.
Kenneth Walter: No.
Tommy Williams: Oh, let's go down to the slide here.
Kenneth Walter: There we go. Next steps I just presented residential and commercial.
To those of you who are wondering where industrial is, we are still working on that and

Appendix A
plan to wrap up the end of the week and working IRP inputs will be headed to Avista
the following week. That's where we're at on the AEG side. James, I don't know if you
have more things that you'd like to add to next steps as far as this group is concerned.
James Gall: After I get myself off mute. I think the next steps after you guys wrap up
will be taking your data and putting it in our PRiSM model for resource selection.
And, like you mentioned earlier, we'll see where the economics move programs in or
out and we'll try to make all data available as soon as we can. Once we're ready, the
idea will be to give the TAC an opportunity to look at the measures, the savings and
the costs of all the savings.
James Gall: I think that's all we have planned for today. I don't know if there's any
questions or comments any of the TAC members have. OK. Well, I'll ramble on just
for a little bit in case something comes up, but our next TAC meeting will be in two
weeks. On Thursday, we will be covering our wind and solar integration study that
determines how much integrating those resources cost from a, we'll call it intermittency
point of view, and that study has been about a two-year process working with some
different consultants and internally with our models. That will be the first study I think
we've done since 2007 for integrating those resources. That's a big deal for us. We'll
also get into some of the scenario analysis that we've been working on over the last
couple of weeks. Stay tuned for that. Any last call for any questions or comments
before we call it a morning? Alright. We'll see you in two weeks. Have a great day.
Leona Haley: Thank you.
James Gall: Thanks Ken, Fuong, and Tommy as well.
Kenneth Walter: Thank you, buddy.
Sofya Atitsogbe (UTC): Thank you.
Tommy Williams: Yep. Thanks everyone.
Andy Hudson: Thanks everybody.
Tommy Williams: Take care.

A endix A
Vop
2025 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 7 Agenda
Tuesday, May 21, 2024
Virtual Meeting — 8:30 am to 10:00 am PTZ
Topic Staff
Introductions John Lyons
Variable Energy Resource Study Clint Kalich
Portfolio/Market Scenarios James Gall
Microsoft Teams meeting
Join on your computer, mobile app or room device
Click here to join the meeting
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���r r/ISTA
2025 IRP TAC 7 Introductions
John Lyons, Ph.D.
Technical Advisory Committee Meeting No. 7
May 21 , 2024

Appendix A
Today's Agenda
Introductions, John Lyons
Variable Energy Resource Study, Clint Kalich
Portfolio/Market Scenarios, James Gall
2

Appendix A
Remaining 2025 Electric IRP TAC Schedule
• TAC 8: June 4, 2024: 8:30 to 10:00 (PTZ)
o Load & Resource Balance and Methodology
o Loss of Load Probability Study
o New Resources Options Costs and Assumptions
• TAC 9: June 18, 2024: 8:30 to 10:00 (PTZ)
o IRP Generation Option Transmission Planning Studies
o Distribution System Planning within the IRP & DPAG update
• Technical Modeling Workshop: June 25, 2024: 9:00 am to 12:OOpm (PTZ)
o PRiSM Model Tour
o ARAM Model Tour
o New Resource Cost Model
• TAC 10: July 16, 2024: 8:30 to 10:00 (PTZ)
o Preferred Resource Strategy Results
o Washington Customer Benefit Indicator Impacts
o Resiliency Metrics

Appendix A
Remainina 2025 Electric IRP TAC Schedule
• TAC 11 : July 30, 2024: 8:30 to 10:00 (PTZ)
o Preferred Resource Strategy Results
o Portfolio Scenario Analysis
o LOLP Study Results
• TAC 12: August 13, 2024: 8:30 to 10:00 (PTZ)
o Preferred Resource Strategy Results (continued)
o Portfolio Scenario Analysis (continued)
o LOLP Study Results (continued)
o QF Avoided Cost
• September 2, 2024- Draft IRP Released to TAC.
• Virtual Public Meeting- Natural Gas & Electric IRP (September 2024)
o Recorded presentation
o Daytime comment and question session (12pm to 1 pm- PST)
o Evening comment and question session (6pm to 7pm- PST)

���r r/ISTA
Avista Variable Energy Resource Integration Study
Update
Clint Kalich
Technical Advisory Committee Meeting No. 7
May 21 , 2024

Table 18: Integration Costs for Base Scenarios
Wind Wind System Forecast Cc�t Cost
IEEE Locaflon Capacity . .
win Columbia Basin 100 MW 5% 15% $2.75 5.0%
a c��a 50/50 Mix of CB& MT 200 MW 10% 10% $6.99 12.7%
Diversified Mix 400 MW 20% 8% $6.65 12.1%
• Diversified Mix 600 MW 30% 8% $8.84 16.1%
ea vlor\,\q Table 24: Effect on Integration Cost of Shod-Term Liquid Markets
t
D [and
dvances in Insights - Annual
Methods for Wind Cap'city Penetration Locafion Cost Savings Savings Mkt Cost Savings
lant Integration 100MW 5% C. Basin $2.75 61.7% $1.70 $I.u5 $490
V) 200 MW 10% 50/50 Mix $6.99 60.8% $4.25 $2.74 $2,456
400 MW 20% Diversified $6.65 38.9% $2.59 4.06 $2,994
600 MW 30% Diversified $8.84 40.6% $3.59 $5.25 $6,224
by Edgar A. DeMeo,
Gary A.Jordan, Table 27: Market Price Impacts on Integration Cost
Clint Kalich,Jack King, Buse
• Michael R. Milligan,
Cliff Murley, Brett Oakleaf, PenetrationMarket Wind System Wind Forecast Cost Savings _
and Matthew J. Schuerger Case Capacity 100 MW 5% C.Basin 15.0% $ 181.90 _ I _52%
Markel 200 MW 10% 50/50 Mix 10.0% $ 589.87 _ 2.67 -62%
INTEGRATION OF WIND-POWER PLANTS INTO 1 Prices 400 MW 20% Diversified 7.5% $ 1,872.51 _ 3-88 -42%
electric power system presents challenges to power-sys
planners and operators.These challenges stem prima 600 MW 30% Diversified 7.5% $ 2,404.10 �.98�.93 55%
1 from the natural characteristics of wind plants,which d 100 MW 5% C-Basin 15.0% $ 920.56 $ Z.Y9 9%
a in some respects from conventional plants.Wind plants o High
ate when the wind blows,and their power levels vary Market 200 MW 10% 50/SO MIX 10.0% $ 5,792.80 $ 8.53 22%
the strength of the wind.Hence.they are not dispatchabl Prices 400 MW 20% Diversified 7.5% $ 9,489.50 $ 7-54 13%
- the traditional sense, which lessens the ability of sys
operators to control them while maintaining the syste 600 MW 30% Diversified 7.5% $ 20,280.32 10.45 18%
E� balance between load and generation.
The impacts of wind's variability and uncertainty on utility
system operation were discussed in this magazine's previous
special issue on wind power(November/December 2W5).By
that time.it had become clear that wind is primarily an energy
iiw,,.n un,�,m.,,nr,xr r rrruwrt�,n;.srn<n•

Appendix A
Differences Between Traditional Resources and VEI ,
Traditional Resources Variable Energy Resources
• Gas, coal, hydro, and biomass • Fuel supply subject to the weather
• Reliable and known fuel supply • Geographical dispersion may help ***
• Responsive to operator direction • Wind fuel supply issues
• "Net contributors" to system ancillary — 36x as hard to forecast as load
service requirements * — geographical diversity helps
• Generation variation is predictable,** as is — varies moment to moment
generally "caused" by operator instructions — wind needs 10-50 mph to generate
• Solar fuel supply issues
— 22x as hard to forecast as load
— driven mostly by cloud cover
— less benefit from geographical diversity
ancillary services covered in later slide
** excludes variation from forced outages that affect all resources
3 but estimating this savings is difficult given varying methods employed

Appendix A
Loading Profiles (as % of Daily Maximum Loading)
January 1 , 2024 (5-Minute Data)
100%
0.1000�_Y
90%
80
—Area Load
70%
CS2 (Gas)
60% Rattlesnake (Wind)
—Lind (Solar)
50%
40%
30%
20%
10%
0%
O Ln O Ln o Ln o Ln o Ln o Ln o Ln O Ln o Ln o Ln o Ln o Ln o Ln o Ln o Ln o Ln o Ln o Ln o Ln o Ln o Ln
O M 7! � N Ln M O ri Ln N O M 7! 7t N Ln M O 7t r-1 Ln N O M ri 7t N Ln M O 7t 71 Ln N O M 7! � N Ln
.. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. ..
4 O O ri r 4 N N M -,* -c* Ln Ln tD r� n oo oo m m O r 4 ri N N M r q* -q Ln Ln LD w r� o0 0o a) (n O -1 r-I N N M M
ri r-1 ri -1 r r-1 r-1 r 4 r 4 r-1 r-1 r 4 r-1 ri r-1 r-1 r-1 r-1 N N N N N N N

Appendix A
Comparing Predictability of Load , Wind , and Solar
January 1 , 2023, through April 30, 2024 (Hourly T-1 vs. Actual Data)
90.0%
85.3%
■Area Load
80.0% Rattlesnake Wind
Lind Solar
70.0%
65.3%
60.0%
51.5%
50.0%
40.0%
30.0% 29.0%
0.4x 35.9x
Load 21.6% Load
20.0%
0.3x 21.7x
Load Load 9.8% 9.9%
10.0%
6.2x 6.3x
2.4% 1.6% Load Load
0.0%
Load Factor Error As %of Forecast Error As %of Maximum
5

Appendix A
Current
Generation
AncillaryServices Must Load Followi G Non- Unavailable
Level
Run .. .. =PM,Reserve Up . .
Minimum Maximum
Generation Generation
Level Level
• What are ancillaryservices? I— capacity services matching real-time variance between load & generation
• Why do we need ancillary services?
— customer load variation
— VER forecast error
— forced outages
• How do we supply ancillary services?
— (generally) "hold back" generator capacity
6

Appendix A
Ancillaries as They Pertain to VERs (Solar, Wind)
Operating Reserves 1000 Reserves for a Sample 3-Day Period
® RegUp LF Up FcstErr Up
750 RegDn LF Dn FcstErr Dn
• Operating reserves are latent 500
dispatchable capacity that can be called 250
upon to maintain reliability during
sudden, unexpected changes of system °
load or generation —250
• Avista currently holds —500
operating reserves types —750
:• Regulation Reserves are procured to handle -loon
rapid, unexpected variations in net load 0000 1200 0000 1200 0000 1200 0000
*e Load-Following Reserves are procured to
handle hour-to-hour variations in net load .;. Spinning Reserves are
ee Forecast Error Reserves are procured to procured to cover NW
handle net load uncertainty in the hour- reserve-sharing agreement
ahead timeframe for load and forced outages
• Reserves are required in both the up 6
.1
and down direction
❖ An "up reserve" is defined as a reserve held integration
to deploy a sudden increase in generation Cost
•:• All reserve types are mutually exclusive and
held independently
7

Appendix A
Ancillaries as They Pertain to VERs (Solar, Wind)
Key Concepts
• Integration costs are driven primarily by the need to hold higher
levels of reserves
• Higher reserve levels are needed because of large variability and
uncertainty of VIER production
• Higher reserve levels means de-optimizing system operations
relative to what they would have been absent additional VERs
8

Appendix A
VIER Integration StudyScope
Purpose and Overview
• What's included in the study?
— consumptive capacity and its costs
— impacts of EIM ("fast") markets
— potential future portfolio VER buildouts
— sensitivity scenarios
• What's not included in the study?
— alternative capacity resources (e.g . , batteries)
— new utility-controlled storage *
— VER-driven investments in existing infrastructure
— distributed generation or response beyond what's in IRP
• we assume size of wholesale market grows commensurate with added VER resources to address need to
transact greater volumes of power (e .g. , 2 ,500 MW scenario has 2 ,500 MW of additional market) `
9

Appendix A
VIER Integration Study
Purpose and Overview
• Consistent application supporting varying analyses
— Integrated Resource Planning
— resource acquisition processes (e.g., RFP)
— transmission rates
— PURPA avoided cost calculations
• Define "Consumptive Capacity" associated with incremental
variable energy resources
• Determine costs of carrying consumptive capacity
10

Appendix A
VER Integration StudyTimeline
Timelines have slipped a bit
June 2022 July 1511 August 81h Q1 X23 Q2X023
Today
VER VER ADSS Study
Project Scenario Scenario Simulations
Kickoff Production Operating Report &
(Avista) Deliverables
Profiles Reserves
Phase 1 (complete) Phase 2
* ancillary services covered in later slide
** excludes variation from forced outages that affect all resources
11 *** but estimating this savings is difficult given varying methods employed

Appendix A
VER Buildout Scenarios
Locations Based on Past Proposals
r--.k �. .
• Three VER portfolios
�on,an.
• Solar, Wind, 50/50*
• Four VER penetrations-�
Eel M.,M-4-
400, 800, 1500, 2500 MW V t ,n
6po1W,.UMy 9011 Sa1+l Cover IrA+..
'h'A
is\1' M.w uM. _ _ ■
Wan so/So Solar Wmd 50/50 Solar Wmd SCISD solar Wend SO/So solar
North Castro,M1 VAnd IrXI ton 200 ICU 20D 200 400 2MI RM na.0
Judith Gap,MT Vend I 200 100 I 200 200 I 300 200 I 400 300 C
saw,atn WA
South Othello.WA Wn ,d 100 I S00 I 100 100 I I50 100 ��
Rattlesnake It Mind I I no I 200 200 no 200 J
Palouf II VAnd I 50 I 75 50 75 75 t
Northern Oregon WW d I ( SO I 200 I 200 tee41-ID.Crkwu.WA
latch,WA wr,d I I 125 I 125 125 �0e
Oregon Oflthore VAnd I I 200 I 5S0 250 •�r.•
South Central WA Wmd I I 100 I 200 «.....
Rattlesnake 111 Mind 200 Sow Cene!WA
lewntm,IDjCJarkston,WA S°lar 100 30U 2C0 300 300 30U 300 300 '
otheaorund,WA solar IOo I zoo eoo I zoo 400 I coo ■ _ ■ Resource Type
Spokane,%CDA DG Sider I wo I 150 300 3W 50D
Grant County,WA Solar I I 200 I 2D0 200 ■ W,nd
Sp°kaneiColv,te tntsallands, I I skaern Gngn
W0. solar lJU :00 300 20U ,�,. •
■ Solar
"to'
nake Wind solar I I 200 I 300 200
Spokane Utility Stale I%Vsl 6 solar 300 • Solar DG
South)
Ent Montana Inea Colstrip Ilne) Solar 400
— ■ Wind Offshore
* 50/50 mix created based on nameplate capacity (e.g., 200 MW solar, 200 MW wind)
12 iirms

Appendix A
VER Profiles and Forecasts
- w�rriwa - eb.a.slw
cvaai,r-
M _
� lb
l„
m
• Forecasts for wind resources utilized the
NREL WIND datasetL Y
:• Wind forecasts were validated to ensure that J
hour-ahead forecast errors were consistent
Y t1 tell UK H HII
with available industry forecast methods
available to Avista
• Forecast for PV resources utilized the
q.
NREL SIND dataset
"
•:• PV forecasts represented a 2006 weather year, q
Ilq qG Oq IIq 'JO ;lp iq Y" fiM t" L"Y 11q I,q 11.q
and were adjusted to represent forecast errors
consistent with available industry forecast
methods available to Avista -
�,_,
m
• Site-specific production/forecasts were
M
summed together to represent total VER M �'
A
production/forecast for each VER " - -
Y
scenario 00 YY YJ. G Jq Yw " O" mq et. Wq IIm q Y" ]lO no-
Wind Forecast Error:
ForecastPV
13 or=

Appendix
Reserve
Calculations
Regulation Reserves
•
•Procured to handle rapid, unexpected variations in load or generation
Reserve levels ar- determined by •Regulation Error= 1-min Net Load—10-minute Net Load Rolling Average
taking •Calculated as a 3a confidence interval of Regulation Errors
a statistical confidence
interval •On-Peak and Off-Peak values calculated by month
of • represent
unanticipated variability or
uncertainty contributed • the
system by '
Reserve identify Load-Following Reserves
level of - • - • to ' "' u • Procured to handle hour to hour variations in net load
of • • and uncertainty of - • Load-Following Error= 1-min Net Load—Hourly Average Net Load
integration for • "� • Calculated as 20 confidence interval of Load Following Error
Each reserve calculation results in an
I '� • Calculation bins load-following reserves held in operating hour by VER forecast
representsMW value that • Discounted by 25%to represent EIM Diversity Benefit
spinning •.
generatorsshould be held by other dispatchable
defined by constraints in the ADSSForecast Error Reserves
production •st mode
Used to handle net load uncertainty in the hour-ahead timeframe
• Energy Strategies' . • • Forecast Error= Net Load— Net Load Hour-Ahead Forecast
reserve confidence
• Calculated as 20 confidence interval of forecast errstatistical analysis ors
• Calculation bins forecast reserves held in operating hour based on VER forecast
based on • Discounted by 25%to represent EIM Diversity Benefit
historical
14

Appendix A
EIM and Reserves
• The Western EIM facilitates procurement of flexible ramping
capacity to address variability that may occur in real-time dispatch
The application of flexible ramping capacity serves to reduce the level of Load
Following and Forecast Error reserves held within the Avista BAA footprint
•:• In 2021, Western EIM flexible ramping procurement diversity savings averaged to 2021 Flexible Ramping Procurement Diversity
approximately 50%
Savings
• However flexible ramping capacity likely would not represent al:1 70%
reduction in load-following and forecast error reserves due to: so% .-
.... ...... ...... ...... ... ... ... ...... ...... ...... ...... ..
❖ Flexible capacity may be constrained by EIM import/export limitations and, thus, 40%
may not be as dependable as physical capacity, resulting in Avista still carrying 30%
20%
some additional level of reserves 10%
❖ Flexible ramping capacity changes hour-to-hour, depending on system conditions, 0%
� � c'c �` a ce �.� 5� e� �c
so more reserves may be required in some hours, indicating it may be appropriate oa oa �a� PQ �` �� �J Poi° `e�O oL�°� ,ee `ee
to assume some reduction in the average flexible ramping diversity benefit
❖ An EIM participant can be excluded from the flexible ramping diversity benefit if ■up ■Down
they fail the flexible ramping test, which would also serve to reduce the flexible
ramping procurement savings
15 ,

Appendix A
EIM and Reserves
VER Profile Operating Reserves
• The graph shows how reserve levels Around-the-Clock Average
relative to the Avista Reference, Baseline +OMW �Cm Dn_Reg
� Up_Reg
and how reserve levels change Wind +400 MW
Dn_LF
Wind +800 MW Up-LF
between VER scenarios Dn_FcstErr
Wind +1500 MW Up_FcstErr
•:• Up- and down reserve levels are similar, _
Wind +2500 MW
in aggregate
50/50 +400 MW
❖ Solar seems to be driving more reserve 50/50 +soo MW
increases per MW of installed capacity, 50/50 +1500 MW C
primarily due to load following 50/50 +2500 MW
❖ Wind Forecast error is larger than PV Solar +400 MW
forecast error, and drives more of the Solar +800 MW =�
reserves in the wind-only scenarios
Solar +1500 MW
Solar +2500 MW
—600 —400 —200 0 200 400 600
MW
• For the VER integration study, we reduced consultant-calculated load following and forecast error reserves by 50%
to reflect benefits of EIM diversity
16 PIM

Appendix A
Study Methodology
• 2021 actual system conditions with ADSS software
— Hydro conditions, outages, fuel prices
• Run Avista system portfolio with and without VER
— 2 VER condition scenarios: without new VER, with new VER
— 5 VER addition scenarios: 400, 800115001 2500 MW
— 3 VER mix scenarios: all solar, all wind, 50/50 solar/wind (by nameplate)
— 3 market conditions scenarios: low, base, high prices
— In total, requires 90 scenarios of 2021 under varying conditions
• Calculate deltas between scenarios to determine integration costs
17

Appendix A
Removing Commodity Energy Value from Study
Two cases include the same energy amounts to avoid biasing results
• "Without VER" scenarios
— input monthly 12x24 energy shape
— no incremental reserves
— emulates a firm contract delivery of same energy quantity as With VER
• "With VER" scenarios
— input hourly-varying energy shape from consultant study
— input incremental reserve levels from consultant study
• Subtracting "Without VER" value singles out integration
18

Appendix A
Preliminary Studv Results - Average Costs
Integration Cost ($/kW-mo) Integration Cost ($/MWh)
Changeset Base High Low Base High Low
Existing 0.16 0.23 0.11 0.78 1. 11 0.53
5050 400 0.05 0.15 0.03 0.20 0.66 0.11
5050 800 0. 12 0.24 0.08 0.50 1.00 0.34
50501500 0.33 0.64 0.21 1.53 3.00 1.00
5050 2500 0.57 0.84 0.49 2.90 4.23 2.50
Wind 400 (0.00) 0.09 (0.00) (0.01) 0.37 (0.01)
Wind 800 0.33 0.71 0.19 1.31 2.85 0.78
Wind 1500 0.90 1.50 0.62 3.78 6.31 2.62
Wind 2500 1.92 2.48 1.74 8.96 11.62 8. 14
Solar 400 0.22 0.41 0. 14 1.10 2.09 0.72
Solar 800 0.36 0.70 0.22 1.89 3.71 1.17
Solar 1500 0.42 0.80 0.28 2.46 4.64 1.62
,Solar 2500 1 0.84 1. 13 0.77 1 6.00 8.14 5.50
19

Appendix A
PreliminaryStudy Results - Marginal Costs
Integration Cost ($/kW-mo) Integration Cost ($/MWh)
Changeset Base High Low Base High Low
Existing - - - - -5050400 (0.03) 0.10 (0.03) (0. 13) 0.39 (0. 13)
5050 800 0.11 0.24 0.07 0.42 0.97 0.28
50501500 0.36 0.72 0.23 1.66 3.33 1.08
5050 2500 0.62 0.91 0.54 3.15 4.60 2.74
Wind 400 (0.12) (0.00) (0.08) (0.40) (0.00) (0.28)
Wind 800 0.39 0.88 0.23 1.45 3.32 0.85
Wind 1500 1.04 1.74 0.72 4.26 7.13 2.95
Wind 2500 2.12 2.74 1.92 9.84 12.75 8.97
-Solar 400 0.26 0.54 0.17 1.34 2.81 0.87
Solar 800 0.43 0.87 0.26 2.33 4.73 1.42
Solar 1500 0.47 0.90 0.31 2.85 5.46 1.87
Solar 2500 0.91 1.24 0.84 6.91 9.38 6.37
20

Appendix A
Next Steps
• Finalize study results
• Generate final study report
• Use in future IRPs/RFPs/transmission tariff
21

Appendix A
VER Study Uses in the 2025 IRP
• Integration Cost ($/kW-month) included as a resource cost (slide 18)
• Reliability modeling will include a "Flex Ramp" adjusted for EIM
benefits reserve determined by this study (slide 15)
• Capacity expansion modeling will include a small incremental flexible
capacity requirement for each state using this study
22

Appendix A
Questions?
23

���r r/ISTA
2025 IRP Market Scenario Update (DRAFT)
James Gall
Technical Advisory Committee Meeting No. 7
May 21 , 2024

Appendix A
Market Scenario Update
• Expected Case (Deterministic/Stochastic)
• Low Natural Gas Prices
• High Natural Gas Prices
• No Washington Climate Commitment Act
Z

Appendix A
Henry Hub Natural Gas Prices
$14.00
Expected Case Uses 951h percentile of stochastic study
$12.00 Low Natural Gas Price Scenario
High Natural Gas Price Scenario
$10.00
$7.20/dth
E $8.00
$5.01/dth
$6.00
$3.86/dth
IL
$4.00
� Uses 25th percentile of stochastic study
$2.00
$0.00
to ti OO M O N M V u7 W ti 00 M O T_ N M le u7
N N N N M M M M M M M M M M le 11 11 It Nr 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
3 Prices inserted are 20-year nominal levelized

Electric Price Forecast Appendix
Mid-Columbia (Washington Delivery)
$80.00
$70.00
$60.00
$50.00
L
$40.00
Q
$30.00 -Deterministic ($45.45)
-Low NG Prices ($41.52)
$20.00
High NG Prices ($52.89)
$10.00 -No CCA ($40.85)
$0.00
W 1­ 00 O O r N CO) 11 LO W f- 00 O O � N M le LO
N N N N M M M M M M M M M M le le le le le le
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
4 Prices inserted are 20-year nominal levelized

Electric Price Forecast Appendix
Mid-Columbia (Non-Washington Delivery)
$80.00
$70.00
$60.00
$50.00
$40.00
CL
$30.00
$20.00 -Deterministic ($44.37)
-Low NG Prices ($40.41)
-High NG Prices ($51.86)
$10.00 -No CCA ($40.26)
$0.00
(D I` 00 O O N M I* M CD I- 00 O O r N M le LO
N N N N M cM M M M M M M M M 11 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 N N N N N N N N N N N N N N N N
5 Prices inserted are 20-year nominal levelized

�iiVISTA°
2025 IRP Load Forecast

Appendix A
System End Use Changes in Load Forecast
Annual Average Load Growth/Decay Rate Annual Average Load Change
Between 2045 and 2024 Between 2045 and 2024
Process -1.03% Lighting -22
Lighting -0.93% Generation -11
Motors -0.73% Motors -8
Ventilation -0.72% Ventilation -8
Water Heating -0.47% Water Heating -7
Losses -0.17% I Process -3
Large Industiral -0.08% I Large Industiral -3
Food Prep 0.07% Losses -2
Cooling 0.37% Food Prep 0
Office 0.42% Office 3
Misc 0.49% Cooling 4
Space Heating 0.72% Refrigeration 10
Appliances 0.87% Appliances 15
Refrigeration 0.96%
Misc S 15
Electronics 1.69% Electronics 16
Generation 4.97% Space Heating 27
Electric Vehicles 19.77% Electric Vehicles 223
-5% 0% 5% 10% 15% 20% 25% (50) - 50 100 150 200 250
Annual Average Percent Growth/Decay 20 year aMW load change
7

Appendix A
Energy Forecast
1,600
1 ,400 0.81 % AAGR
1,200
3 1 ,000
1 .08% AAGR
a,
800
c�
600
Q 0.31 % AAGR
400
—WA- 25 IRP ——— WA- 23 IRP —ID- 25 IRP
——— ID- 23 IRP —System- 25 IRP ——— System- 23 IRP
200 Actual 5yr Forecast
0
In CO f` 00 O O N CO 'I�r Ln cO I— 00 O O N n q LO CO � 00 O O N CO IzT Ln
N N N N N N N N N N CO n CM n CM CO CO CO CO CO IZT Iq � Iq ZT "Z: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
N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N
8

Appendix A
Peak Forecast ( Forecast is 1 -i n =2 Weather Event)
3,000
2,500 1 .02% Winter AAGR
1 . 10% Summer AAGR
2,000 ��.••��+�
3
1,500
1.000
Actual Winter -Actual Summer
500
---2023 IRP August --- 2023 IRP January
••••••2025 IRP August •••••• 2025 IRP January
2025 IRP Winter 2025 IRP Summer
0
V 2 C2 ti o0 6) O N n � LO (0r` 00 6) O N M V LO CD ti c0 0) O N M LO
N N N N N N N N N N COM CO CO CO CO CO CO CO 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
N N N N . N N N N N N N N N N N N N N N N N N N N N N N N . N N
9 slid

Appendix A
TAC 7 Meeting Notes, May 21, 2024
Attendees:
Sofya Atitsogbe, UTC; Kim Boynton, Avista; John Barber; Molly Brewer, UTC; Kate
Brouns, Renewable NW; Michael Brutocao, Avista; Logan Callen, City of Spokane;
Katie Chamberlain, Renewable NW; Josie Cummings, Avista; Kelly Dengel, Avista;
Mike Dillon, Avista; Jean Marie Dreyer, Public Counsel; Michael Eldred, IPUC; Rendall
Farley, Avista; Ryan Finesilver, Avista; Grant Forsyth, Avista; James Gall, Avista; Bill
Garry; Konstantine Geranios, UTC; Amanda Ghering, Avista; Michael Gump, Avista;
Leona Haley, Avista; Tom Handy, Whitman County Commission; Fred Heutte, NW
Energy Coalition; Kevin Holland, Avista; Joanna Huang, UTC; Clint Kalich, Avista;
Scott Kinney, Avista; Seungjae Lee, IPUC; Dan Lively, Clearwater Paper; Kimberly
Loskot, IPUC; Mike Louis, IPUC; John Lyons, Avista; Patrick Maher, Avista; Jaime
Majure, Avista; Ian McGetrick, Idaho Power; Tomas Morrissey, NWPCC; Austin
Oglesby, Avista; Michael Ott, IPUC; Tom Pardee, Avista; Meghan Pinch, Avista; John
Rothlin, Avista; John Calvin Slagboom, WSU; Dean Spratt, Avista; Victoria Stephens,
IPUC; Lisa Stites, Grant County PUD; Jason Talford, IPUC; Charlee Thompson, NW
Energy Coalition; Yao Yin, IPUC.
Variable Energy Resource Study, Clint Kalich
[Recording and transcription started after the introduction.]
Clint Kalich: But we still didn't have real data to compare to, whereas today we do.
We have a lot more information in the industry to study, so let's step into that. Let's
just step back at the beginning here. I will mention though, that there is a work group,
if you're interested, I think the folks, some of the folks I see on the invite list today are
attending today were included in our workshops on the variable energy resource study.
I will say that we've been paused on that study primarily because of an effort we went
into the EIM, and we had to do a lot of new coding to support EIM within the ADSS
software. And when we finally stopped that effort and finished and went into EIM in
2022, we found a lot of what industry insiders called technical debt. For me, what that
means is a software doesn't work. While we got the software to work great for our
trading floor and for the EIM integration, all of the tools we used in ADSS for planning,
which was actually what it was originally designed to do, had broken. The development
team over the last year and a half has been putting all of the pieces back together so
that we can do these studies.
Clint Kalich: So, we had to pause this variable energy resource study. There were
three phases. The first phase was the data collection, and then going over to Energy
Strategies, a consulting firm, to calculate the incremental ancillary services, which I'll
talk about that are necessary to run the study. Then there was the ADSS model runs
that actually occur. The third phase is back to Energy Strategies whereby they take a
look and audit the results of our ADSS software model runs. We're currently in Step 2,
which is the modeling. We're very close, but we're not finished. But the work group

Appendix A
has paused while we're waiting for the ADSS software to be brought back to life for
the planning modules of that software.
Clint Kalich: Now let me step back the differences between traditional resources and
VERs. So, what are traditional resources? There are quite a few different ones. I don't
have them all here, but traditionally in the northwest — coal, gas, hydro, and biomass
have traditionally been used. They have a reliable and known fuel supply. In other
words, if you have a coal plant, you have a pile of coal out there. You know the fuel is
there and you can turn it on and off when you need it. It's responsive to operator
direction either on a scheduling basis for the next hour, or even instantaneously hour-
to-hour, or automated on AGC where the computers control it. If they ask for 10 more
megawatts, they get 10 more megawatts. If they ask the resource to back off 10
megawatts, the resource backs off. That's generally not how variable energy
resources work. I'll talk about those in a minute. We talk about them, or I talk about
them, as being net contributors to system ancillary service requirements. In other
words, because you can control them and move them around, they actually support
system operations and system reliability. The generation, the variation is predictable,
as it's generally caused by operator instruction. So, if you look at a resource
performance, say at our Coyote gas plant, you're going to see a lot of up and down,
not anything like a variable energy resource, but almost all of those ups and downs
are driven by the operators. The operators wanted those plants to move up and down.
They're not reacting to the movement of those plants, so if a variable energy resource
comes offline because the wind stops, you can bring this resource up and it's
predictable and controllable. That's what a traditional resource is. It generally helps
your system respond to load changes, but variable energy resources are quite a bit
different. They act, in some ways a lot more like a load, although they're tremendously
more variable than load.
Clint Kalich: What are some of the characteristics of variable energy resources now?
The obvious one, I didn't even list it here, is it's carbon free. That's one of the huge
benefits some of the traditional resources are carbon free biomass, nuclear, but
variable energy resources certainly are carbon free, and that's why we're chasing
those resources to, as part of our decarbonization strategy. But the downsides are the
fuel supply is subject to weather, and these are some of the things that cause this
integration costs that we're studying. The good news is that geographical dispersion
can help, and in fact you're going to see in some of the statistics today we expect as
we get geographical dispersion from our existing resources, which all are within our
fairly small footprint. In other words, they're located close to our loads, but the
downside is they all operate within the same weather patterns. But as you get
geographical dispersion, it should help. Let's talk about wind fuel supply issues

Appendix A
specifically. It depends on how you look at it. I have some pictures on this, but wind is
about 36 times as hard to forecast as load. In other words, it's 36 times less
predictable, and I'll show some statistics on that later. So, it's a huge challenge. One
MW of wind is like 36 megawatts of load, so we've always dealt with load and loads
have been difficult to deal with. But wind is much more variable, so it has really
challenged our industry.
Clint Kalich: I've already talked about geography, but when it varies moment to
moment. Literally, you can lose an entire wind farm over a period of a few minutes,
especially when a large blast of high-speed wind comes into play. There's cut outs,
you lose them instantly. Other instances where it gets very cold, you may lose those
turbines more slowly. Or when the wind is coming online, you may have turbines come
online, still very quick, but it won't be instantaneous. There's a lot of variability there.
And another thing is you need wind to generate between roughly 10 and 50 mph to be
able to make any power out of these plants. A lot of times wind is lower than 10 miles
an hour or above 50 mph, and in those cases, you don't have any wind generation.
Clint Kalich: On the solar side. Depend again on how you look at the statistics. Solar
isn't as tough to forecast as wind, but it's still about 22 times as hard to forecast as
load. And substantially this is driven by cloud cover. I mean, certainly solar is variable,
but a lot of the variability is the fact that the sun goes down, the sun going down is
fairly predictable. So, what's driving the variability on solar otherwise is cloud cover.
As the clouds go overhead there appears to be less benefit from geographical
diversity, at least as far as the variability goes. But there are some geographical
benefits due to diversity. Again, things we learned with energy strategies and studies
were done on the data we had.
Clint Kalich: Let's just look at a few pictures I talked about when being 36 and solar
being 22 times as variable. Here's some data, I picked the first day of January 2024
and it's not a bad day or a good day. It just was wonderful because it shows some of
the variability. You can see the load shape there in blue. I'm starting at 80% of what
did to make them apples to apples is I graphed their average load relative to their peak
for the day. So, you can see here for in the load we start out the beginning of the day
at just under 80% of the peak for the day. In that moment in time, and you can see it
goes from 80% down a little bit and then comes up and by the end of the day, we're
back down about where we started. So, you can see variability from fairly smooth and
predictable because, again, load is reasonably predictable, and you can see where
the load went.

Appendix A
Clint Kalich: Similarly, on Coyote, that's the orange line at the top. You can see
Coyote came in running at capacity all day. We backed it off a little bit. Midday it came
back up. Back it off a little bit again, and then brought it back up and you can see here
that changed. These changes, though, were driven by operator choices, so we would
call it this day, Coyote was wonderfully predictable and controllable, so Coyote causes
no real issues around reliability or variability.
Clint Kalich: But then let's look at wind and solar. Rattlesnake Wind. I grabbed in
yellow. Here's what Rattlesnake Wind did, it started out at 40% of its 150 MW
nameplate at the beginning of the day, fairly rapidly, over an hour dropped to zero,
was offline for seven hours, and came back on a little bit, dropped offline, came up a
little bit, and then back up midday. Interestingly enough, this wasn't our peak load. You
can see our peak loads here and then, but it performed as soon as our peak load
happened this day. Rattlesnake dropped offline and down again. You can just see all
the variability and here's wind, of course. Wind in green. It's dark, so you don't have
any solar in January until you get into the 8:00 o'clock hour. You can see it came up
fairly predictable, but obviously we had some cloud cover and it dropped, it recovered,
and now we were in the middle of the day. We had much more solar and then you can
see the variability though with the cloud cover and then evening happens and it shuts
off. And of course, our peak loads, here it's dark, so we have no generation
contribution from solar at all. This graph says lots of things, but this is a pretty standard
day for our resources and our loads. There's nothing unique or unusual about this.
This is not an example that is that is biased against wind or solar. It's just an average
day and what we deal with, and this is what the rest of our portfolio deals with, the
movement around load, which is reasonably predictable but does move up and down.
And this variability around wind and solar, it's a tough thing, but our operators
obviously deal with it.
Clint Kalich: This is statistics. Taking a look at our forecast, if you look at one hour
before the actual delivery of the resource and what we actually got, so how much error
was there in the forecast one hour before you actually incurred, in this example the
load. So, here's the average load factor of these resources over a year. Our load factor
on our retail load is about 65%. So, for each MW on average, we deliver .65 megawatts
to serve load relative to our peaks on wind. It averaged in this period of time, January
through April of 2024. So, a year, actually it's a year and four months, it was a 29%
capacity factor and it's about 40% of the load factor of our load. And then solar was
22%, about 30% of the load factor of our load. But let's look at the forecast error as a
percent of the forecast itself, you can see here this is pretty standard. The mean
average error on loads about 2.4%. And the way we buy these services from third
party forecasting services, they're state of the art forecasts, whereas you look at when

Appendix A
you're off by 85.3%, the average error relative to your forecast is 85.5%, which is that
36 times I talked about. And then if you look at solar, it's about 51-52%. So, some
pretty amazing statistical difference between 2.4% versus 85%.
Clint Kalich: If you want to look at nameplate capacity. Some people like to look at
the error and forecast relative to nameplate. I don't think that's the right way to look at
it, because that's not how we do our system operations, but you might see these
statistics in some publications. I wanted to provide it as a percent of maximum
capacity. Load is 1.6% whereas wind is 10 and solar is 10. They're about the same
into their nameplate capacity, so I wanted to share that information. Any questions at
this point? I'll go ahead and stop. I just dumped a bunch of statistics out there, so if
anybody had any questions, I'll pause for a minute.
James Gall: We've got a hand raised. Want to go ahead?
Fred Heutte: And there. Yeah. It's Freddie Heutte, Northwest Energy Coalition. As
usual, I have a question or two, so this is for I just missed something. This is just for
all of your wind and all of your solar combined, right? It's not just a single facility.
Clint Kalich: Well, all we really have, Fred, is we have two wind farms and we have
one solar facility.
Fred Heutte: Right. OK.
Clint Kalich: This is Rattlesnake by itself, and this is our Lind solar plant by itself.
There's not a lot of diversity in our portfolio, so the statistics wouldn't be greatly
different, but you'll see our study looked at the diversity because we expect to see
diversity.
Fred Heutte: Right, exactly.
Clint Kalich: In fact, you're going to see the next tranche of wind actually reduce our
wind integration costs relative to what we have today, because it should add diversity
to our portfolio. We expect it to.
Fred Heutte: Right, and this was.
Clint Kalich: You're going to see our incremental VERs are actually going to lower
our average integration costs. They will probably in our RFPs get a reduction in cost

Appendix A
because of the benefits we expect them to bring. So yes, this is just one project by
itself.
Fred Heutte: Right.
Clint Kalich: This is not a portfolio. That said, I really don't have a portfolio today that
has much diversity relative to this. I have one solar farm, so that's all I have.
Fred Heutte: Right. Got it.
Clint Kalich: Yeah. Well, it's a good clarification.
Fred Heutte: I think where this goes is it's an interesting tradeoff. Actually, it really
argues for and even within some of the large wind and solar facilities, there is going to
be variability within them. [Where they] have a couple of thousand acres, there's going
to be some variability, maybe not very much. One thing we've learned, my friend Justin
Sharp, a meteorologist here in Portland,just finished a big report for the energy system
integration group on weather data and grid operations. His doctorate is in Columbia
Gorge wind. You can't get more complicated than that. We've learned a lot from his
work that a lot of micro variability, but really, looking at it, even a fairly large [project]
like Rattlesnake or Lind. The interesting tradeoff here is you get more diversity, maybe
with smaller new solar and wind facilities spread out over a wider area, but then that
maybe might raise the cost a little bit because you get economies of scale with a 200
MW wind farm or solar versus a 20 MW one. But the diversity has real value and is
really something I hadn't really thought about it like that. These really big developments
have a lot of local impact, so there can be local opposition and so on. It really says
something about the strategy we have to look at going forward. Finally, just want to
commend you now personally and Avista for sticking with us for the last two decades
and really being out on the leading edge of this because we all learn from what you're
finding and that's really pretty important right now.
Clint Kalich: Well, thank you for that. Absolutely I think all of what you just said is true.
This study will help us value that diversity to an extent the one piece that this does not
do, we didn't when we had our contract with Energy Strategies, and part of the
challenge is probably technically possible, but we didn't look at trying to say well what
if we for example instead of buying 20 or 50 MW solar farms, what if we targeted 2 to
5 MW solar farms trying to get greater diversity. I think there's a lot of challenges to
doing that as far as transmission and contracting and economies of scale as you
mentioned, but there may be some diversity benefit. We could do some scenario
analysis based on some back of the envelope diversity assumptions. In other words,

Appendix A
if we could increase diversity and reduce reserves by 50%, what are we willing to pay
for it? But here's the flip side of that, though, is our integration into the EIM has already
substantially managed a lot of that. I'll talk about it later today. We've taken the reserve
obligation of these, even these diversified portfolios that Energy Strategies worked on,
and we cut the incremental reserves by half, which is about what we're seeing as a
diversity benefit in the EIM. That's the reduction we're seeing because you're getting
the full footprint of their larger forecast. So, in some ways, we've already accounted
for that, and we've accounted for it in this study.
Fred Heutte: Yeah, the real, the big breakthrough for me was about a decade ago,
the Western wind and solar integration study, which Michael Milligan worked on,
among others, showed one they had multiple pieces. I could put the link in the chat
here in a moment, just in case anybody's interested. Really showed that resource
diversity across a big footprint like a regional footprint that the decorrelation of the
output of these different resources and also the types of resources.
Clint Kalich: Good.
Fred Heutte: So, it's a geographic diversity and resource type diversity that you get
some benefits from, and the market is a way to capture all that. And of course, that
then depends on having enough transmission.
Clint Kalich: Yeah. We're involved, I think, in all those facets. We've joined the EIM.
We're looking at EDAM and Markets Plus and of course looking at ways to support
that transmission build out. All of those things were aware of, we certainly want to see
those costs come down. Frankly, we need those costs to come down or they translate
to cost. What are we doing physically that creates those costs and what it is, what I
call consumptive capacity, and every MW I need to set aside, say, to follow a VER, I
can't follow a MW of load. Essentially, I end up having to build all this additional
capacity, which is low utilization, very expensive. All of these things benefit the system
and at the end of the day, benefit and make the VER resources and the
decarbonization more efficient, and hopefully at the end of the day, customers having
a lower cost or even if they have a higher cost of decarbonization, we want to minimize
what that incremental cost is. All of these aspects are how we get there.
Clint Kalich: Let's move on. I've got a lot of slides, a lot of data, so let's talk first about
ancillary services, because I talk about consumptive capacity and that's really what
this all is about. It's a deoptimized use of the non-variable resources. In other words,
our other resources that are under control of the operators, they have to operate
differently and they're deoptimized from what they otherwise would do. Let's look at

Appendix A
this picture at the top, there's this current generation level we have what's called
automatic generation control and we have to carry a certain percentage of our capacity
online that responds to the frequency of the larger grid. We call that automatic
generation control and load can move up and down. So, our generation level needs to
bounce up and down in this red zone based on our load requirements. If a wind farm
stops generating, our generation backs off a few megawatts, you have to move up the
rest of your resources to cover that variance or down if the generation is more than
you expected it to be. So, you have this instantaneous ability where the system we
have to manage loads and resources in instantaneous time. We need to make sure
we have resources that can respond instantaneously.
Clint Kalich: Beyond that, we have some of what people call regulation service too.
There's some overlap there, but those are resources that are online and responsive.
In addition to that, there's some spinning and non-spinning reserves. Those are called
contingency reserves if you have a forced outage, so let's use a few examples. If we
had a gas plant and the transformer signals that there was some problem with the
transformer, the plant operators would require us to shut that plant off immediately and
that was unexpected. We have to have reserves of other resources that we can rely
on to back up that, in Coyote's case, 300 megawatts of capacity. That's a lot of capacity
on a wind farm. It could be cold weather cutouts or overspeed cutouts for our Kettle
Falls biomass plant. It could be a problem with our fuel supply, we feed a bunch of
waste fuel products in there and we can have problems with various things going on
there. Whether we have tube leaks in the boiler or trouble feeding the fuel into the
boiler, there's lots of things that could cause issues. You could also have a
transmission outage that separates your generator from your load, and you have to
have other resources to step up. Those are there and they're called contingency
reserves because you don't exercise them very often, but you still have to have them
available.
Clint Kalich: Then there's what I call load following, which is the load following up and
down. If you're carrying a schedule for an hour, you promised to serve all of your load
variability, all of your other variability in your system, and you're selling 100 megawatts
to the to various external parties. You're holding 100 MW net schedule outside your
system to third parties, but you're load and everything's changing, you still have to hold
your system steady by bringing those other resources up and down. They don't
necessarily have to be responsive to AGC, but eventually you're going to have to
replace it as load moves up in the morning. For example, you might have a 200 MW
swing from 6:00 o'clock AM to 7:00 o'clock AM. Where do you make up that 200
megawatts? It's really expensive to have AGC resources provide that because there
aren't that many resources that are able to move that fast. So ,what you do is you have

Appendix A
other resources that I call slower, they're slower responsiveness, but the AGC can
capture the movement of the load for a while. Then you bring one of these load filling
resources on and direct it to operate up more as the AGC will back down and then you
can reset. It's almost like a stair step for your AGC units, so that's load following and
then in addition to that you have certain resources that you have to run. If you have a
nuclear plant or a coal plant, Colstrip, we have minimum operating levels we have to
run. So, the minimum you can generate in your portfolios and then there are units that
maybe are offline or derated and that would be your maximum generation level. So,
you're at your current level and you move up and down in the hour, depending on what
you're doing there and those are what helps you do that or answer your services to be
able to move and respond to load changes.
Clint Kalich: So, what are their capacity services matching real time variance between
load and generation? I pretty much have explained that at nauseam here. Why do we
need them? And I already said this as well, customer load variation, VER forecast
error, and the other major categories, forced outage, and we've already talked about
those. So, what we're talking about for variable integration VERs study is we're looking
at additional incremental load following up and down and additional AGC. And also,
when you have a new resource, you always have spinning and non-spinning
requirements that come along with any asset, but that's the same on a per MW basis,
whether you have wind or you have gas or biomass or nuclear. Those pretty much are
apples to apples. There's no difference, but what really is different in the case of
variable energy resources is this load following and regulation, the blue and the red or
excuse me the green and the red. That's what we're quantifying today.
Clint Kalich: And I'm going to show some slides on that piece, and I'll start showing
actually some how do we provide it. And I already talked about, it's essentially a hold
back on the existing generators we have. Noxon, instead of maximizing its generation
on the peak hours of the day, might have to reduce the amount of peak hour generation
it provides so that it can cover these incremental ancillary services. That means Noxon
generates less value for customers in the energy market because it's providing
ancillary services for the variable energy resources. I'm going to show a few slides
throughout.
James Gall: Hey, Clint. Before you go to the next slide out, there was a question in
chat that I missed from I think a statement you made earlier. This is from Yao. It says
I think you mentioned that there was a pause in the study, but what is your timeline for
completing the study? And we're going to show results here. Is there a pause?
Clint Kalich: Yeah. We had that pause and it's been almost two years now, our

Appendix A
software is back up and running. We still have a few little issues where we get a few
hiccups in the network, but substantially now we can complete the studies. You'll see
preliminary work today. We're just about to the point of finalizing the study and then
we'll have Energy Strategies review the data to make sure that that they think it meets
their understanding of a good wind integration study, that third party review, and then
we'll have some results. I would say late summer, end of the year worst case.
Clint Kalich: And I think, James, you're planning even if we haven't completely
finalized it, you plan in the IRP is to use the preliminary results, right?
James Gall: That is correct, yes.
Clint Kalich: Because we are very close. We've actually run numbers. We have a
good feel for the numbers. They're looking very reasonable. I have a few slides here,
if they look like this with that aqua blue or blue green color, these actually are Energy
Strategy's slides that I've cut out to share. Again, the workshop, and if you're interested
and you haven't seen the workshop presentation materials, reach out to I guess John
maybe is the best resource there and we can get you those. We can also get you on
that workshop group so that you'd be updated when we do have our next public
meeting on variable energy resources. But here are the operating reserves and they
show an example of. The one piece I didn't mention was the forecast here. There are
actually 3 components, regulation, load following, and then there's forecast error.
Remember, I showed that slide before where you have a forecast hour ahead and so
maybe you think your wind resource is going to generate 100 megawatts next hour,
but it actually generates 80 or maybe it generates 120 megawatts. The energy you
need to make up that delta between the forecast and the actual has to come from
another resource on your system, that's the pieces here. You can see in this picture
the regulation Energy Strategy's showed, just an illustration here, over a one-day
period actually looks like it's 1-2-3-day period and then you've got the load following
up and down and then the forecast error. You have to carry reserves up and down to
cover that forecast error to make sure you can meet loads. Those are the four
categories and I already mentioned the spinning and non-spinning reserves, but
they're both in the upward and downward direction because you don't know exactly
where that wind resource is going to be back to that example you thought you had 100
coming in, but did you end up at 80 or 120, or at 0, or 150 the maximum capacity of
the wind facility. Really don't know where it is, but what's important is statistically to
understand what those incremental obligations are.
Clint Kalich: We'll go to the next slide here. Let's talk about some key reasons for
this. Some of this will get a little bit repetitive, but I want to make sure everybody

Appendix A
remembers the key concepts. First of all, integration costs are driven by the need to
hold higher reserve levels, the regulation, the load following and the forecast error.
They're needed substantially and the reason we separate VIER resources out is
because of their large variability and uncertainty relative to traditional resources and
even load. And again, the key concept here. Why is there an opportunity cost? Why is
there a cost of incremental reserves? Because we're deoptimizing our system
operations relative to what they would have been if we didn't have VERs in our system.
That's ultimately where it comes out as costs. Now the benefit of the fuel being free
on when we account for that and the portfolio costs too. There's also a lot of benefits
around wind and solar because they don't have any fuel costs. We do account for that
in our planning as well. Again, you can have a lot of value for the VIER, but a little bit
of it comes back in the form of these additional ancillary services that we have to do
the integration costs. It's not like we're ignoring the other benefits of the resource at
all.
Clint Kalich: So, what's included in the study scope? First of all, we're talking about
what I've called consumptive capacity. Those ancillary services we need and the cost,
we're considering the impacts of EIM and already kind of gave away the answer there.
We've reduced the amount of incremental ancillary services by 50% to reflect the
savings that the EIM is seeing with the diversity of the larger West Coast footprint.
We're considering how the build outs look different levels and I'll show the levels of
build out we're looking at going forward, but it's basically between adding 400 to 500
megawatts of incremental wind and we're looking at sensitivities based on diversity. In
other words, do we have a lot of Columbia Basin wind, or do we include wind that's
diversified around the entire northwest, including east of the Rockies in Montana? And
then we're looking at market prices; low, medium and high wholesale market prices
because we learned in our 2007 study, and it's been confirmed in this study that with
higher or lower prices you see a different integration cost. It's important to at least be
aware of that information. So, what's not in this study. We're not looking at batteries
here. Certainly, to the extent you put batteries on a wind farm or a solar farm, you
reduce the variability. Potentially you also offer, if it's configured correctly, you offer
the utility an opportunity to arbitrage the energy market and provide ancillary services
out of these batteries. So, they can stand alone on their own and generate value into
the portfolio beyond just helping mitigate some of these impacts of variable energy
resources. Now the fact that they aren't included in this study doesn't mean we're not
considering it. James is doing a lot of work around this for the IRP. So don't think that
we aren't studying it. It's just in this specific variable energy resource study, we're not
evaluating batteries today.

Appendix A
Clint Kalich: OK, I already talked about batteries on the wind farm. We're not looking
at other storage assets on the portfolio in this study either, so we're not matching. If
we put 400 megawatts of wind into our portfolio, theoretically we aren't putting another
400 or 800 or 200 megawatts of batteries in to provide general capacity into our
portfolio. We're assuming our non-VER portfolio stays the same size. We're not
making any other investments in existing infrastructure. We're dealing with what our
portfolio is today and we're not looking at further distributed generation or demand
response beyond what's already in the IRP. Those are all being considered in the IRP,
but they're not part of this study. One thing that is important to note though, which kind
of gets back to and somewhat contradicts what's being said here on batteries. We are
assuming as we add for resources, and remember I said up to 2,500 megawatts, we're
essentially talking about adding as much new VIER resource capacity here as we
already have on our entire system. This is a huge, I can't emphasize enough, 2,500
megawatts is a huge amount of variable energy resources for Avista. It's a doubling of
our system capacity. We are assuming on that case that we are able to go out and
interact in the hourly markets up to another 2,500 megawatts. We are assuming a lot
of additional liquidity that doesn't exist in the wholesale marketplace today, which in
some ways acts a lot like a battery would act if we put a battery on our system. If we
didn't assume that the system couldn't solve, we literally would have blackouts and we
would have oversupply situations, extreme oversupply and blackouts situations. You
just can't consume. Actually, the blackouts probably are less likely, but you have huge
oversupply conditions, or you be dumping wind all the time and the economics, it would
just be tremendously cost prohibitive. You'd have no place to put that surplus energy
to reduce or to buy down the cost of that asset. You buy 2,500 megawatts of wind if
on average you can only use 20% of that because you can't balance in the market.
The cost of customers would just be huge, so we really do need to get that power out
into the broader marketplace. And when it's surplus to our needs, we can reduce the
cost customers pay and also then use those dollars to buy energy in times when our
wind is not operating. We can go out to the market and buy that power and replace it.
Those are important concepts here, yes.
James Gall: Hey, Clint, we have a question in the comment. The chats? Yeah, I was
asking, what are the justifications for not including batteries in the study?
Clint Kalich: Well, I think it's just a scope creep. There's an infinite number of
scenarios you could run, so like I said, we're looking at that in the IRP. Itjust isn't done
at this level of specificity. That being said, James and I yesterday were actually talking
specifically about bringing battery technology into ADSS so that we can model it within
the larger portfolio. We'd be able to do exactly that. It's just a matter of time and effort
to do that work, so we're well on the way. ADSS can model batteries. The operational

Appendix A
intricacies of batteries. It has some of the most powerful battery modeling capabilities
of anything out there that I've seen out there in industry in the marketplace today. We'll
be able to do some really good work around that, but in this study, we weren't able to
do that given the time and constraints we have, but it's coming.
James Gall: We got another question now from Fred. Fred, do you want to go
ahead?
Fred Heutte: Yeah, just a note, and I realize this study scope is way down the track
and you probably can't really change it. And I also recognize the many complexities
involved in doing battery or hybrid analysis. That's a very complicated thing, but I'll put
a link in the chat here to an article that just came out. S&P Global has done a big study
of hybrids around the country, noting among other things, 98% of what's in the CAISO
or California queue is hybrids now on the solar side. Anyway, this is kind of a multi
layered complex thing. I guess my sense is what you've laid out would provide at least
an understanding of what the balancing needs are and the opportunity for time shifting.
You can use the solar during the day or wind whenever it happens, and if you don't
need it right then, or you have other resources, or you have the market that also is
available, then you have an opportunity to shift. I think that there is a premium for
having your own control of that or the facilities in your footprint. So just wanted to note
that because we're all wrestling with this issue of how to combine different types of
resources into portfolios that perform the way you really need to meet load.
Clint Kalich: Yeah. And Fred, we've been looking at this and my belief is the utility is
much better served by a battery that isn't tied to a renewable resource because there's
going to be a lot of opportunity for periods when the battery isn't needed to balance
that resource. Solar, I mean at night for example, you could use it more broadly and
get extra value, but those are the questions that we're looking at. If you have a raw
wind energy resource versus something where you match it up with a small or a large
battery relative to the size of the very resource, what is that incremental cost?
Absolutely looking at that, that's important, back to that idea of finding the lowest cost
way of meeting customer needs. Those are exactly what James and friends are doing
on the IRP work.
Fred Heutte: Right. And the issue, as you mentioned, the issue of standalone
batteries versus hybrid combination, whatever you want to call that. Resources that
co-optimize at the point of interconnection, that's a whole other set of issues, because
batteries have a lot of capability and a lot of different places in the system. And you
know, I just foresee a future where we have kind of a shifting mixed bag of all of it,
which makes it hard to analyze. There's no question, but I think there's real value in

Appendix A
having that kind of diversity and figuring out from the modeling what that value is. And
you know, you might not ever be able to say here's the optimal mix of these different
kinds for variable energy resources and storage. And really, I would add demand
response to that, but at least you'd have a sense of where the good approximate
balance might be and that will help with resource acquisition.
Clint Kalich: That's exactly what we're trying to do. And of course you have to balance
that now with your diversity. There's less value to match these up uniquely with a wind
or a solar farm because you already have a lot of diversity. Again, back to the ADSS
model, we have the ability to model it tied to the specific asset and then we can look
at that scenario. We can also model it as something that is a portfolio wide asset that
can be used to optimize so that you get the full energy, I call it energy arbitrage on the
battery, but beyond that we should though be able to with another phase of this study
and that that's the one thing we've talked about. This was phase one. We should be
able to ask Energy Strategies to modify their models within the capability of these
storage assets to reduce the variability. If they can't do it, I know how to do it, it's just
a matter of staff time to be able to reduce the variability that these assets would see
and then we can see a commensurate reduction in the ancillary services that passes
through to much less integration cost. You could somewhat approximate it. You'll see
some examples from 400 to 2,500 megawatts. So, if you can go from 1,500 megawatts
down to a 400 MW equivalency of variability, you can see the integration costs come
down. I think you can interpolate, extrapolate, whatever you want, to use the data here
to get a feel for what the potential benefit might be and that I think is what's important
here today out of this study. We can do that and we have the models to do the specific
work we need to get some more data to run through the models. But I think we're
making some pretty good headway. We want consistent application to support various
analysis.
Clint Kalich: I talked about the IRP James is working on and he needs to account for
some of these costs when we go out and acquire resources, how the goal in an RFP
is to meet your various requirements, to serve load. And these days, to serve load
carbon free. But you also need to account for the different performances and so you
need to be able to find a way to get an apples-to-apples comparison. That's really what
the VERs study does. If you choose a solar resource, you might have $2.00 integration
cost; whereas, if you pick wind, it might be $1 .00. You need to be able to get these to
be closer to apples-to-apples.
Clint Kalich: Transmission. We actually have an interest in modifying our
transmission rate that we charge customers that that move wind and solar across our
facilities. Right now, there is no incremental charge associated with these costs in

Appendix A
order to support a change to your FERC tariff, you have to have a study like this in
place. So, one of the outcomes of this study will also be an opportunity to bring that
forward and be able to recover the costs that our customers right now are paying
incrementally for third party VER resources coming across our system. Finally, the last
piece is for PURPA in our avoided cost calculations. We need a way to differentiate
between say a seasonal hydro versus a biomass versus a waste coal plant versus
wind or solar. These numbers can be used to help set PURPA avoided cost and they
have been in the past and we hope to be able to use them in the future. In fact, in
Washington today we don't have any VER costs associated with PURPA because our
study wasn't fresh enough. The Commission was concerned that the study hadn't been
done more recently than 2007, so we didn't have a discount on wind or solar. This
study will help us to bring that into our PURPA published rates. We can for non-
published rates, negotiated rates we can include them, but for published rates the
Washington Commission wanted a new study. We're going to define the consumptive
capacity, so in the study we're identifying the capacity we need. Where is it coming
from? How much of its regulation? How much of it is load following? How much of it is
a forecast error? And then, what that cost is. That's really the purpose of this study, to
provide a consistent analysis, define what we need, and then define what the cost is,
and do that over these scenarios with increasing quantities of ancillary service mixes.
James Gall: Hey, Clint, before you move on, there's another question from Yao it's
will integration costs be applied to other resources such as hydro in addition to wind
and solar?
Clint Kalich: Yao, the thought there is those resources, they contribute to the system
value. So, we don't see those as having a system cost, they actually add system value
by providing ancillary services. For example, if I took Noxon out of our portfolio, you
would see the portfolio cost go up because that resource provides ancillary services
to the system. There wouldn't be in my view any need to do that work. You could, I
guess, argue that you might look at all of your resources incrementally like that and
determine how much value they provide to this system. But know that the existing
assets, we're not going to add big wind resources, but in the existing asset portfolio,
the value of those assets is already embedded in the system today. So there is no
thought of non-VER resource integration costs. If you bring a hydro project to us today
under PURPA, we don't anticipate we would discount or credit you for ancillary
services. In fact, most of the ancillary service value of our hydro wouldn't extend to a
PURPA anyway because they're not dispatchable. Flip side is they're fairly predictable,
so you don't have as much uncertainty around those. And this is the timeline for, and
James how are we doing and I'm cutting, I think we're done at 10. 1 don't know how
much time you want it on your part. This has taken quite a bit longer than I thought to

Appendix A
go through it. What are your thoughts there? Should I just burn through these or are
you going to postpone what you're doing?
James Gall: I'll probably postpone what I'm doing if we don't have time. I think this is
important and we have a lot of engagement. So, keep going.
Clint Kalich: OK. All right, so here was our original time frame to do this study.
This was a slide from the Energy Strategies update that we did last year. Actually, in
2022, I'm sorry, late in 2022. Clearly, we're doing the simulations now. We're basically
here today and then the study report, hopefully like I said, will be coming out in the
summer, certainly by the end of the year. Let's talk about, I apologize — it's a little bit
small here, but we looked at these different and the data is available in that slide
presentation that we have. We can get that to you, or these slides were made available
I think last week. But we looked at three VER portfolios. We looked at a full solar
portfolio, really these are for bookends. We looked at a full 100% wind and then we
looked at a 50/50 mix of wind and solar on a nameplate capacity basis. In the 400 MW
case, we would have 200 megawatts of wind and 200 megawatts of solar. And then
we looked at 4 VER penetration levels. We already have that 260ish megawatts today
comprised of Rattlesnake Flat Wind, Palouse Wind and Lind Solar, sometimes called
Solar Select. But we have three VERs today of significance. These are incremental
additions to that, and you can see here down below in this, it's very small numerically,
but it shows you basically in each case the locations that the resources were assumed
to land. Obviously, I've left diversity. If you have smaller integration but you can see
here over the various scenarios how much was being added and then you can see the
geography here of the Northwest that was assumed where these plants ran, and this
is out in Montana. This is farther out to the east the graph shows, but you can see here
some of the resources that we're looked at. Again, in the interest of time, I'll leave it at
that.
Clint Kalich: This is the data that was looked at here. The data for when we use the
NREL wind data set, which I think was available from 2007 through 2014. 1 might be
corrected here as we go forward. I might have the specific statistics and then we use
the NREL. It's the NREL solar data set here for the solar forecast and then Energy
Strategies using some of their capabilities, statistics and otherwise generated profiles
for these various portfolios that I showed on the previous slide. Then they showed
some pictures of the data, this is their slide on reserve services where it talks about
regulation reserves, load following, and forecast error. In the interest of time,
I'm not going to dive into the details here unless there's questions, but the idea is in
each one of the mixes of resources and incremental quantities of resources, Energy
Strategies looked at how that would impact these three categories and ancillary

Appendix A
services and gave us the incremental ancillary services necessary to serve those very
resources.
Clint Kalich: We wanted to spend a little time on the EIM. I mentioned earlier, all of
our resources are in a fairly small geographical footprint, but when you enter the EIM,
you get a lot of diversity savings. Actually in the work that Energy Strategies did, we
were assuming a 25% reduction in ancillary service requirements, but upon further
study and thought, we moved to the full 50%. Which if you look at what the EIM
forecast for wind and variability relative to what our system statistics are, it's about a
50% reduction. I'm a little concerned that might be an overstatement because once
we went to a larger, more diversified portfolio, I'm not sure we get a full 50% reduction.
Just the statistician in me thinks that, but in this study, we're going to assume the full
50% reduction in ancillary service requirements. Which is a big deal that makes a big
difference in this reserve studies. This is the statistics, sorry.
James Gall: Clint, Fred has question here.
Fred Heutte: Yeah, very quick one on your system now, what provides or pre-EIM
what provides the ancillary services, hydro and gas, or both.
Clint Kalich: Yeah, Fred. It depends on the ancillary services. I would argue most all
of our resources have something to contribute that we own and control. Even our Kettle
Falls biomass plant has some ability to do some load following, but substantially, I did
a study probably 10 years ago, because there was a lot of debate internally about
where we would follow this additional incremental load.
Fred Heutte: Right.
Clint Kalich: And my argument was that we would run out of Mid-C capacity. and we'd
be supplying it out of our Clark Fork. And internally there was a lot of debate, and
actually I had a lot of folks argue with me about that. But to me, the models didn't lie.
Actually, the study showed about 95% of the year after we brought Palouse in 2012,
a year after that, about I estimated 95% of the incremental ancillary services were
covered by Noxon. Now, in more recent years, we've seen the market get more volatile
and we've seen the gas plants start to play a larger load in providing ancillary services.
You will see Coyote now run a lot more variability within the hour to provide some of
the load following, and even some of the regulation will put it on AGC. I would say the
heavy hitters are Noxon and Coyote. Those are the two heavy hitters, but our entire
portfolio helps us with all the different needs we have.

Appendix A
Fred Heutte: Right. Thanks.
Clint Kalich: Yeah, because if we bring all these incremental obligations they come
into our larger system, we manage them together, not incrementally. It really is an
incremental, but this gives you a feel for and Energy Strategies did update this chart.
If you went to the workshop, you'd see larger bars. But based on the baseline up to
2,500 megawatts, these are the incremental, on average, the incremental ancillary
services we have to carry in megawatts up and down from the zero point. With 800
megawatts of diversified wind and solar, we need roughly call it 175 MW down and
well about 175 MW up in total capacity broken out between regulation slash AGC load
following and forecast error. And then you can see what the components are
incrementally.
Clint Kalich: On the study methodology, how do we do this? 2021 was a reasonably
average system, so we used 2021. We used the actual system conditions, including
forced outages, or hydro conditions and what fuel prices were in 2021. I'll try to jump
ahead of what your question might be, which is maybe why didn't you study more
years? This is a tremendously computationally expensive exercise, and even though
I use 2021, we did move market prices around, so we were able to look at different
market prices. Unlike the 2007 study, we didn't look at varying hydro conditions, so we
still assume average hydro even within a high market price condition here. And
actually, we've seen some of that. It seems like prices are driven more by natural gas
prices than they are driven necessarily by hydro. In some, there's a lot of mix in there.
We're running the system with and without the variable energy resources to look at
that incremental and I want to be careful here when I say with and without. In the with
case, we bring the VER resource in and all of its variability. In the without case, we still
are bringing the energy in because we aren't interested in trying to figure out the
arbitrage value, the actual energy commodity value that's already accounted for in the
RFP process. So, we bring that in as a 12 by 24. We bring in an average monthly
energy shape and we stick that into the without case, so it doesn't have any variability
associated with it, but the energy does come into the system. So, we're able to
calculate. We're not mixing into, and I call polluting, we're not polluting the variable
energy integration costs with the arbitrage value or the timing of when we get the
energy.
Clint Kalich: We're really bringing out and quantifying just the incremental integration
costs here. We're doing two conditions: with and without the VER we talked earlier.
There's actually five VER scenarios besides the existing condition. We have 400, 800,
1,500, and 2,500 megawatts of incremental VER. And then we look at those 3 mixes

Appendix A
and then we also look at three market conditions. You can see how this adds up to
lots of market runs. It's around 80 studies of 2021 with our system. Well, I guess it
came out to 90, so 90 different scenarios that we had to run. We ran the year 2021.
Every time we run this, or update it, we have to run 90 different studies of 2021 and
then we go calculate the delta between all these scenarios to determine the cost of
integration and the average cost in the incremental cost.
Clint Kalich: I'm going to show some data in a few slides here. We're moving the
commodity value, I guess I did carry a slide on this, so this is our without VER
scenarios. I already talked about the fact that we put the energy shape in the 12 by 24
energy shapes with no reserves and then the with VERs scenario. We put the whole
thing in just as it is expected to come from Energy Strategies in its raw case. By
subtracting the VER out, the without VER case from the VER case, we get to single
out the integration. I'm sorry, I should have covered this in the slide, not earlier when
didn't have the benefit of the slide, but we just want to get to the integration. Is that
clear? That's a pretty complicated concept. I remember when I first was introduced to
it back in the early 2000s by EnerNex, I had a little trouble consuming what all that
meant, but all again we're trying to do is we're not trying to value the timing of when
the energy comes or the fact that we've added a whole bunch of additional energy into
our system. What we want to model is just the variability and the capacity costs of
providing those incremental ancillary services. The energy in a non-VER case is the
same amount of average energy as the VER resource would provide in the VER case.
Probably made it worse by explaining that.
Clint Kalich: Let's talk about results. These are preliminary, so please, I assume Fred,
you're taking a screenshot, but please be aware that these will change modestly, but
you can see here and actually they have changed a little bit from the version that was
sent out in the draft. We hadn't completed the study yet and we've identified a few data
issues. There were substantial that I'm happy to talk with offline about that made an
impact on the incremental cost, but here's what we're expecting the cost today to be
with our existing portfolio. Base prices, $0.16 per kW month comes out to about $0.78
per MWh. That's quite a bit lower than the study that we came up with. I think I've got
a slide a little bit later on that to show what they were, but in fact let me jump ahead if
I've got it. I thought I had a slide. I want to go back to this. Well, I showed it earlier with
600 megawatts, almost $9 a MWh. We're talking here about just tremendously lower
costs. In fact, with 200 plus megawatts, we were about $7.00 a MWh and we're talking
here about being about $0.78. So, a huge reduction here associated with this study.
Associated with the existing portfolio. But then when you bring in a wind resource of
400 megawatts, you actually see that our integration costs drop to actually a penny of
savings per MWh. What that means is there's a tremendous amount of diversity in that

Appendix A
window resource relative to our existing portfolio and that's because we're assuming
a diversified resource of when in fact our next incremental quantity of wind that we
procured through an RFP driven substantially by the need for diversity will be
Clearwater Wind out of Montana. And you can see here, we actually expect this to be
a benefit to our portfolio and we go from an average $0.78 per MWh down to this is
again draft to roughly the integration cost dropping to zero. It's a huge benefit of having
that diversity. But then if you increase up to go from 400 to 800 megawatts of wind,
your average integration cost now as a $1.31 per MW hour and you can see it $2,500,
excuse me, 2,500 megawatts of wind, you're about $9 per MW hour of cost with high
market prices, it goes up, maybe 50%. Low market price is fairly similar. Cost depends
on the quantity. If you look at the solar case. Well, I thought it was interesting about
solar is in the low penetration quantities, solar actually has higher integration costs,
but when you get into these large diversities and Fred, I think this has exactly to do
with what you discussed, if you get a lot of because the solar facilities are smaller in
size and you get a tremendous diversity of solar, you actually see the integration costs
not go up nearly as aggressively as wind. I still think there's more work to be done
here. This still may be a little bit high, I don't know because that wasn't the absolute
focus of this study to look at small versus large wind farms. But this shows wind farms
are, excuse me, solar farms are smaller in size than wind farms, so that may be why
we're seeing some of this lower cost as we get to larger penetration relative to wind.
Some interesting results there. And then if you look at the diversified case. Let's look
at 800 megawatts, you're talking about $0.50 per MWh versus if you did all the wind,
it's $1.30. If you did all solar is $1.90, so these numbers, it's pretty interesting.
Clint Kalich: The diversity, what it does, it definitely shows the strategy we've been
pursuing for a number of years on acquisitions of trying to pick up more diversity, is it
pays off. If you can get a price that's competitive for the energy itself now, if we get a
bid from Montana, it's $10 more per MWh. The diversity benefit can't overcome that
$10 likely, but at least it does bias us towards getting more diversity. The other thing
to keep in note though is and the reason I started out with the dollar per MWh, that's
how we traditionally talked about it. But we actually model, we build these resources
on a per kW month basis because it really is based on their nameplate capacity. It's
not based on, this is 1,500 megawatts at nameplate, not of energy. So, these are the
right ways to look at it. If we're doing 800 megawatts of wind, we would actually want
to include in our RFP analysis $0.33 a kW month for integration cost associated with
that wind portfolio.
James Gall: Clint, I think Fred's got, somebody wants to add here.
Fred Heutte: Yeah. One more quick question. Just for comparison here, looking at

Appendix A
the dollars per MWh, the production cost for solar and wind is, I'm guessing
somewhere between $20 and $30. So when you start getting up to $6 to $8 bucks,
that does start to look like a pretty significant amount. If I'm getting that right.
Clint Kalich: Well, I'd love to be able to buy solar for $20, but irrespective it's $20 or
$40, it's definitely getting up to be a pretty substantial piece. I mean, you're really
starting to do some pretty perverse things to the rest of your portfolio to be able to
integrate that much variability and that really I think is the challenge before us, is if,
and keep in mind for this is doubling our system capacity, this isn't a, James and
were talking about this, we were questioning the value of even doing the analysis and
presenting 1,500 and 2,500 because we don't think this is something that's going to
happen in the next 10 years.
Fred Heutte: Right, it's not small.
Clint Kalich: Should we really even be studying this? And there is a possibility in the
final results of the study, we don't even provide this information. It may just be
considered too nosebleed to be doing, but yeah.
Fred Heutte: Well, I think it's interesting just as kind of a corner case or whatever. You
really Max things out and look, this is what happens. But I think what you're saying is
that the likely landing zone will not be at the high end.
Clint Kalich: Or we'll have batteries. We'll have a different market system, will have
batteries to go with it.
Fred Heutte: And then you have the right exactly.
Clint Kalich: We're not going to be able to just dump 2,500 megawatts of wind. We're
going to have to make other portfolio choices and bring those in to match up with that
window resource, so.
Fred Heutte: Right. And of course, there are other issues in terms of getting large
amounts of various transmission capacity and all that onto the grid.
Clint Kalich: Yes.
Fred Heutte: Alright. Thanks.
Clint Kalich: Yeah. And those types of things would be considered in the other

Appendix A
aspects of the RFP outside of the integration cost. I wouldn't define those as
integration costs. I mean, they are in a certain sense, but as far as the consumptive
capacity pieces that we're modeling here, they would be considered otherwise. And
then if you go to the next slide, here's the marginal cost associated with these different
resources. It probably makes sense for our next tranche of resources that we don't
charge the average. You probably should account for the fact the next 400 megawatts
of wind actually would probably discount. We probably should give that a credit
because they actually benefit our portfolio based on the results of this study. James
and I have been talking about whether we should use average or incremental and
maybe that's something folks want to talk about here today. We certainly will in the
wind, the VER workshop. But there's the marginal cost. We just wanted to look at those
incrementally here. Let's go to the next slide.
Clint Kalich: Next steps, obviously we need to finalize these results. We need to get
the report out and then we need to use it in our future IRPs or RFPs and get our
transmission tariff with FERC updated as well. Those are the next steps going on and
then, James put this slide together for the 2025 IRP, I mentioned that kW month
charge. I don't know if that's slide 18 anymore. It's actually slide 19 or 20. I'm not sure
which one we'll use. James can speak to these. More specifically, we're going to
increase the flex ramp requirement in our reliability modeling because in those cases
where we're adding a lot of new VERs to serve increased load over time, we will need
to account for the incremental reserves necessary to integrate the wind. It will have a
diversity, excuse me. Not a diversity, it will have a reliability impact because absent
the VER, that Noxon example, we'd have maybe an extra 10, 20 or 50 megawatts of
capacity to serve an extreme load. But if it's being consumed for a variable energy
resource, that may not be possible. And then we talked here about including a small
flexibility requirement as well in capacity expansion modeling. That's my slides,
James. I have given you a whole 8 or 18 minutes. If there aren't any other questions
anyway, so that's all I had, I think.
2025 IRP Market/Scenario Update (Draft), James Gall
James Gall: Any questions for Clint before we move on to the next presentation? Bear
with me one moment, I'm going to try to transition to the next slide deck. OK, hopefully
you guys see this. I'm probably going to go a little faster than I would like just because
we have about 18 minutes left. The purpose of this portion of the presentation is to
give you an update on where we're at on both market scenarios and our assumptions
on portfolio scenarios. We've also made some changes, and to finalize our price
forecast for the wholesale energy market. We've also finalized our load forecast and
we're providing some updates to those as well. They get started on the market side.

Appendix A
Just to remind everybody, we're looking at four different market price forecasts for this
IRP. There's obviously the expected case. We run a deterministic case, which Lori
Hermanson, presented a couple months ago, and we have just finished our stochastic
case. I think it finished up yesterday. That's 300 simulations of varying assumptions
on load and hydro, carbon prices and wind production, inflation, and several other
variables. We're also running the low hydro, or sorry low natural gas price case, high
natural gas price case, and another scenario where we do not have the Climate
Commitment Act in Washington. As many of you know, there is an initiative on the
November ballot to repeal that law, so we're running that case and in the event that
happens.
James Gall: On to the assumption side of things. For Henry Hub, here are the prices
that we're assuming in these different scenarios. The expected case is around $5 a
dekatherm levelized and then the low case we're at $3.86 and the high case $7.20.
The high case we're using the 95th percentile of the prices that we assumed in the
stochastic modeling and then the low case is the 25th percentile. We're trying to get a
broad understanding of where [market electric] prices would be in the event that our
gas assumptions are wrong so we can judge whether or not a resource that may be a
higher cost that's related to gas would have an impact in a different price scenario. For
example, when we look at potentially adding natural gas peakers in our portfolio, would
that still be the choice in the high gas price scenario. That's the value of these
sensitivities.
James Gall: Moving to electric prices, we do have preliminary results where
deterministic cases around $45.00 a MW hour, which is actually a couple dollars less
than the previous forecast that we shared a couple months ago. We've been going
through the model and making sure we got the model working properly with all the
correct assumptions. We did revise our forecast down, so it looks like, at least on the
deterministic case, we're on $45.00 and then the low-price case, that's shown in blue
comes in around $41 and then the high price case is $53. These are for prices that
are delivering at the Mid-C with Washington to delivery. As we discussed a couple
months ago with the CCA in place, it kind of complicates things. Whether or not there
is a delivery into the State of Washington, which could have a CCA allowance cost
versus prices that are traded at the Mid-C but not delivered in the state, which would
have a lower price without the allowances. We have two prices shown here. One is a
Mid-C delivery and then another price and the next slide. That's without a Washington
delivery. And then lastly, we did run a case without the CCA that does have a forward
$5 lower price approximately without CCA. I would say the reason why you don't see
a lot of variation here, maybe compared to some previous IRPs of years past, is that
the portfolio is extremely renewable. We're using basically the same portfolio of

Appendix A
resources across the region because regardless of if the CCA exists, or what prices
are of natural gas, the portfolios are getting more renewable and more energy storage
over the next 20 years. You're seeing here is that prices where natural gas really don't
have as much impact on the electric prices. The same thing goes for the CCA. If you
looked at our portfolio for the northwest, with and without CCA, and you kept that
portfolio design out in the future, you would see much greater variation in the results.
But because of the additional solar wind and storage, you don't see that variation.
Tom Pardee: James, just a question.
James Gall: All right, go ahead.
Tom Pardee: It is from Kevin. Does the price forecast include hourly pricing?
James Gall: Yes. This is a based on an 8,760 hourly price out 20 years and we run
300 of those. Actually, for the stochastic, but for these deterministic cases, it's the
expected hydro, expected load, and expected conditions on an hourly basis. If we
looked at on peak versus off peak prices, you would see definitely a difference in the
prices or even extreme peaks. On the non-delivery in Washington, prices are a little
bit less. It's a couple dollars spread, but again its kind of the same shape as we saw
before. OK. So that's that on prices. Again, we'll be using these to run sensitivities on
the portfolios that we have gone over. Actually, the last several TAC meetings that just
to test them, whether or not the portfolio would be better off with a different resource
in the event of some of these scenarios. Fred has got a question. Go ahead, Fred.
Fred Heutte: Yeah. Quick one. I realize we're running out of time here. On the gas
price forecast, I wonder if you're looking at or including any assessment of what will
happen to regional prices when the new LNG Canada export facility goes online, which
is probably the end of this year. Now I realize that this mostly does not come from
British Columbia, but still, that's a 2 billion cubic feet a day resource facility that's going
into operation. Total gas production in the Western Canada Sedimentary based, BC
and Alberta together, is about 17 BCF right now. I'm just wondering if you're looking
at that and if you have any observations on what that might mean for prices?
Tom Pardee: Yeah, Fred, good question. This is Tom. What I understand of the
project is that our own production up in the Montney and they have their own dedicated
pipeline to the facility. But to directly address your question, the price is considering
that this is a blend based on the presentation a couple two or three TACs ago, but they
would have, I mean, it's a global look as how they do the modeling and knowing that
Canada LNG camp was coming on, that would be included in the price forecasts.

Appendix A
Fred Heutte: OK. Thanks.
Tom Pardee: Good. And just a quick recap on how these prices are developed, we
do a blend between forward prices, the EIA long term price forecast and then two
consultant long term price forecasts that are blended together to create that black line
in the middle. And then we've looked at historical volatility and forward prices to come
up with how those prices may vary over time. And then the high and low case is the
statistical result of those forecasts.
James Gall: OK, we got about 10 minutes and I have about 3 hours of material left
that I'm going to try to reduce down to 10 minutes. But, if there are questions, we don't
get too today, we can always push some of this out to the next TAC and we are doing
this every two weeks. So, that's possible if we get stuck in the next 10 minutes. First,
on the load forecast, we had AEG conduct an end use load forecast for us and they
did a presentation on that about a month ago. Two weeks ago, they did a presentation
on our energy efficiency forecast. Since that time, we've been working with them to
finalize the load forecast and there's been actually quite a bit of revision since then.
One of the big changes has to do with the water heater requirement for basically a
heat pump water heater I believe by 2030 in the federal standard. That was a major
reduction in our load forecast and then also another change was they were
implementing some price elasticity into the load forecast as well. At the end of the day,
what you're going to see here is a much lower forecast than we presented about a
month ago as we've been going through the data that AEG has provided us. One of
the benefits of using an end use forecast is we can see the load changes that we
expect between now and 2045.
James Gall: And this is an interesting couple charts of where the load is reducing and
where the load is increasing by end use. On the left we have several different
categories of end uses and obviously the negative ones are ones that we expect loads
to reduce over the next 20 years. Areas where loads are expected to increase.
Obviously electric vehicles is the largest increasing amount of load generation, which
interesting on this one. It shows up as positive, but it's actually a reduction, which is it
reducing load. But that's the second largest growing area. Then you have electronics,
refrigeration, appliances, space heating are rolling off the top increasers. Decreasing
a lot of it is lighting, ventilation processing, mostly on the industrial side. Water heating,
which I mentioned before, is also on that list of reduction from a low point of view.
Percentages may not matter when they're a small amount, but when you look at total
load changes, lighting is the biggest reducer. Same with generation. That's mostly
solar generation, motors and ventilation, but you can see that load growth is really

Appendix A
coming from electric vehicles, space heating, because we do expect quite a bit of
electrification in the next 20 years, but also electronics, appliances, refrigeration and
a little bit from cooling as well. But it's definitely an interesting way to look at how loads
are going to change over the future.
James Gall: Now that we actually have an end use look at the system. OK, so what
is that? Where do we come out from a load forecast point of view? I believe we were
at 1.5% energy growth and the previous TAC meetings and then we're now down to
about 0.81%. How this slide works is in yellow or orange is our actual energy we've
witnessed in the last 9 plus years. And then in Orange is the load forecast that Grant
had presented to us at that TAC meeting. And then the black solid line represents what
our final load forecast is. We are moving our load forecast a little bit higher in the short
run compared to Grant's forecast due to a large industrial load that's going to be on
our system starting in August and then we expect loads to continue to flatline and then
slowly increase in the 2030s, and then goes up quite a bit higher as the electric vehicle
forecast kind of kicks in. As far as the state level look in blue is Washington, and in red
is Idaho, where Washington is expecting higher load growth from the electric vehicle
sector and a little bit on the electrification sector. Idaho is staying more flat because
we expect less EVs in Idaho and less electrification as well. The codes and standard
changes that are expected from the federal level to have more of an offset in Idaho
compared to Washington because there's just not as many loads taking over and the
dotted lines represent the last IRP's forecast from 2023. A little bit higher loads on a
system basis than the last IRP, mostly driven from Washington. I'd say the two biggest
drivers of that is the higher electric vehicle forecast and a little bit more electrification
than the previous forecast.
James Gall: OK, I'm moving to peak. We also have some revisions there as well.
We've also tried to make it a little bit easier to understand on how we look at peaks,
because peak is kind of a difficult thing to look at because when you look at history,
you could have a peak that shows up in January, November, even March from a winter
point of view. In the summer, peaks are most likely going to be in either late June, July
or August. On the historical side of this, we have a seasonal peak, blue is winter, red
is summer. Showing on the right is in the solid lines. Our forecasted peak, we call them
a seasonal peak, which could be the highest event in the winter and in the summer.
You can see that our peak forecast is a little bit less for winter compared to our event
we had in January and that's because we're forecasting we would call it one in two
event versus in last January was a, we'll call it an extreme event. I'm where we actually
had a planning margin to our loads to cover that variability.

Appendix A
James Gall: In the dotted lines that are shown in there are the monthly peaks. When
we look at planning in the IRP, we look at a monthly peak level of January, February,
etcetera and that's what our model plans to. But we add a planning margin to cover
that and that planning margin that we add is intended to cover that seasonal peak as
well as other outages or extreme events. So, we want to include the dotted line in there
to give you a reference of what the January and the August peaks are. But we do
acknowledge there is, from a seasonal perspective, a much higher peak so that when
we compare history to forecasts, it's more relative. The biggest takeaway, though, is
compared to our last IRP, we have significantly higher peaks expected and that's really
driven by one, we have a new industrial load, but two, we actually had two significant
events both winter and the last year. That's really helped us reset our data because
when you don't have, especially in the winter, a significant peak event without that
data. What you're looking at is going to it's going to be reflective of the past historical
data. So, if you don't have a peak event in your data set, that's recent, you're going to
underestimate what you expect peaks will be in the future.
James Gall: We have got about 2 minutes left. I think I'm going to stop there, and we'll
get into portfolio scenarios at the next TAC meeting because I think this is going to be
a little bit more detail than I can cover in 2 minutes. I can't talk specifically on
electrification, so we wanted to cover what we're looking at from our electrification
scenarios. I think that deserves definitely more time than two minutes.
I'm going to stop there. Grant has a comment. Go ahead, Grant.
Grant Forsyth: Yep. Thank you. So just real quick though about the peak load
forecast too. I would just throw out that there was an adjustment. Now there I put in an
adjustment. Now in the peak load forecast, uh for a post pandemic change too,
because of the hybrid work environment that seems to have pushed up people out a
bit as well.
James Gall: Thank you. Anything else? We have one minute left. If there are no other
questions, we'll see you in two weeks, but I'll leave the mic open for any questions.
Try to answer comment could be come back to the issue of new industrial load and for
future work job. Do you have something in mind, what you want to know?
Fred Heutte: Yeah, my thought there is that everybody is all a big uproar about this
and there's a lot going on with new data centers, and actually a lot of other types of
industrial load. You've got a pretty good area for that kind of development, and I think,
Spokane is a big high-tech center and you've got a good system. I'm just wondering if
you're seeing any potential for significant new industrial load. And like I said, maybe
this is something to bring up later.

Appendix A
James Gall: Yeah. We are going to run a scenario. I believe it's 100 megawatts in
2030. We're going to run that scenario, the industrial load we just picked up was an
existing customer that was, I wouldn't call it there an existing load that was not our
customer. They moved their load to us, but we are consistent on a data center coming,
which is why we're going to be running that 100-megawatt scenario. Another scenario
want to talk about briefly today, but we didn't get to, is the decarbonization efforts for
central systems that are owned by the state and that could create a significant large
load as well, especially universities. That's another scenario we could probably cover
as well.
Fred Heutte: Thanks.
James Gall: Alright, we'll see you in two weeks. Have a great week and we'll see you
later.
Charlee Thompson: Thank you.
James Gall stopped transcription.

A endix A
I ,1
IF
2025 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 8 Agenda
Tuesday, June 4, 2024
Virtual Meeting — 8:30 am to 10:00 am PTZ
Topic Staff
Introductions John Lyons
Electrification Scenarios James Gall
New Resources Options Costs and Assumptions Michael Brutocao
2030 Loss of Load Probability Study Mike Hermanson
Load & Resource Balance and Methodology Lori Hermanson
(Moved to TAC 9)

���r r/ISTA
2025 IRP TAC 8 Introductions
John Lyons, Ph.D.
Technical Advisory Committee Meeting No. 8
June 4, 2024

Appendix A
Today's Agenda
Introductions, John Lyons
Electrification Scenarios, James Gall
New Resources Options Costs and Assumptions, Michael Brutocao
2030 Loss of Load Probability Study, Mike Hermanson
Load & Resource Balance and Methodology, Lori Hermanson
(Will be covered in TAC 9 meeting)
2

Appendix A
Remaining 2025 Electric IRP TAC Schedule
• TAC 9: June 18, 2024: 8:30 to 10:00 (PTZ)
o Load & Resource Balance and Methodology
o IRP Generation Option Transmission Planning Studies
o Distribution System Planning within the IRP & DPAG update
• Technical Modeling Workshop: June 25, 2024: 9:00 am to 12:OOpm (PTZ)
o PRiSM Model Tour
o ARAM Model Tour
o New Resource Cost Model
• TAC 10: July 16, 2024: 8:30 to 10:00 (PTZ)
o Preferred Resource Strategy Results
o Washington Customer Benefit Indicator Impacts
o Resiliency Metrics
• TAC 11 : July 30, 2024: 8:30 to 10:00 (PTZ)
o Preferred Resource Strategy Results
o Portfolio Scenario Analysis
o LOLP Study Results

Appendix A
Remaining 2025 Electric IRP TAC Schedule
• TAC 12: August 13, 2024: 8:30 to 10:00 (PTZ)
o Preferred Resource Strategy Results (continued)
o Portfolio Scenario Analysis (continued)
o LOLP Study Results (continued)
o QF Avoided Cost
• September 2, 2024- Draft IRP Released to TAC.
• Virtual Public Meeting- Natural Gas & Electric IRP (September 2024)
o Recorded presentation
o Daytime comment and question session (12pm to 1 pm- PST)
o Evening comment and question session (6pm to 7pm- PST)

���r r/ISTA
,V
2025 IRP Portfolio cenario Update (DRAFT
James Gall
Technical Advisory Committee Meeting No. 8
June 4, 2024

Appendix A
High Electric Transportation Scenario
450
—2025 IRP EV Forecast
400 _2025 IRP EV High Scenario
350 ——— 2023 IRP EV Forecast
——— 2023 IRP EV High Scenario I♦
300
I
250 ♦I
200 �♦
150 40 do do do
100 to����
��� so OvOvOv�
50 �d� ���Ow
S do 0, 40600000
do to
CO f1— 00 0') O T— N CO Iql- LO C0 f` 00 0') O N CO It LO
N N N N CO CO M CO CO CO CO CO CO CO Iql- 1:31 It It 1:11 It
O O O O O O O O O O O O O O O O O O O O
2

Appendix A
State Electric Vehicle Load Projections
Idaho Washington
300 300
Idaho-Expected Case Washington- Expected Case
250 Idaho-High Scenario 250 Washington-High Scenario
200 200
150 150
100 100
50 50
0 0
(0 r-- 00 O O N M 't (!) (O r-- 00 6) O N M (f) (0 r- 00 O O N CO 't (P) (O r— 00 O O N M "t (P)
N N N N CO M M M M M M M M M N It I Izi- N N N N M M CO M M M M M M M It 11 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
3

Appendix A
Space Heat Assumptions for Building Electrification
Space Heating Efficiency Curve
4.00
3.50 ""� For homes with central
heating, the homeowner
3.00 •' may find efficiency, cost,
equipment longevity
2.50 challenges when
••`.�•''� Heat Pump Lockout Point for Gas Coupled Systems w/o retrofitting to fully electric
•
a ''i••' oversized equipment due to increased duct
O 2.00
V �•••••••• .•j sizing requirements and
�''•• installation cost.
1.50 �••''•••�
Retrofit HP on NG
1.00 - — — • Net Efficiency furnace may have similar
♦ Heat Pump Compressor
outcomes
0.50 -4- ••••••••• Poly. (Net Efficiency)
Poly. (Heat Pump Compressor)
0 10 20 30 40 50 60 70
Temperture (F)
NREL Study of Actual Systems in the Northwest
4 Field Validation of Air-Source Heat Pumps for Cold Climates
https://www.nrel.gov/docs/fy23osti/84745.pdf

Appendix A
Building Electrification Electric Impacts
80% Reduction in WA/ID System Natural Gas Usage by 2045
500
450 Load Forecast Impact (Energy)
Assumes 75% of WA
400 and 90% of ID
350 natural gas
300 customers use Avista
2 250 electric
200 Load impact is close
150 to even between
100 states
50
2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
■Annual Energy - - 10 20 30 41 51 62 74 85 97 109 122 135 147 162 176 190 204 221
■January Energy - L
20 42 63 86 109 132 156 180 205 230 256 283 311 339 368 397 427 458
■August Energy - 2 4 6 8 11 13 16 18 21 23 26 29 32 35 37 40 43 46
5

Appendix A
Load Forecast Comparison
January Peak Forecast
3,500
3,000
w 2,500
M
3
M
2,000
1,500
1,000 Expected Case
Energy Forecast 80%Washington Building Electrification by 2045
3,500 500 80%Washington Building Electrification by 2045&High Transportation Electrification Scenario
Expected Case Extreme Building/Transportation Electrification for Washington& Idaho w/o new Natural Gas CTs
80%Washington Building Electrification by 2045 0
3,000 f0 I-- 00 M O — N M Iq to t0 I-- CO O O — N M � O
80%Washington Building Electrification by 2045&High Transportation Electrification Scenario 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Extreme Building/Transportation Electrification for Washington& Idaho w/o new Natural Gas CTs N N N N N N N N N N N N N N N N N N N N
y 2,500
3
m 2,000
a�
1,500
L
Q 1,000
500
0
to 1­ OD M O r N M q In W I.- M M O r N M qr In
6 N N N N M M M M M M M M M M 'Cr le le le le 'CrCDCDCD CDO CD O CD CD CD CD CD CDO CD CD CD CD CDN N N N N N N N N N N N N N N N N N N N

Appendix A
Load Forecast Scenarios Still Under Development
• Load forecast data will be posted on Teams site once finalized
• Remaining scenario update:
— Maximum Washington Customer Benefits: EV/Solar penetration to be increased in Named Communities
— Data Center in 2030: Assume 200 MW in Idaho service area
— RCP 8.5 Weather: in process
— Low Growth: see assumptions below
— High Growth: see assumptions below
— Campus Building EIectrifications: Should this be a scenario or added to existing scenario?
• 30 MW to 60 MW winter load
Load Forecast Economic Conditions
Expected Low •
Case Growth Growth
Scenario Scenario
2045 Area Population 941,587 857,869 11001,564
Avg. GDP 1.80% 1.26% 2.26%
7

Appendix A
Supply Side Resource Options
2025 Electric IRP, 8t" Technical Advisory Committee Meeting
June 4, 2024

Overview and Considerations Appendix
• IRP supply-side resources are near commercially available technologies with potential for development within
or near Avista's service territory.
• Resource costs vary depending on location, equipment, fuel prices and ownership; while IRPs use point
estimates, actual costs will be different.
• Certain resources will be modeled as purchase power agreements (PPA) while others will be modeled as
Avista "owned". These assumptions do not mean they are the only means of resource acquisition.
• No transmission or interconnection costs are included at this time.
• Interconnect included for off-system resources.
• An Excel file will be distributed with all resources, assumptions and cost calculations for TAC members to
review and provide feedback.
2
DRAFT AdiiLr1f1STA

IRA Details Appendix
• Production Tax Credits ($2022 USD)
— Geothermal, Solar, Wind and Biomass
— $0.026 per kWh tax credit
— Nuclear
— $0.015 per kWh tax credit plus $0.003 base credit ($0.018 total per kWh credit)
• Investment Tax Credit (Battery Storage, Pumped Hydro, Solar)
— Costs incurred thru 2032 qualify for a 30% tax credit
— Credit falls to 26% in 2033, 22% in 2034, 10% in 2035/2036, and 0% in 2037
— Additional 10% low-income tax credit
— Domestic production adder of 10%
DRAFT ,r,4'7V15TA

Resources Not Modeled Appendix A
• Carbon Sequestration
• Coal
• RNG except as fuel for Frame CT
• Sodium , Vanadium , and Zinc Bromide Batteries
• Wave
4
DRAFT r,4171VIsra

Resources Modeled Appendix A
Resource Fuel Source Mw Capacity Factor Capital $/IQU=6)
Frame CT Natural Gas 180 $831
Frame CT Ammonia 90 $1 ,079
Frame CT RNG 90 $831
Reciprocating Engine Natural Gas 185 $1 ,272
Combined Cycle Natural Gas 312 $1,271
Small Nuclear Modular Reactor Uranium 100 93% $8,224
Wind (On System) Wind 100 35% $1 ,500
Wind (Off System) Wind 100 35% $1 ,642
Wind (Montana) Wind 100 42% $1 ,582
Wind (Off Shore/System) Wind 100 49% $5,220
Geothermal (Off System) Earth 20 90% $5,139
Hydrogen Fuel Cell Hydrogen 25 $6,703
Kettle Falls 2nd Biomass Unit Wood Waste 58 50% $5,308
Kettle Falls Upgrade Wood Waste 11 60% $2,864
Rathdrum CT 2055 Uprates two unit operation Natural Gas 5 $925
Rathdrum CT: Inlet Evaporation 2 unit operation Natural Gas 10 $167
Palouse Repower Wind 120 36% $1,200
Rattlesnake Repower Wind 180 27% $1 ,200
Lind Repower Solar 25 24% $11114
5
DRAFT c'.,Irvfffsra

Resources Modeled (continued) Appendix
CapacityFuel Source MW MWh . . . .
Residential PV(New Construction) Solar 0.006 16% $3,810
Residential PV Solar 0.006 16% $4,141
Commercial PV Solar 1 17% $2,297
Low-Income Community PV Solar <1 30% $369
Utility PV(Fixed) Solar 5 30% $1,845
Utility PV(Single Axis Tracking) Solar 100 30% $1,392
Utility PV(Single Axis Tracking, Southern NW) Solar 100 32% $1,392
Distribution Scale Lithium-ion 5 20 $2,195
Distribution Scale Lithium-ion M& $3,934
Lithium-ion 25 100 $1,663
Lithium-ion 25 200 $2,979
Lithium-ion 25 400 $5,613
Flow 25 100 $1,317
Flow 25 200 $1,383
Iron Oxide 100 10,000 $2,574
Pumped Hydro Water 400 3,200 $4,070
Pumped Hydro Water 100 1,600 $3,655
Pumped Hydro Water 100 2,400 $3,384
DRAFT

Solar PPA Price/implied EnergyPayment AppendixA
$350
$300
$250
$200
$150
$100
$50
2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
Residential PV(New Construction) Residential PV Commercial PV
Low-Income Community PV — Utility PV(Fixed) Utility PV(Single Axis Tracking)
Utility PV(Single Axis Tracking, Southern NW)
*Community PV does not include administrative costs (—$25/kW-year)
7
DRAFT C043hIfISTA

Wind PPA Price/implied EnergyPayment AppendixA
$200
$180
$160
$140
$120
75 $100
$80
I
$60
$40
$20
2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
On System Off System — Montana Off Shore/System
s
DRAFT

Baseload Clean Energy Appendix A
$250
$200
$150
75
$100
$50
$-
2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
Small Nuclear Modular Reactor - Geothermal (Off System)
9
A"i'i VISTA

EnergyStorage PPA Price/implied Capacity Paymenf pendix A
$800
$700
$600 --------
L $500
a�
$400 — — —
$300
i
$200
$100
$-
2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
Distribution Scale 4hr Lithium-ion— — Distribution Scale 8hr Lithium-ion 4hr Lithium-ion
8hr Lithium-ion 16hr Lithium-ion - 4 hr Flow Battery
8 hr Flow Battery 100hr Iron Oxide Pumped Hydro (8 hr)
Pumped Hydro (16 hr) Pumped Hydro (24 hr)
10
DRAFT A041VISTA

Dispatchable Resource Variable vs Fixed CostAppendix A
Framt CT(RNG)
300
Frame CT (Ammonia)
200
c i 150 Hydrogen Fuel Cell
Rathdrum CT: Inlet • 4
n
m Evaporation Two Reciprocating Engine • ;
> 100 Unit OperationPPP
• :
1
` l T •���••••• ' ' ' '
r
Kettle Falls Upgrade Kette Falls 2nd Biomass Unit
Frame CT(Natural Gas) Combined Cycle
0 ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
` Rathdrum CT: 2055 Uprates Two Unit Operation
0 160 200 300 400 500 600 700 800 900 1,000 1.100 1,200 1,300 1.400 1,500 1.600 1.700
Fixed Cost$per kW-year at Busbar
Resources with lighter and darker shades indicate costs in Washington and Idaho, respectively
11
D RAF1 ,CdiiI f1.5TA

NEI Cost Studies to be Added Appendix
• Avista obtained licenses to run the IMPLAN model for Washington and
Oregon to be able to run our own economic impact studies for each of the
new resource types
• Still learning and configuring the model as this time and will report back to
the TAC as the studies are completed
Upstream emissions estimates
Estimated direct, indirect and induced jobs for construction and operations
Reviewing additional outputs of the IMPLAN model for possible inclusion in the IRP
12
DRAFT A'-iiLr1fffsra

���r r/ISTA
2030 Loss of Load Probability Study (DRAFT
Mike Hermanson
Technical Advisory Committee Meeting No. 8
June 4, 2024

"`F.gRAFT
Topics
• LOLP Purpose
• Study Methodology
• Reliability Metrics
• Results
• Planning Margin

"`f7RAFT
Purpose of Loss of Load Stu ". r
• Determine the ability of our system to meet load and reserves each hour
when subjected to 1 ,000 iterations with different combinations of:
— Water years
— Load
— Temperature
— Maintenance
— Forced outages
— VER production
• Utilized currently expected portfolio of resources in 2030 and availability to
purchase up to 330 MW from the market.
• Climate data utilized for water, load, and temperature in future years.
3

AURAFT
Modeling Framework
• Avista Reliability Assessment Model (ARAM) - Excel based model with VBA code and
linear optimization Excel Add-in What's Best!
Renewable generation based on
wind speed that is random
Run of river generation number that is auto correlated
based on hydro year and influenced by temperature
Non-Dispatchable Hydro generation R- . • generation C•
Generation — Run of River capacity an• profile
Model output:
All resources subject to 8760 for each iteration for
availability logic that Linear optimization to solve for load loss events and/or not
randomly assigns outages Reserves .. • least cost way to serve load on meeting spin or non-spin
based on assigned ...............an hourly basis reserve requirements
probability of occurrence
Dispatchable Hydro generation Thermal - -
Generation - generation
Storage hydro dispatched Thermals dispatched against Market price is estimated based
market based on heat rate, on regression dependent on
based on hydro year, market fuel rice and load. Ca acit month, day of the week, hour,
price, load, and storage and p p y
flow constraints is dependent on daily hydro conditions and load
temperature
4

AAFT
Reliability Metrics
• Studies are conducted with 1 ,000 iterations of the ARAM Model
• Model metrics provide insights and targets to achieve a reliable system
• Metrics
- LOLP — Loss of Load Probability: Calculated by counting the number of iterations where there is unserved load or unmet
reserves and dividing by the total number of iterations.
LOLE — Loss of Load Expectation: Calculated by counting the days where there is unserved load or unmet reserves and
dividing by the total number of iterations.
LOLEV — Loss of Load Expected Events: Calculated by counting the number of consecutive blocks of unserved load or
unmet reserves and dividing by the number of iterations.
LOLL ' — Loss of Load Hours: Calculated by summing the number of hours with unserved load or unmet reserves and
dividing by the total number of iterations.
EUE — Expected Unserved Energy: Calculated by summing all of the unserved MWhs over the study period and dividing
by the number of iterations. Two versions are presented one with unmet reserves and one without.
5

Reliability Metrics AFT
LOLP Can be used to determine the probability or likelihood of
events due to insufficient capacity.
LOLE The majority of entities conducting LOLE studies
primarily use it to establish resource adequacy criteria.
Industry standard is 0. 1 days per year LOLE.
LOLH The LOLH metric is computed by a large number of
entities in North America. However, only one entity uses
this metric as a reliability criterion, with their criterion set
a 2.4 hours per year.
LOLEV The LOLEV metric is useful in systems that are
concerned with the frequency of events, regardless of
duration or magnitude.
EUE EUE is useful in estimating the size of the loss of load
events so planners can estimate the cost and impact of
the loss of load events.
Note: information taken from NERC, Probabilistic Adequacy and Measures Report, July 2018
6

A DRAFT
2030 Existing Portfolio
12x24 Resource Deficiency
• The following chart presents the sum of the hourly average of loss of load
over 1 ,000 iterations by month and hour in MWhs:
Hour
2030 No Additional Resources
Month 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
1 10.2 11.5 13.2 14.6 15.4 20.2 31.7 39.4 32.0 28.9 25.9 22.1 20.1 14.3 16.5 14.8 17.3 17.8 18.8 19.2 19.5 17.6 14.2 12.8
2 2.4 3.2 4.3 5.8 6.9 10.0 12.2 15.8 11.0 8.8 6.3 5.5 3.9 2.3 2.4 3.2 3.6 4.0 5.6 5.5 6.7 6.5 6.1 6.1
3 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 0.0 0.0 0.0
4 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 0.0 0.0 0.0
5 0.0 0.0 0.01 0.0 0.01 0.0 0.01 0.0 0.01 0.01 0.0 0.01 0.0 0.01 0.0 0.01 0.0 0.01 0.0 0.01 0.0 0.01 0.0 0.0
6 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 0.0 0.0 0.0
7 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 0.3 0.9 1.3 0.8 0.1 0.0 0.0 0.0 0.0
8 0.0 0.01 0.0 0.01 0.0 0.01 0.0 0.01 0.0 0.0 0.0 0.0 0.0 0.01 0.0 0.31 0.6 1.2 0.6 0.11 0.0 0.01 0.0 0.0
9 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.01 0.0 0.01 0.0 0.0 0.0 0.0 0.0 0.0 0.01 0.0 0.0 0.0 0.0 0.0 0.0
10 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 0.0 0.0 0.0
11 0.1 0.1 0.1 0.11 0.1 0.1 0.4 0.1 0.2 0.4 0.3 0.1 0.0 0.11 0.11 0.2 0.3 0.0 0.3 0.01 0.3 0.2 0.31 0.1
12 9.1 8.1 9.012.714.119.827.129.528.329.023.421.219.114.815.916.018.020.320.622.821.222.719.115.E

AURAFT
Summary of metrics
• Planning margin determined by running model with increasing values of
additional dispatchable resource
Additional ' • ' e Resources LOLP — Loss of Load Probability
LOLE — Loss of Load Expectation
LOLH — Loss of Load Hours
LOLEV— Loss of Load Expected Events
LOLP 13% 10.4% 7.6% 5.2% 4 20/ 5.0% EUE — Expected Unserved Energy
LOLE 0.44 0.32 0.24 0.16 0.11
LOLH 4.98 3.66 2.48 1.71 1.12
LOLEV 0.98 0.83 0.62 0.48 0.32
EUE (with reserves) 1084 783 520 340 203
EUE (without reserves) 1066 768 511 334 199
Implied Planning Margin 21.0% 23.8% 26.6% 29.3% 32.1%
• Interpolated model runs to calculate 167 MW to achieve a 5.0% LOLP
• Consider (evaluate) moving winter planning margin from 22% to 30%

Appendix A
Avista 2025 Electric IRP
TAC 8 Meeting Notes
June 4, 2024 8:30 to 10:30 am PTZ
Attendees:
Sofya Atitsogbe, UTC; John Barber, Customer; Kim Boynton, Avista; Molly Brewer, UTC;
Kate Brouns, Renewable Northwest; Michael Brutocao, Avista; Logan Callen, City of
Spokane; Katie Chamberlain, Renewable Northwest; Josie Cummings, Avista; Kelly
Dengel, Avista; Mike Dillon, Avista; Jean Marie Dreyer, Public Counsel; Michael Eldred,
IPUC; Rendall Farley, Avista; Ryan Finesilver, Avista; Grant Forsyth, Avista; James Gall,
Avista; Bill Garry, Customer; Konstantine Geranios, UTC; Amanda Ghering, Avista;
Michael Gump, Avista; Leona Haley, Avista; Tom Handy, Whitman County Commission;
Lori Hermanson, Avista; Mike Hermanson, Avista; Fred Heutte, NW Energy Coalition;
Kevin Holland, Avista; Joanna Huang, UTC; Clint Kalich, Avista; Scott Kinney, Avista;
Seungjae Lee, IPUC; Dan Lively, Clearwater Paper; Kimberly Loskot, IPUC; Mike Louis,
IPUC; John Lyons, Avista; Patrick Maher, Avista; Jaime Majure, Avista; Ian McGetrick,
Idaho Power; Tomas Morrissey, NW Power & Conservation Council; Austin Oglesby,
Avista; Michael Ott, IPUC; Tom Pardee, Avista; Meghan Pinch, Avista; John Rothlin,
Avista; John Slagboom, WSU; Dean Spratt, Avista; Victoria Stephens, IPUC; Lisa Stites,
Grant County PUD; Jason Talford, IPUC; Charlee Thompson, NW Energy Coalition; Yao
Yin, IPUC.
Introduction, John Lyons
James Gall: We're going to do that right now.
John Lyons: And as a reminder, if you have a question, either use the raise hand function
or bring it up in the chat and we've got a couple people here in the room watching for
those. If we don't get to you right away, we're just waiting for a good pause on that. But
we will get to those. Anything else you'd like to add, James.
James Gall: I just want to cover what's coming up next. Like they see, the next meeting
is June 18t" and at that meeting we're going to cover transmission and distribution
planning. And then on the 25t" of June, we'll cover our technical models. That's I guess
an optional meeting for those that want to dive into the models a little bit more deeply,
we're going to cover the PRiSM model, the ARAM model, and then the resource cost
model that's actually being discussed today. It's the model that was used to come up with
the costs that Michael is going to cover later and then July 16t" will be the pinnacle of the
IRP process where we're going to share our Preferred Resource Strategy results and
then we'll continue that process over the summer before we file our draft IRP on
September 1st. So, with that, I guess we'll get started. Unless there's anything else.

Appendix A
John Lyons: Yeah, I think we're good, James.
Electrification Scenarios, James Gall
James Gall: You might get any questions before we get started. I'll find my presentation
and we'll get going, right? Give me a second. I'm on one screen today and it makes it
hard to find everything.
James Gall: OK, I think our last TAC meeting, we left off on trying to go through the
different scenarios we're going to be covering and electrification was where we left off last
time we covered, I believe it was the updated load forecast, and this time we wanted to
share the scenarios that we were planning on conducting with that load forecast with
electrification to get started. Let's go to the next slide.
James Gall: The first one I wanted to cover is our high electric transportation scenario.
In this scenario, we wanted to take a look at the high case of what customers may do to
electrify vehicles. Our base case, that's shown in the dotted red line put together for our
IRP study is our base assumption that has a significant amount of commercial vehicles
and a significant amount of residential vehicles. Light duty vehicles, compared to our last
IRP, which is shown in the dotted black line. And in that case that we're assuming for our
current base case is actually higher than our high case in the 2023 IRP showing in the
dark black line. But we want to make sure this IRP covered, I wouldn't call it a worst case
scenario, or maybe call it the best case scenario for electrification where we tried to look
at trying to get what happens if almost all vehicles as compared to today electrified by
2045 in both states. What does that mean? It means about 1.1 million vehicles would be
electrified by 2045. In this high case assumption, in that dark red line, we also wanted to
make that look like more of an S curve growth pattern to show what happens if customers
adopt electrification much faster than we assumed in the base case. You can see that
curve grows much quicker and then flattens out about the 2040 period. It's about 400
aMW in total for this case.
James Gall: And if we move to the next slide, this shows you what it looks like between
the two states. And on Idaho, it's a significant increase for this scenario because our base
case doesn't assume a lot of electrification in the Idaho Service territory. Most of the
growth, at least compared to the base case, is much higher than the Idaho case on the
Washington side, while it is higher than our expected case, it's really moving that load
growth faster in the earlier years and then flattening off. That's what our high case it's
going to be for the for electrification of transportation. Definitely welcome comments or
thoughts on this if you have any. I'm going to pause there if there's any thoughts or
comments? OK.
James Gall: And what we're going to kind of cover, back to this when we wrap this up
with the other scenarios, and then I'm going to move to building electrification and building
electrification. It comes down to how heat pump technology works, and really there's two

Appendix A
types of appliances we're talking about. For the majority of building electrification, one is
water heating, and the other one is space heating. Space heating is really what I want to
talk about today. Water heating is a little bit more simplified because you're converting
natural gas water heaters to likely a heat pump water heater. That changeover is a little
bit less controversial compared to space heating. On the space heating side, we're
utilizing a study done by NREL as referenced in the bottom left corner. This study looked
at cold weather heat pumps in mostly the Spokane area and a few other areas that have
colder winters. And the study looked at, I believe, around 12 different buildings or homes
and they were trying to identify how well they performed in cold weather. Each of these
buildings had different designs of their system, which is kind of what's reflective of what
we would expect today because a lot of data you may see for heat pumps on how well
they perform in cold weather really depends on the building they're in. And I'm going to
get to that in a little bit. But the gray line on this chart is trying to represent how efficient a
heat pump is supposed to be in the cold weather from the study. On the bottom X-axis
you have temperature, outdoor temperature, and then on the left side you have COPD
and this is efficiency. The best way to think about this is an efficiency of 1 would represent
a forced air electric furnace that is resistance heat. And if you have a COP of two, you're
twice as efficient as that electric resistance furnace. When you're at around 65 degrees
in this study by NREL, they found that you're a little bit over 3.5 times more efficient than
an electric furnace. But what happens is as temperatures decline, the heat pump loses
its efficiency. At the coldest temperature they recorded in this study was about 5 degrees.
They found that a heat pump was a little bit less than 2.0 efficiency, so a little bit less than
two times more efficient than the electric resistance.
James Gall: But there's some issues with that. One is the heat pump on its own couldn't
provide all of the heat for the building, so auxiliary heat had to turn on, and then too many
of these heat pumps have to go into a defrost cycle when it's around 35 degrees. So, you
have efficiency losses between the auxiliary cycle and the defrost cycle. The blue line
represents what the net efficiency is. Of these, these heat pumps and cold weather, still,
even at 5 degrees or slightly above 11 COP, you get below that. You basically trend down
to a COP of 1, and it's also possible you could go below one if your unit gets stuck in a
defrost and it's on full resistance. And of course, if your heat pump is oversized for your
home, you may be able to get a higher COP then these are showing, but that means
you're going to be installing more expensive equipment for your home and have quite a
bit more cycling. You have a question. All right? Well, from Fred, OK.
Fred Heutte (NWEC): Hey there. It's Fred Heutte, Northwest Energy Coalition. Good
morning, everybody. I'm not familiar with this report, but thanks for providing the link or
the reference, but I have a couple of quick questions. Could you say what the net
efficiency line represents?
James Gall: Yeah. That's taking into account the auxiliary heat and the defrost cycle.
Fred Heutte (NWEC): OK.

Appendix A
James Gall: What their actual efficiency is, of delivered heat in the home, so if it's five
degrees out between the heat pump and the auxiliary heater, you're a net efficiency. At
five years it would be just over one on average.
Fred Heutte (NWEC): Right. And then the other question is that little bubble there says
heat pump lockout point. What do they mean by lockout point?
James Gall: Yep. That's what I was about ready to get to.
Fred Heutte (NWEC): OK, before you go on, I just want to say about the defrost cycle,
new heat pumps where I'm staying here in Portland on January 13t", it got down to 15
degrees here, wind chill was below zero with 50 mile an hour wind. Spokane is not
unfamiliar with that kind of condition. We certainly are not. What I noticed was, and these
brand new Daikon heat pumps are good, they were defrosting about every 20 minutes in
those conditions and definitely you know the temperature dropped inside. I mean, that's
pretty extreme, especially over here in the West side. But I just want to say I have
personally experienced this divergence on the curve that you see.
James Gall: Yeah. And if you do check the study out, there's a good chart they show for
each home. How much defrost is happening and it's quite enlightening. I think, like you
just said, you experienced that event and it is, I guess, the downside of a heat pump
technology and maybe that's when I get to this heat pump with the gas lockout, that's a
solution for it. All right.
Fred Heutte (NWEC): Yeah. Oh, it also noticed that Northwest natural came yesterday
and took away our gas meter. A few months after we shut off. So, we're really committed
now to the heat pump side.
James Gall: Alright, OK, what do I mean by heat pump lockout for gas? This is something
we're remodeling from our last IRP, we haven't modeled this scenario in this electric IRP,
but will be modeling the gas IRP. But if you have a hybrid heating system, this explains
why we've mentioned there's a point where you want to transfer your heat pump from
natural gas or from electric to natural gas. In the event you had a combo set up and you
have instead of an electric axillary unit you have a natural gas unit. You get to a point,
and this example it's around 40 degrees, when the heat pump can't on its own provide
enough heat for the building. That's when the auxiliary unit, in this case natural gas, have
to start turning on. You can see everything left of that curve. There's a divergent where
you start losing efficiency. But basically, also at that point, if your house is designed in a
way that your heat pump cannot satisfy the heating load, then you're going to have to use
an axillary system. If your home and your HVAC system is sized properly at around 40
degrees, your heat pump would have to switch over to an axillary system. If it had a
natural gas auxiliary, if it had an electric auxiliary, you can continue to maintain both. But
if you oversized your system, you could possibly have your lockout, the lower temperature
maybe down to 30 degrees, but that depends on the system. Where I'm going with this is
every home is really unique and it's set up for what the heating capacity of its heat pump
is versus the home's design. On average, we assume it's around 40 degrees where if you

Appendix A
do have a natural gas backup, that's where it would switch over. Alright, what does this
all mean for load? In this case, if you moved 80% of our gas system to electric, this is
what you end up with new load. The orange line represents the January energy amount.
It's about 450 megawatts of average energy. If we wanted to convert 80% of gas load to
electric and this includes the space heating we just covered at the efficiency curves, water
heating, and then we call it other natural gases.
James Gall: Now, not all of the load that's on the gas system and either state wouldn't
become Avista electric customers. We estimate around 75% of Washington customers
would be Avista customers on the electric side, the rest would be potentially Inland
Empire. Sorry, Inland Paper are Inland Power or Vera Modern. Some of the other coops
and municipalities in our area, also on the Idaho side, it'll be about 90% of the natural gas
customers would become electric. So, there are actually higher loads than this. It's just
they would not be in our service area, the electric service area.
James Gall: Going back to this on the blue bar represents how much annual energy there
would be. And in gray represents the August energy. August really represents maybe the
water heating amount of this electrification and then the space heating as you can see in
the orange, significantly higher than when you average all that out, it looks around 200
megawatts. I believe our January load today is around 1,300 average megawatts, so you'll
be adding about 450 megawatts to 1,300 just to give you a comparison of how much extra
load this is to the electric system. Quite significant. So, what does this mean when you
add all these up?
James Gall: We had three scenarios we promised to run in the IRP. The first one
obviously is the expected case, which we will show everybody in the next TAC in July.
We guess the one after the next one and then we had three other load scenarios. We're
going to cover that with electrification.
James Gall: The first one is the 80% building, Washington building electrification. That
is basically this chart here, but just for the Washington service territory, we're going to
while just Washington on its own for building electrification, that's the orange line in these
charts. And then we will then do a second scenario where we combine the building
electrification and the high transportation electrification just for Washington. That's in the
green line. And then in the blue line will be a combination of both states.
James Gall: High electrification scenarios, that would be what I called the ultra-high load
case in blue where we're looking at 2045. Our peak January forecast would go from about
2,150 megawatts up to 3,250 megawatts. So, about 1,000 MW load increase.
James Gall: That's the four scenarios for electrification. We are looking to give everybody
an update on other load forecast scenarios. It seems like most of the scenarios that we've
been asked to do this time around are related to load. Here's just a quick rundown. The
maximum Washington customer benefit scenario, there is a different load forecast for
that. We're going to have a different EV and solar penetration load that's in the Named
Communities. We're still working on getting that data from the DER study for that case,

Appendix A
so that will have a slightly higher EV forecast than our Expected Case. And then a higher
solar forecast, those might offset a little bit, but that will be used in our maximum Customer
Benefit Indicator scenario.
James Gall: We'll be doing a data center scenario where we would get a 200 MW new
data center load and we are assuming that would be in the Idaho Service territory by
2030. We could move that to Washington as well. I guess it depends on what it might be
beneficial to run it in both states, but I guess that's something we can discuss if there's
interest in one state versus together, but about 200 megawatts I think is probably the
upper end of what we're seeing for data center sizes.
James Gall: The third scenario we're going to be conducting is the RCP 8.5 case. That's
still in progress. We have two other ones that we're looking at as well, low growth and
high load growth. And these are two scenarios that are based on economic conditions.
I've got some examples of those economic conditions down in the bottom. We're still
working on getting those load forecasts complete. The last one is a scenario that we
haven't talked about yet, but it's something I was going to mentioned that might be
interesting. I think the Washington State legislature passed a campus building
electrification or decarbonization bill. I can't remember if it was this year, I think it was last
year. We have a number of campuses in the service territory that could, depending on
the how they meet that requirement, electrify a significant amount of heating load. We're
debating whether we should do this scenario or not. It could be as much as maybe 60
megawatts of winter peak load, could be even as low as 30 MW. That's something we're
thinking about and happy to listen to any thoughts on that bill. If you have any information
on that, or if this sounds like a good scenario, but I also don't want to overwhelm the
process with a million different scenarios because we are getting, I think over 20
scenarios. That's all I have for slides. If there's any comments or feedback on what was
just presented.
Fred Heutte (NWEC): Yeah, it's.
James Gall: Right answer question. Yeah, go ahead.
Fred Heutte (NWEC): Yeah, it's Fred. Just a very quick question. Is there any particular
reason to specify Washington or Idaho on the data centers? There's some reason why it
would make a difference.
James Gall: There is. If it's in Washington, we have to supply with 100% clean energy
by 2045. Idaho there is not that requirement now.
Fred Heutte (NWEC): Alright.
James Gall: The data center itself may ask for that, so I guess we could make the
assumption no matter what service territory it is, they want 100% clean supply. That might
solve that issue.

Appendix A
Fred Heutte (NWEC): Yeah, I think most of the operators want that now anyway.
Certainly, you're in Oregon.
James Gall: Yeah. Maybe that's what we'll do is we'll just assume it's 100% clean, no
matter what state it's in. And then that solves that problem. Alright, good comment. Thank
you. Alright. Anything else? If not, we'll skip to the resource presentation by Michael and
there should be lots of things to talk about there. So, whenever you're ready.
New Resources Options Costs and Assumptions, Michael Brutocao
Michael Brutocao: Trying to get this to share. Alright, looks like it's working. I'll be
covering our supply side resource options that we're modeling this IRP. It's basic graphs
throughout this, so feel free to interrupt. There might be some awkward pauses, a lot of
time for questions, but jump in. Some of the overviews and considerations these
resources we're considering, the current and near commercially available technologies
that are both within or near this service territory.
Michael Brutocao: Are these costs? There are variables such as location, equipment,
fuel prices and ownership that are going to affect resource costs and have those little
vary. We are also modeling resources as PPAs as well as Avista owned. These
assumptions do not mean that these are the only means of resource acquisition. Those
resources that are modeled as PPAs are the solar, wind, nuclear and geothermal. Owned
would be all others. That might be battery storage, pumped hydro, fueled gen. These
costs do not include any transmission or interconnection costs except for off system
resources. An Excel file will be distributed that basically shows how all this was calculated
and broken out and that I think will be covered at the June 25t" meeting. The technical
modeling workshop.
Michael Brutocao: OK, how the IRA was included in these costs. There are production
tax credits for geothermal, solar, wind and biomass, as well as nuclear. And then there
are investment tax credits for battery storage, pumped hydro and solar again. Solar is
modeled as both a PTC and ITC separately, and then the lower of the two costs are taken.
The lower the two approaches for the ITC, it's a 30% tax credit for those resources through
2032 and then that falls to 26% in 2033 to 22% and 2034, and 10% in 2035 and 2036.
For residential customers, residential solar goes down to 0% in 2037.
James Gall: Molly has got a question. Molly.
Molly Brewer (UTC): Yeah. I was just curious, the Commission came out with the policy
statement on incorporating the IRA in the IRP. I don't have specific examples right now,
but I'm just curious if you know, is that captured and what we're seeing here?
James Gall: Exactly what we're capturing. Yes.
Molly Brewer (UTC): OK, good. Just wanted to make sure. Thanks.

Appendix A
James Gall: Yeah. We're trying to include everything we know about potential for ITCs.
But the real challenge one is, the, we have a blank on the name the IJ, JIJ.
Molly Brewer (UTC): Yeah.
James Gall: You know, those are a little bit more challenging for long term. They're more
focused on, it seems like shovel ready projects, so that is not going to be included, but
anything IRA related will be included in this, our assumptions for those.
Molly Brewer (UTC): Cool. Thanks.
James Gall: Yep. And then we do have a question in chat. Since pumped hydro likely
qualifies for the 10% domestic content bonus ITC, should it be 40% for pumped hydro?
Batteries, presumably not qualified due to foreign sourcing.
Michael Brutocao: That's a good question. I will have to check that. I didn't know that
the country would be qualifying there. We'll verify that and we'll add that to the tax credit
if we do agree with that. On the battery side, that is something we are assuming that and
the iron oxide batteries would get the extra 10%. But the lithium ion we're assuming would
not. That should maybe address Matthew's comment. I wanted to say I think we have
something happening to that 10% domestic production adder. But I can't check, verify
that right now.
Michael Brutocao: Here's just a list of some resources that are not being modeled. I'll
point out on line three. RNG is not being modeled except as a fuel for a frame CT. And
some of the resources that were something, but it's the first of two sizes on resources that
are being modeled. See at the top, those first three frames, CTs differ by fuel source, so
there's natural gas, ammonia and RNG. That being the differentiating factor of those and
then the bottom 7, starting with Kettle Falls and below, those are all upgrades to existing
resources. And this is mostly for reference. It's a lot of information to take in at once and
cover, but if there are any questions, please feel free to, we can come back and answer.
James Gall: Michael, do you mind covering where we put the sources for our cost
assumptions?
Michael Brutocao: Yeah, there are obviously some internal, but maybe those upgrades,
but the majority of not all of these costs are from NREL, from the most recent annual
study. The, blanking on the name of that, I can certainly share that with anybody who's
interested. So, these are the rest of the top half or the top portion. You can see the solar
resources and then down below, some of those storage batteries and pumped hydro.
Michael Brutocao: And then we'll get into a couple graphs. I think there's five of them
that are going to show you the Ievelized cost of these resources. Here's our solar
resources. The Y axis, these are in dollars per MWh. On this, I want to point out the note
in the bottom, community PV does not include administrative costs. Which about $25 per
kilowatt year. And it also points out the low-income community PV, I believe looks like
through 2033 that model is assuming Washington covers 80% of the capex and then it

Appendix A
takes ITC or PTC depending on which is cheaper and the following one or two years, I
think for the rest time period. Fred has a question.
Fred Heutte (NWEC): Yeah, very, very quick on the community solar. Did I hear you
right? Not including admin costs, but the admin costs are $25 a kilowatt year?
Michael Brutocao: Yeah.
Fred Heutte (NWEC): OK, doesn't seem like all that much, but not unimportant. OK,
thanks.
James Gall: We're still validating that number for admin, a lot of it depends upon how big
the program gets. If we had just one program with say less than a megawatt facility, it's
probably going to be significantly higher than that. But if you start, let's say you get 10
megawatts or more than you're probably in that range.
Fred Heutte (NWEC): Yeah, I can see that. Just a note, we have a pretty extensive
community solar program in Oregon. It's been a long haul to get where we are. It's actually
quite good, but it's also had a lot of struggles with costs, interconnection and admin costs.
Like you said, it's not a cheap thing to do the way we are doing it. Anyway, it will, especially
for us, given our transmission constraints over here on the West side, I think it's going to
be increasingly seen as being very valuable. Our projects typically are in the 1 to 3 MW
range. So, you're not really getting scale economies from that, but you're also getting a
better distribution in places where they can fit in well. It can add up to quite a bit, but yes,
it's more expensive obviously than doing bigger grid connected.
James Gall: Yeah. And I believe the Washington credit is for projects less than 1 MW. I
don't know how I let it string those together and we're just starting to investigate this, but
it's going to struggle from similar challenges you've seen in Oregon.
Fred Heutte (NWEC): Yeah. And just so everybody knows, rough rule of thumb on these
solar projects is, I don't know if this may be an over underestimate, but I would say
approximately 10 acres per MW for space.
James Gall: Yep. That sounds correct for a non-tracking system. Alright, Molly has a
question. Yeah, Molly.
Molly Brewer (UTC): Yeah. What is commercial PV?
Michael Brutocao: Yeah. Commercial is, I think it's just a one MW, so basically a
commercial customer.
Molly Brewer (UTC): Commercial customer. OK. Thank you.
Michael Brutocao: Yeah. See the residential customer, commercial customer, and then
we broke out residential between new construction and existing construction because the
costs of a new construction home is quite a bit less than an existing home, but
commercial, it was about the same.

Appendix A
Molly Brewer (UTC): OK.
Michael Brutocao: Alright, one thing that you'll see on the remainder of the slides here
is this jump in the middle, just make that connection, this is being phased out, ITC and
PTC credits.
Michael Brutocao: OK, there's wind, offshore wind at the top, and then the rest keeps
on system, off system here locally and then Montana wind. These are MW hours on the
Y-axis. Baseload energy. These would be nuclear, small nuclear, modular reactor on top
and geothermal system on the bottom. These are in MW hours on the left-hand side. And
a bit more going on here. These are all the energy storage options, batteries as well as
pumped hydro. Hydro is in the kind of green hues and here they move into the top of the
chart. Everything else is going to be batteries. And where you see these dotted lines, that
is the cost for distribution scale of this type. For example, this would be the 4-hour lithium-
ion battery. The utility scale is down below and the solid line. And if you can't see it, the
8-hour lithium-ion for that orange dotted line, it's kind of hiding behind this 100-hour iron
oxide battery. Another question from Matthew. Matthew, do you want to cover your
question?
Matthew Shapiro: OK. I guess this is a little bit in the spreadsheet that is in the future,
but did these factor in the different life spans of the technologies like the 15-year lithium
ion versus the 60 to 100 year for the pump storage? That was my first question. Then
because the Ievelized cost of storage should be immediately even if you only used 45
years or something like that. When you compare it with the cost from the earlier slides, it
shouldn't be that much higher I would imagine. Then the other is related to why it jumps
in 2032 when the effect of the ITC is essentially to lower the cost of building the project.
So, the 2032, as long as the project enters construction by that time it captures 100% and
then at 2033. If it has, it enters construction by 2033, it's a bit lower, et cetera, et cetera.
And then it drops away completely if it doesn't enter a construction, but once it's in place,
the ITC is for the construction of the project. The effect is permanent. So, just wondering
why that jumps up so much at 2032 and then why the pump storage number keeps going
up whereas the lithium ion is flat into the future. Those are, I guess, three questions really.
Michael Brutocao: Yeah, we may need a refresher on those, but now I'm forgetting the
very first one. The lifespan is accounted for in two ways. In one, there's the reinvestment,
I think for batteries it's replacing dead cells. And then, there's also a different. I'm working
on the word,just different depreciation period for the assets with different life spans. We're
using 50 for pumped hydro. Or 45. It might be 50.
Michael Brutocao: I think I answered your first question. The second that I think there is
a challenge though on your second question on the construction start date. If you do start
in 2032, you're going to get the tax credit, even though it's not complete until 2035. 1 think
that's a valid argument. We'll have to think about how to address that because we don't
know what projects are going to be there. But you're probably right. We could probably
extend that out, at least three or four years to take that into account. That's a fair argument

Appendix A
where the other battery technologies, they're going to have a much shorter construction
cycle, so I don't think that's as big of an issue.
Matthew Shapiro: Well, the pump storage is going to be able to take advantage of the
ITC for its entire Iifespan because essentially, you're lowering the cost of the capex of the
project for its entire Iifespan versus the batteries.
Michael Brutocao: Correct.
Matthew Shapiro: If they're coming online, they're first replacement and say, 15 or 20
years of the system doesn't get the ITC and all of a subsequent replacements over the
course of the equivalent Iifespan of the pump storage presumably don't get the ITC.
Michael Brutocao: Yeah, I think.
Matthew Shapiro: And so, it benefits the pump storage much more really.
Michael Brutocao: Correct. Yeah, I think there's a misunderstanding of the chart. The
price you see here assumes when it was put into service, a project built in 2032 gets that
price forever versus the price that was in service in 2033 gets that price forever.
Matthew Shapiro: Right.
Michael Brutocao: We're doing exactly what you're referring to. I could have made that
a little more clear. But yeah, and the same thing with the other projects on the other slides,
that's the price when it's in service. Still here it's effective price is going to be straight.
Fred Heutte (NWEC): Yeah, just a quick comment, I think.
James Gall: Fred, then Sofya.
Fred Heutte (NWEC): I think I agree with your approach here that basically these tax
credits, you can net them out against the capital cost up front like a lump sum. The
question of how they apply over time is a different, that's a project finance question I think,
but I think for planning purposes this is fine. So, something, let's lithium ion, which has a
say or 10- or 15-year replacement cycle over 50 years you'll have a couple of those, but
you'll already have a incorporated the full value of the tax credits up front. And you know
you can levelize that out, but I don't really see a big obstacle here. The way project finance
deals with these tax credits is all over the map, and that's a whole other subject.
James Gall: Sofya.
Sofya Atitsogbe (UTC): Thank you. Hi. This is Sofya Atitsogbe with Washington UTC. I
have a question about 2035. The U.S. signed an agreement to go coal free after 2035
and understand that Avista will not have any coal on the system by that time. But maybe
that would influence the prices of the energy resources for which Avista will compete with
the competitors. Do you know what impact it will have if any at all?
James Gall: I don't think we know the impact. We're assuming how each of the costs of
all the resources change over time is the annual assumptions and they're looking at

Appendix A
competing for a different, you don't think about concrete, steel lithium, the different other
materials that are used to build these assets. They're taking that into account. I would to
some extent, but you know obviously this is a new question that probably get reflected in
the next draft that NREL puts out. But our cost assumptions for future cost declines or
increases come from the NREL study. I guess the answer is it's not considered to our
knowledge. I don't know how it would affect costs.
Sofya Atitsogbe (UTC): Gotcha. Thank you.
John Lyons: Yep, let me pick up the question on the difference between the flat for
lithium ion and the increasing cost for pumped hydro on the later years and that goes
back to the question — how did NREL assume costs were going to decline? They're
probably assuming that it's more of an increase in inflation overtime on the pumped hydro
and the lithium ion there, assuming there's still probably some technological solutions
getting in there that would flatten it out, correct, OK.
James Gall: Thank you.
Michael Brutocao: Dispatchable resources, so on the left-hand side we'll see variable
costs in dollars per MW hour and on the X-axis you see fixed costs per kilowatt year.
Yeah. For some of these, there are two different shades of color. The lighter shade is
going to indicate a cost of Washington, with darker shade being Idaho costs, and then to
help you kind of read it, the bubbles as they increase in size, that's indicating that we are
moving forward in time. The smallest dot on any of these lines is going to indicate 202026
costs and the largest bubble is going to indicate 2045 costs. And again, these are level is
so when it unit is. Built, I guess and put in the service that would be. That cost is. Lovely
eyes still can't answer question, yeah. So if you go ahead.
Sofya Atitsogbe (UTC): Oh sorry. I'm seeing my hand up, it's not.
James Gall: I just want to bring one thing up on the variable cost. This is both fuel costs
and variable operating costs. And then for projects like the ammonia turbines, that
assumes that the cost of the hydrogen to produce the ammonia that is included as a
variable cost rather than a fixed cost. So that's, I guess, yet to be determined if that
resource is picked, if it's a fixed cost or variable, we just assume it's a variable cost, same
with hydrogen. And then lastly on the Rathdrum CT, is a negative cost and that is because
that upgrade lowers the heat rate of the overall facility. So, the variable cost is actually
less, but there is a capital cost to do that upgrade.
Michael Brutocao: Thank you, James. And I will pass it off to you Dr. Lyons.
John Lyons: OK, so a little bit of a change that we've seen. Last IRP, we had some NEI
studies we had an outside consultant run. It was DNV, if I remember right. There were a
lot of things that we looked at and thought it would be nice if we could actually run some
of these studies ourselves. So, we went and looked at different modeling applications that
we could do these studies and we ended up getting IMPLAN. IMPLAN is one of the major,
the two major, modeling software for this. It's a more inexpensive one, started in the 1970s

Appendix A
for the US Forest Service to be able to look at these non-energy impacts. We now have
a license to run it for Oregon and Washington. We've just been getting into it. We've done
some preliminary studies and we're getting into the nuances of what we actually get out.
There's a lot of data that comes out of these studies, but which ones that we feel
comfortable with using because some of the data is thinner than in other areas. Say you
wanted to run a study for a modular nuclear reactor. No one has built one of those yet,
so there's no data for that. But we can say run a study that shows what is the net impact
of building a wind project in Washington. We would have the direct impact of jobs, the
indirect impact of the jobs for all the businesses that supported that, and then you would
also have the induced jobs from all those people making money and getting to spend it in
the community. We can also calculate upstream emissions estimates, there's some we
have again better data than others, but at least this gives us the opportunity to run these
studies. Other things that you can have in there would be a local state and local tax
receipts and what would be there We're still getting our feet wet in this, but we'll be sharing
more with that model outputs on this as we go along.
2030 Loss of Load Probability Study, Mike Hermanson
Mike Hermanson: Hi, my name is Mike Hermanson. I'm a Senior Power Supply Analyst
here in the resource planning team, and I'm going to be covering the 2030 loss of load
probability study that we just recently completed. I'll talk about the purpose of a loss of
load probabilities study, the methodology that we used, some of the metrics that you can
pull from the results, and then look at the results from our study. And then the ultimate
result is the planning margin, which is the amount of resources we would carry in excess
of our load projection.
Mike Hermanson: The purpose of the loss of load study is to determine when your
system cannot meet load and there's a number of reasons why you would not have
enough resources to meet load. You have different water years, and you have different
load projections, and different load years. The temperature is different each year. You
can have maintenance outages that are planned. You can also have forced outages that
are unplanned and of unknown duration, and then we also have additional variable energy
resources that are being added to our system and you cannot accurately predict like you
can with a gas CT how much production you're going to get out of that. We run this study
in a Monte Carlo fashion. We run 1,000 iterations and it does different combinations of
these water years. The load, the temperature, maintenance, and forced outage the
software combines those in in all sorts of different iterations and then determines at what
point can we not actually meet the load. That is as expected of the system. We're looking
at our system in 2030, but with no increased resources. We're looking at what we have
planned right now, and we have a market-purchases that are allowed, up to 330
megawatts from the market and the period of record that we used was 1947 to 2045. All
future data is the climate data that we used for our water and load and temperature in the
future years only. Got a question.
James Gall: Go ahead, Molly.

Appendix A
Molly Brewer (UTC): Yeah, with the availability of the 330 MW hours from the market, I
think I recall some time ago you guys saying that might be in question. So curious, where
does that come from? And is that availability in question?
James Gall: Sure. It's been a number that we've used for quite a long time. We looked
at what has been available from the market, looked at data, and we are actually possibly
reevaluating that expectation from the market, but it's kind of been a rule of thumb almost.
I would say professional judgment. Has all come into that and just experience with what
we've been able to get from the market. Also, a conservative value. You don't want to just
have your whole system rely on the market and so that value has been used in previous
loss of load studies. And so, we continued this study, but we have had discussions of
increasing it. I'll add a couple things there. The MLK event was an example of this where
we were able to get more than this amount before our units tripped, but then there was a
question of could we have gotten that amount as it got colder that weekend. I think this is
going to be a debate internally. Do we stick with this number? Do we increase it? Do we
lower it? And I think when Mike gets to the results, you'll see what the impact of this is.
Because for every MW you change from this number basically changes how much we
would need in our system future. It's a major assumption and we're going to have to keep
looking at this, but the results are going to see here today is based on the 330 MW, but
that's subject to change. Fred, go ahead.
Fred Heutte (NWEC): Yeah. My question is, I would assume by 2030, all of us will be in
a day ahead market, you haven't made the decision yet. Actually, I don't know. I'm just
wondering, does that change the nature of how you address the market issue? Do you
assume that you're going to get roughly the same quantity from an organized market as
opposed to bilateral? Or is there much difference? And then I guess the other question
with the other issue for me, and we certainly learned this in January, was the value of the
organized market or the day ahead market in optimizing the dispatch, which makes it a
whole lot easier to count on that. Whatever quantity you want, you have a higher likelihood
of actually getting it because you don't have the obstacles of bilateral training to get what
you need. I'm hopeful that it will increase it but also you have the WRAP's coordination
on top of that. Alright.
Mike Hermanson: That's kind of blending to maybe we should plan for a higher amount,
but then you look at the resource adequacy of the system that is, I would say in an even
position or short position. I think in a perfect world where there are resources being added
to be reliable system, I think we could increase this number. But then on the other hand,
if resources aren't built, then maybe we should be lowering this number. I guess it just
depends on your, go ahead.
Fred Heutte (NWEC): Yeah. I have to say that I also am taking some concern from the
count of Northwest Power Council. Just had their Resource Adequacy Advisory
Committee last week. They're showing we're pretty OK through the end of the decade
with the kinds of resources that are currently in plans, staying on track. But we get into
trouble if we have a bigger data center load growth outcome than is kind of a moderate

Appendix A
one, more of an aggressive one. I agree that the real underlying issue here is what is the
overall resource adequacy of the northwest? of the West? That's really the issue driving
this.
Mike Hermanson: Yep, thanks. This is just a look at what the methodology is to arrive at
the total load numbers. Essentially, we use an Excel based model with VBA code and
then it uses a linear optimization Excel add in that's called What's Best and it's an hourly
model and it basically runs our system virtually for every hour and it's targeted to meet
specific loads and resources or reserves that we have put in hourly loads and then the
hydro generation and storage, and that is a dispatch storage, and that's the linear
optimization portion of this. We have thermal generation and then we have historical
hydro generation from run of river projects. We have renewable generation that is
dependent and autocorrelated and it's influenced by temperature, and we have the ability
to add batteries and then we have all of our contracts in there. And so essentially it runs
every hour of a year and tries to solve for meeting the load and the reserves and then we
output the results, and we can look at how many iterations it has not met load.
Mike Hermanson: Reliability metrics are an interesting thing. They are hard to find as an
industry standard. You cannot go out there and find that NERC has put together a target
for each of these types of metrics and the metrics are all similar, but they do have their
differences. The main metrics that we looked at were lots of load probability and that's
calculated by counting the number of iterations where there is unserved load. That could
be any 8,760, anytime that we were not able to meet load that counts as one and then
you divide that by the total number of iterations, and you get a percentage.
Mike Hermanson: Lots of load expectation is similar, but you're just counting the days
where there is unserved load or unmet reserves. So, instead of 8,760 chances you have
365 days that could have a loss of load. Loss of load, expected events, like I said, similar
calculated by counting the number of consecutive blocks of unserved load and then
divided by the number of iterations. Loss of load hours actually starts to look a little more
deeply, I think at the duration of any time you have an event where you've lost the load
and then the expected unserved energy actually looks at how many megawatts you were
short. It starts to get into magnitude. Being able to look at all five of those is fine and it is
similar to what the Power Council is now doing, looking at three different metrics. We're
moving in that direction, but currently we look at that one metric to inform our planning
reserve margin.
Mike Hermanson: This is taken from a NERC document. The probabilistic adequacy and
measurement report. This is as close as I could come to finding some sort of description
about an industry standard, but they are very quick to point out that all utilities are
different. What their loads are derived from or different, their resource mix is different.
This is a description of how it was described in this report and what these are used for.
The LOLP is really used to look at the probability or likelihood of events due to insufficient
capacity. LOLE is primarily used to establish resource adequacy criteria. This is the
closest one to a kind of an industry standard. It has a 0.1 days per year or one event one

Appendix A
day in 10 years. The LOLH metric is computed by a large number of entities in North
America, but only one entity uses this metric has arrived reliability criterion and they look
at a goal of 2.4 hours per year. The LOLEV metric is useful in systems that are concerned
with frequency of events, regardless of duration, magnitude, and the UAE is an estimate
of the size of the loss of load events. You can look at that cost and impact of those events.
Mike Hermanson: Now I'm going to get into the results of our study This is looking at
how many the sum of the hourly average loss of load across 1 ,000 iterations. It's looking
at months on the vertical across hours and so you can start to see what times of years
we're having loss of load issues and it's not surprising the winter months during the peak
hours are our most problematic at this point. We have a smaller issue during the months
of September and August and a little bit in May and one in June, but primarily the loss of
load with our current system is occurring in the winter months. The way we use this, the
loss of load, is to establish our planning reserve margin and you can do that by taking
what your base case is, what you currently have planned for 2030 and then you
incrementally add additional resources, and these are additional dispatchable resources.
These results show the metric on the left for each of these additional resources and so to
get at. I should back up a second and say that Avista's target is really to meet an LOLP
of 5%, and that's a target that we've been using for a number of years.
Mike Hermanson: And then the other metrics we're starting to look at, but have not
incorporated into our decision-making, and we're just looking at the LOLP and the use of
it is to look at our load versus our resources. We have a target load, and we look at what
happened with what we have. For example, if we had a target load of 1,000 MW and we
have resources at 1,000 MW, then we would have a balanced system. But when you put
it into the tool to look at the LOLP with all of the additional uncertainty, you start to get a
different answer. What we do is add in the amount of dispatchable resources that we've
added in, and then divide the load, or the resources by the load. And we're looking to hit
that target at 5%. Our base case, we have an LOLP of 13%. That would end up with an
implied planning margin, to achieve that we need 21% additional resources than we
currently have to have that kind of margin that will account for all of the uncertainty within
the system.
Mike Hermanson: And as you can see, as you add additional resources, your planning
margin goes up because you're adding in additional resources. So, your resources
needed to achieve these lower LOLPs, so you need to add 200 megawatts, for example,
to get the 4.2% LOLP. So, you've added a lot of ability to absorb unexpected events.
We're looking at a target of 5% and so did an interpolation of these results and we would
need to add 167 megawatts to achieve an LOLP of 5%. Right now, we're in the process
of digesting these results and right now we have a planning margin of 22%. So, 22%
above our forecasted load and looking to see what planning reserve margin we. Worse,
with Teams, here it is covering up the one number I need to see. To achieve a loss of
load probability of 5%, the planning margin would need to be 30%.

Appendix A
Mike Hermanson: Another option we we're looking at it, it goes back to the discussion
we had earlier on market, should we assume more market and keep the same planning
margin is the other alternative. It's either add resources or be more reliant on the market.
That's the debate we're having and would like to hear your opinion about one thing I
wanted to also add what's changed from our last IRP that shows us and that is the reserve
discussion we went through with the last TAC being that Clint Kalich went through from
the work Energy Strategies in the solar integration study and basically discovered we
need to carry more reserves than we had in the past. If you look at the amount of reserves
that that study resulted in, it is basically the difference in added capacity between our
22% planning margin and the 30% and accounts for I believe 7% of that 8% change.
Mike Hermanson: By holding the additional capacity back for variable energy resources
is what's driving, the change from 22% to 30% and the results here. But then you ask the
question, should we stay with that assumption of the market at 330 MW meeting the
reserve? Should we be more market dependent or less market dependent? I think this is
a great study that basically shows you where we're at and then we got to identify what
tradeoffs are best for our customers. Is this to be more market reliant or to build more
generation to supply the variability because we are definitely subject differently to
changes in load because of our resource design. We have a lot of energy that is, we have
capacity, but we don't have a lot of energy that goes with it. I would like to maybe go back
to the previous slide real quick and you notice in this one in the winter months. We just
lost it that one. We're especially in January in December, we're having issues in all hours,
which is showing that we have an issue with energy and capacity storage is a great
solution for the summer months that you see here where you have a 5 hour issue, but
we're needing something that's definitely long duration and that creates challenges
because we have a significant hydro system that can't generate continuously days on
end. And so, we're going to kind of be in a new situation that's driving these high planning
margin requirements just because of a lack of sustainable energy in these peak periods.
James Gall: I just saw we got a post in the chat, which we'll take a look at. That's a good
reminder. That's regarding the NERC forecast, but I just want to open it up if there's any
last comments or questions on this. It's highly technical, but I think this is extremely
important to discuss because we're going to debate if should we be planning for more
market or more resources. Go ahead, Molly.
Molly Brewer (UTC): Just to confirm, if you're planning for more market, then you'd be
OK with going below 5% LOLP.
James Gall: I think what it means is, well, I guess depends on the way you look at it.
Molly Brewer (UTC): But that's the trade off, right?
James Gall: We would assume, let's say we went with 500 MW market, we would let the
model buy 500 MW for the market. We would recalculate the LOLP based on 5%. For
example, here we are using that 330 MW you're already assuming.

Appendix A
Molly Brewer (UTC): Oh, got it.
James Gall: Let's say you added zero. You had zero market. Our planning margin would
be, I'm just going to throw out a number, 15%. We're already assuming a certain level of
market, which is prudent. It's just a matter of what is the appropriate level.
Molly Brewer (UTC): You keep 5%, but it would end up being a lower MW hours number
and then that's a lower planning margin.
James Gall: Correct.
Molly Brewer(UTC): OK. Thank you. I don't have an answer for that, but I'll want to chew
on that.
James Gall: Yeah, definitely. Another option is we move to go with the higher market but
use the 0.1 LOLE is another option we could change to a different metric. I know LOLP
is, from a Power Council point of view, is falling out of favor for the three other metrics,
but so there there's definitely options out there. I saw two hands pop up. Let's go to John
first and then Fred.
John Calvin Slagboom: Hi, good morning. Thank you for this presentation. I just wanted
to ask a question regarding what assumptions is the model making when it comes to
purchasing from the market in these scenarios? What is the market area that that's
purchasing from and any other information that you can provide?
James Gall: It's essentially a number that the model has available to it. When the model
is solving to meet load, it has 330 MW available to it. We do have the ability to do different
types of markets so we can run different amounts for peak times versus off peak times.
We also have what I called a constrained market, which we base off of temperature so
that we can set a different market amount for a certain temperature level. In this particular
study, it was 330 MW for everything, but we could do different things. It's really just an
inputted number that can be applied based on different time periods, peak, non-peak and
then again that constrained market condition when you could have the market shrink
when it's a really cold event.
John Calvin Slagboom: OK, so when you're saying the temperature variability, is that
essentially baking in reliability issues that come with heating or cooling events?
James Gall: Yeah. I mean it's essentially use. We're assuming that if we were having a
really cold event, then that the market is going to shrink because everybody needs it.
John Calvin Slagboom: Yeah. OK, got it.
James Gall: And that's the 330 MW that we're referring to.
John Calvin Slagboom: OK, good to know. Just wondering, because there's this pretty
significant heating event a couple years ago that if I'm understanding the documents I
read correctly, put a lot of strain on the WECC, the Western interconnect, and it caused
some reliability issues. And as we see increased temperature events happening and

Appendix A
interconnectedness, if we were relying on these market-based solutions without backing
up with enough generating options, there might be a bigger issue at hand I'm wondering
about.
James Gall: Yeah, that's our primary concern as well.
John Calvin Slagboom: OK.
James Gall: If there's a balance, it's just trying to figure out what's that appropriate
balance.
John Calvin Slagboom: Yeah. Thank you.
James Gall: Great.
Fred Heutte (NWEC): Yeah, I have a more general question. I see you've got one more
slide maybe so I'll I can just hold off.
James Gall: Yeah, we got rid of that one, Fred. So go ahead.
Fred Heutte (NWEC): OK. Well, really broad questions actually. Just you mentioned the
Power Council got these new kind of multipart multi-metric approach. They're really giving
it finally, giving it a full drive around the track. I'm still wrestling with what I like and maybe
I'm not so sure about in all of that. My first question is what do you think about what they're
doing and is it providing any of the insights that are useful for your approach?
James Gall: You know, I think there was the biggest insight is trying to help with that
market assumption. Their analysis showed that the system, if resources are added to the
system, the system would be efficient in the same time period that we're talking about
here. But that's a big if. I also then look back on what was the issues that they had lost a
load, it was a cold day, and it was a low water year. Basically, the conditions we just saw
this last January and it makes me wonder, what if you may have a low probability or meet
your criteria because you assume that a low water, you're in a high load, only occurs less
than 5% of the time or whatever the number is. I think that is on our minds. We're really
planning for that event and if we're not planning to meet a low water year and a high load
event or cold day, we're planning to fail, and that's what concerns me the most. I mean,
we can meet load on all other events except for when those two conditions occur as a
region. It makes me wonder what is the right planning methodology? Should we just be
planning for that event, that scenario, because we can meet all the other scenarios?
Probably still want to run these studies. Validate that, but that was my takeaway from the
Council's presentation.
Fred Heutte (NWEC): Yeah.
James Gall: I know we have Tomas on here as well and you could probably speak to
that more than I can, but.
Fred Heutte (NWEC): Yeah, I was thinking more about the methodology here. They've
got this. They're really committing now to this multipart metric. And I think conceptually

Appendix A
that makes some sense to me. But then the question is, LOLP or LOLE or any of them is
as a single metric is pretty straightforward. It's not exactly pass fail, but when you're in
danger and when you're not pretty straightforward. On the other hand, those single
metrics cannot represent the three legs of the stool, which is frequency, duration and
magnitude. I get that in I generally feel like any of these, like you were just saying, any of
these methods will tell us what we already know, which is that we're especially with low
water, high demand we got problems in the Northwest and also in the summer, not just
the winter, because a little bit more hydro in the summer actually helps us quite a bit in
the late summer. But the real issue is going to be demand. And really, this is for me, this
is the really underlying thing we think we've learned, especially in January, the demand
surge that accompanies these kind of extreme weather events is not fully represented in
our load modeling or at least in our modeling. The way I think, we really need to now and
everybody is kind of grappling with that. So, no matter what metric you've got, that's a
really important underlying thing. And I know you also saw that in the heat dome in 2021,
with equipment stress and everything else that happened. So just a thought on that.
James Gall: Yep.
Fred Heutte (NWEC): My second question is referring to the WRAP. The WRAP has a
very elaborate approach to resource adequacy. I have some concerns about it. I'm on the
Program Review Committee, which is just the thing that reviews the rules, but I've been
thinking a lot about this also. Puget seems to be pretty enamored with the WRAP
approach. I am wondering though because I don't think it's really built for this kind of long-
term planning. And it's an important thing. And you know, if this is going to be in the
WRAP, the binding program will start whenever it starts. But I think the issue for me is
that, that looks to me more like an input into the IRP process because now you have in
the short run, the next few year's commitments, that you know you have to meet that to
become part of the area assessment. But I have some concerns about some of the
approaches in the WRAP, especially on the assumption of average load and the way they
do the storage, hydro modeling, and the seasonal approach rather than the month-by-
month approach for each of the seasons. Where in a season, now that early June does
not look like late August. Early December, early November does not look like January. I
just wonder what Avista's views are on the WRAP and how you are approaching that
given that you're committed to it.
James Gall: Yeah, great question. On the WRAP, what we've done is our L&R, which is
the presentation we're going to cover next. We're going to shift to that the next meeting.
We're using, I'd say the WRAP methodology for how we account for loading resources.
The planning margins that Mike went through that would assume you know QCC
methodology for resources, so how much qualifying capacity does each of our resources
get compared to what we call is our 1-in-2 load event. The WRAP has, like you mentioned,
a different load methodology. That's a lower load forecast. It's more of a coincident
regional load look, that's a ten year look versus a little longer period. That's an area where
we would differ, but as far as your idea of incorporating the WRAP in the short run, we've

Appendix A
looked at what our position is with the WRAP in the short run, and it basically shows we
have sufficient resources. There are some challenges in some of the maintenance
months, but we're sufficient in that short run. But our initial thinking is to use WRAP QCC
values to try to make an assumption of how QCCs will change over time. But at the end
of the day use our planning metrics because we don't know what the WRAP is going to
be long-term as far as the planning margins required.
Fred Heutte (NWEC): Yeah.
James Gall: Hopefully that helps.
Fred Heutte (NWEC): I just say that's a pretty reasonable way to look at it.
James Gall: Yeah. I do like your idea of maybe putting in a constraint short term but given
our length compared to the WRAP, that's probably more work than we need to do. But
it's probably something the utilities should probably look at. But it is a challenge because
we don't know what, for example, the biggest issue we're seeing is storage. The WRAP
gives storage a very high qualifying capacity credit, but if everybody has storage only
resources and the amount of gas and coal decline as expected, energy short resources
like storage are going to have a lower QCC value and we're trying to incorporate that. But
that's where the study that Mike just did. We're going to be doing another study with our
Preferred Resource Strategy both in 2030 and 2045. Love to make sure we can still
comply with whatever metric we end up choosing. That still meets that regardless of what
we think WRAP will do.
James Gall: And then there is our other concern on the WRAP is, will the WRAP survive
and if all the utilities are not participating then the WRAP is not meeting its intended goal
there's not a market out there to go get resources. If one or two major utilities don't show
up and participate, that's a concern for us as well. Lastly, the other concern, and
something that you brought up, that monthly versus seasonal. I believe there's three
months that the WRAP doesn't look at and that means, and they've traditionally not done
that because there's enough generation in those months. But what if every utility puts
their resources on maintenance in those months and we could create a problem in months
that are normally not an issue but become an issue because everybody's dispatchable
resources are on maintenance. That's something to watch out for as well.
Fred Heutte (NWEC): Yeah, I think people forget. It's not just peak load, it's also the
amount of resources. It's the balance between them. It really matters. We've seen
situations in so-called shoulder months where we got in trouble. Fortunately, early
October of 2019, when the compressor, the big pipeline explosion happened in BC and
Jackson Prairie is on an outage for maintenance that it was a close call. It was a low
demand period, but it was still a close call. So those things can happen.
James Gall: Yep.
Fred Heutte (NWEC): I agree with your view that the WRAP is still on spec to some
degree, I think we are finally really seeing that. The other thing that really bothers me

Appendix A
about the WRAP is for those of us who are not, you're in the program. For those of us
who are on the outside, there is no information. We have zero information about this
showing period. Even though it's a voluntary season showing period, we don't know what
the total amount of load resources UCC by resource category, PRM, any of it and that
bothers me a lot.
James Gall: OK. We have about one minute left. Any last questions or comments before
we call it a day? OK. We're going to cover Lori's presentation on loads and resources at
the next TAC meeting. Hopefully we can get to it. We all saw the transmission and
distribution hopefully be able to cover all three of those. We're also going to be meeting
internally over the next couple of weeks and hopefully we'll have some of these
assumptions of nonmarket, decided upon then. If not, we'll discuss it at our TAC meeting
again next time. Thank you for coming today and we'll see you in two weeks and have a
great day. And if you can come to the natural gas TAC meeting tomorrow.
Charlee Thompson: Thank you.
Dean Spratt: Thanks. Good job guys.
Teams Meetinq Chat Content:
[8.48 AM] Fred Heutte (NWEC): Thanks this is a really interesting NREL study with
assistance from Ecotope. 4 of the 13 sites are in the Spokane Valley, most of the rest in
SE WA, and lots of very detailed per-site results. like 1
[8.49 AM] Fred Heutte (NWEC): correction 7 of the 13 in Spokane area
[8.56 AM] Unknown User: Since pumped hydro likely qualifies for the 10% domestic
content bonus ITC, total should probably be 40% for pumped hydro. Batteries would
presumably not qualify due to foreign sourcing remaining dominant.
[9.06 AM] Unknown User: Do these factor in the different Iifespans? With Li-Ion at 15
years and pumped storage at 60-100 years, the comparative levelized cost of storage
should be lower for pumped storage even if up-front cost is slightly-to-somewhat higher
(using 8 hours as the basis of duration), even if you only used, say, 50 years (the usual
initial term of a FERC license). ALSO, why does it jump at 2032? IF it's related to the
ITC cliff, the ITC essentially lowers capex so permanently lowers annual cost.
[9:13 AM] Unknown User: Thank you.
[9:26 AM] Unknown User: I coordinated a study of the economic and employment
impacts of small modular nuclear reactors back in 2010 using IMPLAN, which might be
helpful. Here is a link to the tudy: https://www.nrc.gov/docs/ML1802/ML18023A166.pdf
[9:43 AM] Slagboom, John Calvin (Guest): NERC is forecasting insufficient operating
reserves in multiple markets, in above-normal

Appendix A
conditions. https://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/NER
C SRA 2024.pdf
MRO
tit�,a,pc'L:Pr
1% WECC
B
NPCC
New England
WECC
CA/MX Key
WECC ■High Risk
YA, Texas RE MI SO ■ Elevated Risk
FRCOT
Figure 1: Summer Reliability Risk Area Summary
Potential for insufficient operating reserves in normal peak conditions
Potential for insufficient operating reserves in above-normal conditions
Sufficient operating reserves expected

A endix A
Vop
2025 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 9 Agenda
Tuesday, June 18, 2024
Virtual Meeting — 8:30 am to 10:00 am PTZ
Topic Staff
Introductions John Lyons
Loads & Resources Discussion Lori Hermanson
IRP Generation Option Transmission Planning Studies Dean Spratt
Distribution Planning and Microgrids Damon Fisher

���r r/ISTA
2025 IRP TAC 9 Introductions
John Lyons, Ph.D.
Technical Advisory Committee Meeting No. 9
June 18, 2024

Appendix A
Today's Agenda
Introductions, John Lyons
Loads & Resources Discussion, Lori Hermanson
IRP Generation Option Transmission Planning Studies, Dean Spratt
Distribution Planning and Microgrids, Damon Fisher
2

Appendix A
Remaining 2025 Electric IRP TAC Schedule
• Technical Modeling Workshop: June 25, 2024: 9:00 am to 12:OOpm (PTZ)
o PRiSM Model Tour
o ARAM Model Tour
o New Resource Cost Model
• TAC 10: July 16, 2024: 8:30 to 10:00 (PTZ)
o Preferred Resource Strategy Results
o Washington Customer Benefit Indicator Impacts
o Resiliency Metrics
• TAC 11 : July 30, 2024: 8:30 to 10:00 (PTZ)
o Preferred Resource Strategy Results
o Portfolio Scenario Analysis
o LOLP Study Results
• TAC 12: August 13, 2024: 8:30 to 10:00 (PTZ)
o Preferred Resource Strategy Results (continued)
o Portfolio Scenario Analysis (continued)
o LOLP Study Results (continued)
o QF Avoided Cost ins

Appendix A
Remaining 2025 Electric IRP TAC Schedule
• September 2, 2024- Draft IRP Released to TAC.
• Virtual Public Meeting- Natural Gas & Electric IRP (September 2024)
o Recorded presentation
o Daytime comment and question session (12pm to 1 pm- PST)
o Evening comment and question session (6pm to 7pm- PST)

���r r/ISTA
2025 IRP Loads & Resources Discussion
Lori Hermanson, Senior Power Supply Analyst
Technical Advisory Committee Meeting No. 9
June 18, 2024

Portfolio
Realignment
Chelan 1-87.5 MW
6.
Chelan 2-87.5 MW
Chelan 3-87.5 MW 175 MW
Douglas PUD-24MW
CBH-Russe
CBH-EBC 4.6 -2.2 MW
CBHSummer Falls-94 MW
CBH-PEC 66-2.4 MW
CBH Quincy Chute-9.4 MW
CBH-Main Canal-26 MW
CBH-PEC Headworks-6.2 MW
Palouse-105 MW
Rattlesnake-144 MW
Clearwater Wind-97.5 MW
Adam on Solar-19 MW
ELF ISolar-19 M
Lancaster CCCT-283 MW
Northeast-66 MW
. •.
Paper
20242025 • 2027 2028 • 2030 2031 20322033120351 • 2037 : 2039 2040 2041 2042 204320441

Appendix A
Monthly Net Energy Position
Jan' Feb Mar Apr May Jun Jul AugSep Oct Nov Dec Annual
2026 25 26 175 348 696 508 177 78 200 171 63 22 204
2027 1 54 209 381 750 553 226 133 254 215 94 57 244
2028 7 96 209 374 743 551 219 126 255 219 98 51 245
2029 9 87 234 401 760 563 221 122 258 227 106 67 255
2030 13 86 234 394 754 561 217 121 254 227 105 69 253
2031 16 97 245 398 768 579 231 125 264 229 108 72 261
2032 21 142 251 405 769 580 223 122 257 227 102 72 264
2033 14 103 252 399 765 571 214 112 253 226 105 71 258
2034 44 64 205 344 696 509 161 60 210 184 44 12 204
2035 65 54 195 337 690 500 148 45 195 167 32 5 192
2036 76 88 186 326 677 484 133 33 182 154 11 17 182
2037 91 37 170 307 665 473 119 16 170 146 5 32 165
2038 110 18 148 290 639 439 73 16 148 124 23 57 140
2039 129 6 138 272 622 419 52 35 138 110 37 71 124
2040 131 29 126 260 612 387 29 57 120 93 46 105 110
2041 246 134 20 148 510 272 108 179 9 16 160 214 8
2042 525 402 244 34 323 82 372 433 248 271 415 489 252
2043 585 462 313 103 272 29 426 485 298 328 485 562 312
2044 617 445 339 132 249 2 464 516 321 347 510 594 336
2045 798 664 510 246 151 93 612 666 473 505 677 764 488

Appendix A
Proposed CETA's Clean Energy Goals
100%
95% Alternative Compliance
■Expected Targets
90%
85%
MO 80%
- 75%
T �M
O 70%
65%
60%
55%
50%
2026 2027 2028 2029 2030-33 2034-37 2038-41 2042-44 2045
4

Appendix A
Washington Clean Energy Position
1,200
Idaho Legacy Hydro Available
for Alternative Compliance
1 ,000
Washington
CETA Primary
Load Estimate
Compliance
Washington —
800 Retail Load — CETA Shortfall
600 Idaho Allocated
Clean Energy
Transferable to
i Allocated Wind Washington
Q 40
Allocated Biomass Allocated
Allocated Solar
Allocated Hydro Ener renewables
0
(. f- 00 M O N CO U') O rl- 00 O O N M Ul
N N N N M CO CO CO CO CO CO CO CO M It It
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N

Appendix A
Capacity L %R Discussion Issues
• Avista is not settled on capacity planning assumptions
• LOLP studies indicate a need for increased planning margin or higher
market reliance.
— Current market reliance limit is 330 MW in "constrained" hours
— Avista's main challenge is energy limited capacity resources
• Other capacity planning issues under consideration
— Maintenance planning
• Historically maintenance is not included in L&R planning due to uncertainty on timing and number of units out
year to year
• Should we plan for a minimum maintenance assumption?
— 3rd Parties in our control area
• Should we plan for 3rd party load and transmission schedules who under schedule during peak events?
— Should we use an alternative capacity planning methodology
• For example, low water, low VER, and high load event
6

Appendix
000-
Integrated Resource Plan (IRP)
Transmission Planning Studies
Dean Spratt, Transmission Planning
Technical Advisory Committee Meeting No. 9
June 18, 2024

Appendix A
SRC Standards of Conduct
Summary of requirements
• Non-public transmission information can not be shared
with Avista Merchant Function employees.
• There are Avista Merchant Function employees attending
today.
• We will not be sharing any non-public transmission
information. Avista's OASIS is where this information is
made public.
2

Appendix A
Agenda
• Introduction to Avista System Planning
— Useful information about Transmission Planning
— Overview of recent Avista projects
• Generation Interconnection Study Process
— Integrated Resource Plan (IRP) Requests
— Large Generation Interconnection Queue
— Third year into the Cluster Study Process
3

Appendix A
Introduction to Avista System Planning
Avista's System Planning Group includes:
• Distribution Planning
• Transmission Planning
— Focus on reliable electric service
• Federal, regional, state, and local compliance
• Regional system coordination
— Provide transmission service and system analysis
• Planning for load growth and a changing generation mix as
well as dispatch
• Interconnection of any type of generation or load
— We are ambivalent about type (must perform though)
r
4

Appendix A
Information About Transmission Planning
• Our focus is the Bulk Electric System (BES)
— Avista's 115 kV and 230 kV facilities (> 100 kV)
• We identify issues where Avista's BES won't
reliably deliver power to our customers
• Then we develop plans to fix it
— "Corrective Action Plans"
— Mandated and described in NERC TPL-001 -4
• We live in the world of NERC Mandatory
Standards
— Energy Policy Act of 2005
5

Appendix A
NERC Standard TPL-001 -
• Describes outage conditions we must study
— P0: everything online and available
— P1 : single facility outages, like a transformer
— P2, P41 P5 & PT multiple facility outages
— P3 & P6: overlapping combination of two facilities
Table I-Steady State&Stability Performance Planning Events Interruption of Non-
Steady State&Stability: Category Initial Condition Event' 2 rm C.n:quential
a. The System shall remain stable.Cascading and uncontrolled islanding shall not occur. Service Allowed Allowed
b. Consequential Load Loss as well as generation loss is acceptable as a consequence of any event excluding P0. PS Delayed Fault Clearing due to the
C.
Simula - - failure of anon-redundant EHV No' No
d. Simula Multiple Contingency component of a Protection System''
e. PlanneCategory Initial Condition Event Fault Type 2 BES Level 1 Fir Transmmion
in (Fault plus protecting the Faulted element to
are ne Service Allowed non- operate as designed,for one of the
Steady State PO redundant Normal System following: SLG
_ _ component 1.Generator
f. Applic No Normal -- --- ofa 2.Transmission CircuitHv Yes Yes
ContingencY Systern g. Event Protect ion
3 Transformer'rs
Coordi System
h P failure to 4 Shunt Devce°
lannii PI operate) 5. Bus Section
I. The re'. Single Normal! Loss of one of the following:
used ti Contingency Loss of one of the Loss of one of the following:
1. Generator
Stability Only', P3 Loss of generator unit 2. Transmission Circuit 30 EHV,HV
j. Tronsi, Multiple followed by System 3. Transformers Multiple Category Initial Condition Event' Fault Type 7 BES Level 'I Con sequential
Contingency adjustments° Continge Tir—nnission Load Loss
4. Shunt DeviceeService Allowed Allowed
_ (Two
S.Single pole of a DC line SLG overlopp P7 The loss of:
P2 Loss of multiple elements caused by singles) MultlPle 1. Any two adjacent(vertically or
Single Normal! a stuck breaker-(non-Bus-tie ____EHV Contingency Normal System horizontally)circuits on SLG EHV,HV Yes Yes
Contingency -------- --- Common common structure"
Breaker)attempting to clear a Fault (
on one of the following: Structure) 2. Loss of a bipolar DC line
P4 1. Generator SLG
Multiple 2.Transmission Circuit HV Yes Yes
Contingency Normal System 3.Transformers
(Fault plus 4. Shunt Devices
stuck
breaker!') 5. Bus Section
6. Loss of multiple elements caused z
6 by a stuck breaker1q(Bus-tie SLG EHV,HV Yes Yes
Breaker)attempting to clear a
Fault on the associated bus

Appendix A
TPL=001 =5, cont.
• A couple of NERC directives for the above faults
— "The System shall remain stable"
• Cascading and uncontrolled islanding shall not occur
— "Applicable Facility Ratings shall not be exceeded"
• Equipment ratings, voltage, fault duty, etc.
— An objective of the planning process is to minimize
the likelihood and magnitude of Non-Consequential
Load Loss following planning events"
r
7

Appendix A
Two Approaches tn Reliability Issues
• Transmission Operations (TO) are guided by
significantly different standards than
Transmission Planning (TP)
• TO standards provide flexibility that TP
standards do not allow
— Operators can push system limits to SAVE the
interconnected system
• Shed load, overload equipment, etc. — all short term
• The planned system should give them the tools to do this
• The standards continue to define this balance
8

Appendix A
Standards are a Roadmap
• Western Systems Coordinating Council (WSCC)
— Ensure that disturbances in one system do not spread
to other systems.
• Operating agreement with 40 electric power systems
established in 1967
• Western Electricity Coordinating Council (WECC)
— Responsible for coordinating and promoting electric
system reliability established in 2002
• North American Electric Reliability Council (NERC)
— Ensure the reliability of the North American bulk power
system reformed in 2006 ; Corporation in 2007
• Established as a voluntary organization in 1968
9

�•Cne;;eian Santl c�•t
\ P
COLVI 1 E RESERVATION
ott Sa^, ro'nx-Cabinet 115 V
increase qp4&pity
~ �Li
own
Grand COWee' �•U_... i w '-•Alhc \ ''
estside /115 kV 1
L rease ca city ,: Irvin 115 kV 4 Tr
Wilbu1. ; i
Switch' Station ,
P ALy s'�/•PasF'
•Coulee Gt S - —q::�yipe gnt • ,bane• ek`nelValiey l/./�`•C eAlene
Sunset 115 kVi /•
?� `'• r' increase_capacity 115'kV 4n ergfound
4R" ��• cable-re lacements
•oaese "" CDA-PIN 115 kV
Adam Neilson s COEUR JALENE RES_Rk k increase capacity
Solar(19 MW)
Ling-Warden Palouse
iocr s_ Cs Wind (1iO4 MW)
} ' .gi
n• Rattlesnake Flat' ��`4•��J
" Wind(144 MW)
• OtIF
0 �� I ,I �• -, \
inci as rel'abili N on 115y kV �� •P o ow 230/115 kV
�' ` switching station increase capacity
SaddleMt 230 5`k
L
new, acity
BNT-OSS 115
increase capacity �$ `A•'
�� ' EL PERCE RESERVATION
.� >n• Lolo 230/115 kV
^� increase capacity
�./ •Kr00�+id
i] ram..��_ .- '7•. 1
•Cotton':cotl
�� --' -. _ - _T� � 1 •Ciea•v.atcr
1

Appendix A
Non -Wire Alternatives are Considered
• We are documenting this with more clarity
• Non-wire options require robust wires to perform
— Avista is working on the transmission fundamentals
..-•o
• . .
Nam
PUSH ••.
o ® -
0 SmartValve
11

Appendix A
Evaluated Batteries for T=1 =1
• TPL-001 -5 ~ T- 1 - 1 for long lead equipment
— Double transformer outages
• Shawnee 230/115 kV outage followed by a concurrent
outage of Moscow 230/115 kV transformer.
— Could we mitigate performance issues with storage?
• Yes. . . but. . . We would need a 125 MW battery
— Typical charge is 8 hours, discharge for 12 to 16 hours
— Transformer outage is weeks to months
• A third transformer is a better solution
Robust performance and much less $$$$
Requisitions:Requisa.�-s
Requisition 162964
Description M08-Westide 250/280MVA,230-115-13.81W,three
phase auto transformer. Status Approved
Created By Wilson,Barnes Scott(Scott) Change Fismry NoUrgent Requisition No
Creation Date 12/06/2017 12:49:35
Deliver-To One Time Shp To Attachment View
Justification This is the second transformer associated with the Note to Buyer Quote attached.Bid evaluation sheet pre
Westside Substation rebuild. Shelly Campbell
Details
Line
Description Need-By Deliver-To Unit Quantity Qty Deivered Qty Canceled Open Quantity Price Amount(LISD)1
1 250/280MVA,230-115-13.8W,three phase auto transformer. 10/03/2018 12:51:34 One Time Ship To Each 1 1 0 0 2397826 USD 2,397,826.00
2 SFRA Testing at factory and field 10/03/2018 12:51:34 One Time Ship To Each 1 1 0 0 5400 USD 5,400.00
Total 2,403,226.00
12

Appendix A
Generation Interconnection Study Process
Process for Generation Requests
• Two sources:
• External developers
• Enter via the OATT
• Internal IRP requests
• Feasibility Study. . .then OATT
• AVA Merchant MUST follow the OATT just like external parties
• Typical process:
• Hold a scoping meeting to discuss particulars
• Outline a study plan
• Augment WECC approved cases for our studies
• Analyze the system against the standards
• Publish findings and recommendations
13

Appendix A
Transition to Cluster Study Process
Challenges with Serial Interconnections
• Large serial queues become difficult to process
efficiently
• Interdependency of projects becomes complicated
• Studying single projects is inefficient compared to
studying projects in a group
• Projects that do not reach commercial operation may
cause re-studies
• System Upgrade allocation
• The serial process is difficult for the developers and the
utility
Transition to Cluster Study process in 2022
14 W=

Appendix A
Serial Process was Complex and Slow
FERC Timeline 45 Days 90 Days 90 or 180 Days
System Impact
® Project#1 QFeasibility StudyQStudy QFacilities StudyQ
Project#2 QSystem I my pact Q Q
0 0stem
Project#3 Feasibility Study Study '
Interconnection Requests necessitated a better Process
Active Interconnection Requests by Year
45
40
35
30
25
20
15
10
5
0
2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024
15

Appendix A
Two-Phase Cluster Study Process
Benefits and Objectives
• Create a more efficient process
• Design a process with definitive timelines that can be
consistently met
• Allocate System Upgrades proportionally
• Ensure commercially viable projects have a clear path for
development
• Alleviate the backlog in the queue
VA.4 Phase One N, Phase Two Individual
Study Study Facilities Studie
16

Appendix A
Current Interconnection Queue
Serial or Point of Interconnection MW
Output
059 Roxboro 115kV 60.0 Solar/Storage Adams WA
Q60 Dry Creek 230kV 150.0 Solar/Storage Asotin WA
Q63 Post Falls 115kV 26.0 Hydro Kootenai ID
Q66 Kettle Falls 115kV 71.0 Wood Waste Stevens WA
Q97 Lolo 230kV 100.0 Solar/Storage Nez Perce ID
TCS-03 Warden 115kV 80.0 Solar/Storage Adams WA
TCS-14 Dry Creek 230kV 375.0 Wind/Storage Garfield WA
CS23-06 Shawnee -Thornton 230kV 255.9 Wind Whitman WA
CS23-12 AVAHub-04 230kV 199.0 Storage Franklin WA
CS23-13 Davenport 115kV 40.0 Solar Lincoln WA
CS23-14 North Fairchild Tap 115kV 40.0 Solar Spokane WA
CS24-01 South Othello 13kV 1.1 Solar Adams WA
CS24-02 Third & Hatch 13kV 0.5 Storage Spokane WA
CS24-03 Saddle Mountain 115kV 150.0 Storage Adams WA
CS24-04 Benewah 230kV 100.0 Storage Spokane WA
CS24-05 Rathdrum 230/115kV 203.0 Natural Gas CT Kootenai ID
CS24-06 Bronx 115kV 120.0 Natural Gas CT Bonner ID
CS24-07 Othello 13kV 2.0 Solar Adams WA
CS24-08 AVAHub-04 230kV 199.0 Solar/Storage Franklin WA
CS24-09 Othello 13kV 9.5 Solar Adams WA
CS24-10 Spangle 115kV 80.0 Solar/Storage Spokane WA
CS24-11 Thornton 230kV 70.0 Solar Whitman WA
CS24-12 Shawnee - Sunset 115kV 40.0 Solar Whitman WA
CS24-13 Benewah -Thornton 230kV 95.0 Solar Whitman WA
CS24-14 South Fairchild Tap 115kV 40.0 Solar Spokane WA
CS24-15 Bluebird 230kV 300.0 Wind/Storage Lincoln WA
17

Appendix A
Generation Integration Cost Estimates
Generation Integration at New sites
F- Requested Pol Cost
11301 StationorEstimate
• . • '
Big Bend area near Lind (Tokio) 100/200 230kV 127.8
Big Bend area near Odessa 100/200/300 230kV 170.5
Big Bend area near Othello 100/200 230kV 216.8
Big Bend area near Othello 300 230kV 258.7
Big Bend area near Reardan 50 115kV 9.7
Big Bend area near Reardan 100 115kV 12.8
Lewiston/Clarkston area 100/200/300 230kV 1 .9
Lower Granite area 100/200/300 230kV 2.9
Palouse area, near Benewah (Tekoa) 100/200 230kV 2.4
Rathdrum Prairie, north Greensferry Rd 100 230kV 34.0
Rathdrum Prairie, north Greensferry Rd 200/300/400 230kV 51.9
Sandpoint Area 50/100/150 115kV 1 .6
West Plains area north of Airway Heights 100/200/300 230kV 2.4
18 Preliminary estimates are given as -25%to +75% ,

Appendix A
Cost Estimates, continued
Increase in Capacity or Additional Generating Facilities at
existing generation sites
Requested POI Cost
POI Station or Area (MW)
Voltage
million)
Kettle Falls Station 50 115kV 1 .6
Kettle Falls Station 100 115kV 19.0
Northeast Station 50 115kV 1 .6
Northeast Station 100 115kV 7.7
Palouse Wind, at Thornton Station 100/200 230kV 1 .4
Rathdrum Station 25/50 115kV 11 .1
Rathdrum Station 100 230kV 15.9
Rathdrum Station 200 230kV 40.5
19 Preliminary estimates are given as -25%to +75% ,

Appendix A
ReardanIm 100 MW
Choice of interconnection point may result in extensive
system reinforcements
.0 Mw
LO1N.0G0L6A pT 3.0 Mar
LITTFALL
1.007 pu
1MW 1.6 41 LONGLAKW
.7 ,
BLS
- 0.0 Mva 1.007 pu 1.0]
0.0 Mvar NINEMILE
jy.� 1--�21 MW 1.005 Pu I
1 Mar DEVILGPW DEV LGPE _ �_U 5 War 7 MW
8 MW 1.006 pu 1. 6 pu 21 MW 1 Mvar
d 1 War 5 War 7 MW I
1 War
8MW ��21 MW I •_•_•-
1 Mvar �I�_.�`� 4 War 7 MW
d 1 War �` 21 MW
2 War G;J 7 MW MVIr
LONGLAKE 1 War INDTRAIL
I.Oqeu 93% 1.006 pu
.� 4.4 M W
0.1 War
— ►F — ►4 — -•� - —•c — — — - r -IE - —
7
-•'<•I� -X- <-•-----�E•-®-•'<•-•-•-••- -
I I I
LARENE+ SPRNGHIL
1.019 PO 1.015 pu
-K- ----------A -^� -----f-' .--------
2 MW 100 MW 6.5 MW X
1 Mvar -32 War 2.1 War I
I
REARDAN
1.017 pu SEVENTA
1.010 pu
20MW �AIKIKI
0M W13 1.014 pu0. var 2P 1 MW
0.3 War
WE
n �v
0 0 WEST
1.008 Pu
20

Appendix A
Espanola : 100 MW
Optimizing the interconnection point is a key benefit of the
Cluster Study process
- 16.4 mw POSTSTRT
0.0 War FLINT RD
0.9 War 1.016 pu
1.015 pu
0:2 M W
0.2 War
AIRWAY T 3.0%rv.r
9 MW 14 MW
1.015 pu1.4c 1 War 0 War
0.1 MW 10.0 MW SPKWASTE METRO
0.1 Mvar0.2 War ` 1.015 pu 1.016 pu
FAIRCHLD GARDENSP '_f� 16 MW
O15 pu RUSSELL RD 1.03 pus �` 'J 1 War 7.2 MW
2.8 Mw 0.1 Mvar
0.0 Mvar
a AVAQ80PV " ` 04.6 War
Espanola +-- 0 MW i -1 GARDENSP �-y. SUNSET
FAIRS 0 Mvar 1.015 pu 1.016 pu
100 MW 1.014 pu CR .01 RD
1.014 pu
-17 1.5 MW � � 0 MW 19.3 MW
0.0 War 0 War 0.9 War
5.1.0 MW War 1A T
HAYFORD
HAL&WHIT FOURLBPA 1.014 pu
1.014^i 1.014^� 7
SILVRLK2 SILVRLA 8.9 MW oa
1.017pu 1.014p 0.2War
2.5 MW
0.0 Mar
5.5 MW 4.7 MW
0.1 War 0.1 War
HANGMAN
1.015 pu
MELVILLE
1.014 pu 7 0.6 MW
.1 War
21

Appendix A
Questions?
Refer to Avista's Open Access Same-time
Information System (OASIS) link for information
regarding System Planning and the Interconnection
Process at:
http://www.oasis.oati.com/avat/index.htmi
Generation Interconnection (Serial)
SE] Generation Interconnection Cluster Studies
J 2022 Cluster Study
j 2023 Cluster Study
i� 2024 Cluster Study
►i Application Documents
22

Appendix A
North Plains Connector
- - ----:r
11MCI County
t '
I
tuucr ' '
- - ---- - - - - ; -♦ i •ickinsuri Mandan
•� - - - - 1 rl I IgRTOM SBISMarck
Mlles city •_. t
rton
• ♦ I Bakel
N6161 ti HL1011 I WMT — i r County
+v
I 1 L
Project's route is under active development
i
and is subject to change.
• 2025 IRP will model this transmission expansion as a capacity market resource up to 300 MW.
• QCC will be limited to the difference between line rating and Montana Wind QCC.
0 Project can be selected beginning in 2033 or any year thereafter.

�� VISTA°
Distribution Planning and Microgrids
Damon Fisher, System Planning
Technical Advisory Committee Meeting No. 9
June 18, 2024

Appendix A
Goals of Electric Distribution Planning
• Ensure electric distribution infrastructure to
serve customers now and in the future with a
focus on :
— Safety
— Reliability
Capacity .
— Efficiency
— Level of service q ' -
- Operational flexibility
p Y
— Corporate/Regulatory goals
r
— Affordability
2

Appendix A
What is a Microgrid ?
. What is a microgrid ?
. Same as a "macro" grid but smaller (self similar)
. Maintain Voltage and Frequency within limits
. Respect Thermal Limits
r }
. Load = Generation "
. Protected equipment
x
r
3

Appendix A
What is a Microgrid ?
North American Regional
Reliability Councils
and Interconnections
NPCC FRCC 0 THE tones
,�;1 Intorconnedion
P RFC 0 MRO P WECC `t
L
SERC 0 SPP ASCC
------- Int.rconnectlon '
Sauce:North A—d—RBMMY Coroornlon
4

Appendix A
What is a Microgrid ?
• Major equipment-
. Microgrid Controller and Communications
• Generation (PV, Wind, Thermal, Fuel Cells. . . etc.)
• Storage and/or dispatchable source
• Grid disconnect switch
• Major functionality-
Black start capable
• Island mode
• Grid Synchronization
• Managed Demand
r
5

Appendix A
Why a Microgrid ?
Typically, one of four reasons or combination of them-
1 .
• Critical Load
• Essential Service
2. Economic
• Demand charges
• Energy arbitrage
• Other utility services
3. Climate goals
4. Difficulty serving load or getting service
• Remote/isolated
r
6

Appendix A
Microgrid as a resource
• A microgrid is a black box that the utility can ask for
help. That help will usually be in the form of reduced
demand or increased generation .
Depending on the goals of the microgrid and the current state
of the system the microgrid controller may say-
. 1 can't help
• Sure, here you go
• Sure, I am going into island mode
• The incentives/agreements between the microgrid
owner and the utility will greatly influence the answer.
7

Appendix A
Avista, and Microgrids
• Avista has a couple of microgrid projects.
— WSU Spokane campus (demonstration/pilot)
• Solar + Battery
— MLK Center (Out for bid)
• Solar (115-kW do array) + Battery (500KW/1 MWh) + Natural
Gas Generator (150kW)
• Approximate cost $2.5 million (grants and matching funds)
8

Appendix A
Avista and Microgrids
ON
MLK Resiliency Center
Operated by the MLK Community Center
LSwsrw �
OFF O SOLAR PANELS:Produce clean,renewable
t✓ electricity to run the Center and charge the
batteries when grid power is out.
© BATTERY STORAGE:Powers essential
A operations during unexpected outages,
enabling the Center to function as an
eAV24V
emergency community hub.During a power
or natural gas outage you can receive the
following services and resources in your
, neighborhood:
/ / O Food bank refrigeration
A/ /
/ ®Kitchen operations
f ��� Lighting
� �♦� ter ' , Showers
►�►� MiK Comm — r F�+"" ��� u Heating&cooling
Outlets(for charging phones)
Battery storage also lessens the strain on
Avista's grid,boosting resilience.
Q GRID INTERFACE SWITCH:Disconnects the
During its regular daily operations,the MLK Center Center from Avista's grid when there is a
functions as a Tier 1 resource hub,providing the power outage,allowing the microgrid
community with access to essential support services, batteries to sustain the center
including N95 masks,bottled water,food bank independently.
provisions,and childcare.In times of weather-related Q MICROGRID CONTROLLER:Manages
emergencies,such as extreme cold or heat,the City the different modes and provides
of Spokane can turn the Center into a Tier II daytime controUmonitoring of the microgrid.
relief hub.It can then offer additional vital services, Q EV CHARGERS:Excess electricity can be
like a place to warm up or utilized during an outage to power two
cool off or find better air
•KINGS R � electric police cars stationed at MLK.
quality when needed. !..
9

Avista,
Appendix A
nd Microgrids
.+ 1
t
t`,i � � � er ingJr.Commun�tyCenter
.. —�'� Southeast Day Care Center'� 1
10

How could it be a 8/1 "
317.3
resource?
40.74
4389
247
Feeder 3HT12F5
• Mitigate a grid constraint
• Transformer
• Feeder
• Mitigate a resource +
constraint
11

Appendix A
Advantages of Microgrids
1 . Ride through grid outages for those served by the microgrid.
2. Control system optimizes resources on the microgrid for the
desired goals.
3. Billing flexibility and autonomy.
4. Grid resource options.
r
12

Appendix A
Disadvantages of Microgrids
1 . Initial costs can be high. Equipment is expensive and the systems
are custom-made designs which are complex.
2. Extra costs for the ongoing maintenance and the local expertise to
maintain it.
3. Regulatory, policy, and contractual complications.
r
13

Appendix A
Distribution PlanningAdvisory Group
• Avista's overarching Distribution Planning goals are:
• Develop a transparent, robust, holistic planning process for
electric system operations and investment
• Create a long-term plan to ensure we are maximizing operational
efficiency and customer value
• Distnuution Planning Advisory Group (myavista.com�
• Next meeting Wednesday, July 24, 2024, 9:00 AM-10:50 AM
r
14

� W
\ _
Appendix A
Questions?
log
SON
w
-1 � -
M
15

Appendix A
Avista's 2025 Electric IRP
TAC 9 Meeting Notes
June 18, 2024
Attendees:
John Annu, Fortis BC; Sofya Atitsogbe, UTC; Kim Boynton, Avista; Annette Brandon,
Avista; Moly Brewer, UTC; Kate Brouns, Renewable NW; Terrence Browne, Avista;
Logan Callen, City of Spokane; Katie Chamberlain, Renewable NW; Kelly Dengel,
Avista; Joshua Dennis, UTC; Mike Dillon, Avista; Chris Drake, Avista; Jean Marie
Dreyer, Public Counsel; Michael Eldred, IPUC; Ryan Ericksen, Avista; Rendall Farley,
Avista; Ryan Finesilver, Avista; Damon Fisher, Avista; James Gall, Avista; Bill Garry;
Amanda Ghering, Avista; John Gross, Avista; Leona Haley, Avista; Tom Handy,
Whitman County Commission; Kyle Hausman, Avista; Lori Hermanson, Avista; Mike
Hermanson, Avista; Fred Heutte, NW Energy Coalition; Kevin Holland, Avista; Clint
Kalich, Avista; Paul Kimmell, Avista; John Lyons, Avista; Austin Oglesby, Avista;
Sarah Pambianchi, Invenergy; Jared Schmautz, Avista; John Calvin Slagboom, WSU;
Dean Spratt, Avista; Victoria Stephens, IPUC; Lisa Stities, Grant County PUD; Art
Swannack, Whitman County Commission; Jason Talford, IPUC; Charlee Thompson,
NW Energy Coalition; Taylor Vallas, Invenergy; Bill Will, WASEIA; Yao Yin, IPUC; Cole
Youngers, Avista.
Introductions, John Lyons
John Lyons: Alright, so again, welcome to our TAC meeting. Today we're focusing
on load and resource discussion. That was the one Lori is going to pick up. We ran
out of time, last time we had such a good discussion. Dean Spratt's going to be talking
about transmission projects and all of the work that goes in from that side of the
company and what we're putting in for that. Damon Fisher is going to talk about
distribution planning and specifically about microgrids. James, did you want to go
through some of what we've got for upcoming meetings?
James Gall: Yeah. So, slide deck, our next TAC meeting is going to be a modeling
seminar. I believe that's on the 26t" or 27t" John, so it's one of those.
John Lyons: Yeah.
James Gall: Fortunately, we're confused. There's a gas TAC meeting, I think on one
of those days and the electric on the next one. But anyway, the plan is to go through
the PRiSM model. We plan to have a version of that posted either Friday or Monday
on Teams to look at prior to the TAC or the modeling session, and then we'll go through
that model and how it works. We'll also go through the new resources spreadsheet so

Appendix A
you can see how our assumptions are derived for our new resource cost as Michael
Brutocao went through last week, and then we'll also get into our ARAM modeling,
which we're still working on. Look forward to that and then the next TAC meeting will
be after the Fourth of July. We're going to skip the next two weeks and then I will be
showing our Preferred Resource Strategy and our capacity need at that meeting Lori
kicked off here in just a second. We're going to talk about our L&R position. We're
going to be mostly focusing on energy and renewable needs, but we're going to have
some discussion time on capacity needs as well. So, let's skip going. Go ahead, Lori.
If you want to pull it up, slide mode. There we go.
Load & Resource Position, Lori Hermanson and James Gall
Lori Hermanson: I'm Lori Hermanson, Senior Power Supply Analyst in James' group.
As he mentioned, we're going to talk about our loads and resources positions. Since
our last IRP, we've had a couple of RFPs, that renewable RFP and an all-source RFP.
We've acquired quite a few resources since then, and this is an overview of our
resources and what's coming online, what's either expiring or retirements. To start at
the top, we've had an ongoing slice of Chelan, 87.5 megawatts and that's been on our
books for a while, but that will expire in 2030. A second slice started at the same
percent or the same amount 87.5 megawatts, and that will expire in 2033. We have a
third slice that we acquired about the same time and that starts in 2026 and then in
2030 when the first slice expiring, that third slice will jump up to 10%, so 175
megawatts. We have a small Douglas, 24 MW, a contract that expires in 2028. To help
us with our summer capacity, we acquired a contract with Columbia Basin Hydro and
there's 7 projects that come on at varying times and you can see those there and those
will extend through the end of the planning horizon to 2045.
Lori Hermanson: We have some ongoing wind, Palouse and Rattlesnake, and we've
added recently, and it was a need in our last IRP that we added Clearwater Wind for
just under 100 megawatts and that will go through 2045. We have Adam Nielson Solar,
a 19 MW project and that expires in 2040. I'm sorry, in 2038, that expires 2038. And
then also solar is a new 119 megawatts that's coming online or projected to come
online mid-2026 and will continue through about 2040. Boulder Park Solar will be
expiring, projected to expire in 2040.
Lori Hermanson: As you know, Colstrip is going offline for Avista at the end of 2025.
So that's 222 megawatts. Kettle Falls CT will expire in 2040. Lancaster is really a
contract extension. It's on ongoing now through late 2026, but with this recent contract
will continue through 2041. And finally, Northeast, that retirement we're projecting that
it will be through the end of 2029, but any of this could be updated, so that could go
offline sooner, but that's what we're projecting right now. Rathdrum units one and two

Appendix A
of 176 megawatts we anticipate won't be retired until 2045, right before we have to be
100% clean. And Stimpson is a smaller industrial customer that 5 MW load and
generation, that will go offline. Actually, they made an announcement earlier this year
that they're going out of business and will no longer be generating. We have a recent
contract with Inland Empire Paper for 30 megawatts of demand response and that's
on our books until 2031. And then there's a couple of sales, one of bundled RECs and
then the Morgan Stanley Clearwater Paper sales. That's an overall look at our
resources and when they're being added and taken off for retirements or expirations
of contracts.
Fred Heutte: Yeah, just a couple clarifying question or one clarifying question.
Could you just say what kind of resource Northeast is?
Lori Hermanson: It's a pecker, isn't it?
James Gall: Yeah, it's an aero derivative natural gas turbine.
Fred Heutte: OK, for some reason I didn't know about that. That's fine. By the way,
this Fred Heutte, Northwest Energy Coalition.
James Gall: Yeah.
Fred Heutte: Good morning, everybody. Also, congratulations on the 30 MW DR
contract. That's looks like a good one. Thanks.
Lori Hermanson: Thank you. This has helped out a couple of times in the last couple
of years. OK, so here's our energy position. It's as you can see on an annual basis,
we're in good shape, especially with those most recent acquisitions. But there are a
few months where we're short. An example of that is January 2026 and that's related
to one of those sales that I mentioned at the bottom of our last slide. As you know,
we're participating in the non-binding WRAP program. The forward showing winter
periods for November through March and the summer periods are June through
September. Basically, the region is shifting or intending to shift most of the
maintenance to those shoulder months. If we were to include maintenance of this, you
might see some more shortages in generally those shoulder months, but sometimes
they'll be something that occurs in those winter or summer periods. But that's all I have
to say there. James, do you have anything else you want to add on this one?
James Gall: Yeah. This is our monthly net energy position and what is kind of
surprising for the last IRP, we were expected to show a lot of length after the last RFPs

Appendix A
where we had when we acquired Clearwater Wind and Lancaster. Now we're showing
a slight deficit for a few years and nearly 2026 through 2029 in January. This is a little
surprising to us. It's really driven by a large amount of load increase and our load
forecast in the January time period. So, we're trying to think about how do we solve
this small issue from an IRP perspective? We don't necessarily think it's a good idea
to acquire resources for such a small position, but it does demonstrate that we are in
a kind of a deficit period. I know in Washington State if there is a deficit period, we are
required to do an RFP but so this got us asking some questions internally about how
do we want to handle this small deficit. We haven't shown yet the capacity deficits.
We're going to probably share that again. Like I mentioned earlier in July, we're still
working through that analysis. We may show deficits early on in the plan. We may not.
That's yet to be determined, but with these deficits, it does have a consequence from
issuing an RFP. It's something we're looking at if we want to go to next slide. But before
I go there, are there any questions on what's been presented so far on where we're at
on energy position? OK, alright.
James Gall: Should we also on this last one, I think we touched that last TAC meeting,
but maybe just remind everybody we're projecting relying on the market for 330
megawatts, but that's another thing that you know could be up for discussion is
whether or not they should be relying more or less with everybody being in the WRAP
and shifting maintenance to the similar times and that kind of thing.
James Gall: We are going to talk a little bit about clean energy and then we're going
to shift back to capacity really quick. We proposed CETA targets for this IRP. These
are the same targets we used in the 2023 IRP as well. I guess the next four years, the
official targets will be part of the CEIP process, but this is what our proposal is into that
CEIP process. 66% in 2026 moving up to 76.5% by 2029. And then obviously meeting
the 80% target by 2030. And 2030, that's when the 4-year period starts and we're
proposing to go from 80% to 85% in the next 4-year period, then 90%, 95%, and 100%
by 2045. Again, these targets will be discussed again in the 2029 IRP, at least after
2030 for that CEIP process, but this is what we're assuming to date. We will be
modeling a couple different scenarios with different targets we agreed to in the last
CEIP process. How our model works? It will be trying to target this amount of clean
energy over either the year before 2030 or over the 4-year period after 2030, but it
does have monthly energy targets. There's also an annual, or sorry, hourly targets.
Washington State is contemplating, in an IRP process for planning purposes in the
new rulemaking for use rules, and we're watching that to decide what we need to issue
in this IRP, if they have our rules that require hourly accounting.

Appendix A
James Gall: By the time we issued the IRP, we go to the next slide using those targets.
This slide is a complicated way of showing what our energy position is for Washington
State clean energy targets. How this works? Because Washington is quite
complicated. Unfortunately, we get kind of a complicated chart, but I'm going to start
with the black line that you see going across the table. That is our Washington State
load estimate. It starts around 800 average megawatts, but growing over time you can
see loads are very flat like we've mentioned in the previous TAC meetings, then start
to escalate as we expect electric vehicles and more electrification of buildings to
happen. But that's not what the Washington State CETA targets, at least not until 2045,
would actually use this calculation, called retail load. And what retail load is, actually,
it's just sales plus you can remove out any qualifying facilities or PURPA contracts,
but it also lets you remove out any resources that are clean energy that's sold as clean
energy. For example, the Solar Select program is one of those. So, we reduce our
load obligation by those amounts and we our goal is actually that dotted black line. So,
where we're at today, the bars make up the different resources we have that qualify.
The light blue represents our hydro. That's allocated to State at Washington. We have
wind energy in the green allocated to Washington, and the very small slice of yellow
you have are solar and you can see that doesn't start until after our customer
agreement with the Solar Select program ends and then we'll have that resource
available for meeting CETA targets. We also have some biomass at Kettle Falls,
shown in in orange, and then that's where things start to get more complicated. We
have two states in our system and we have resources that are required to meet energy
loads. But they also qualify for CETA and in our last CEIP process, there was an
agreement that we could use energy that was allocated to Idaho or meeting
Washington law cited targets assuming that Washington compensated Idaho for those
RECs. That amount of energy is shown in gray, and the energy that we're allowing to
be transferred between states, if necessary, is newly acquired resources and Kettle
Falls. Mostly it is our wind contracts, the Columbia Basin contract, the New Chelan
contract. Those are allowable to move between states, at least in our last CEIP. The
last block is the blue block. That's our legacy hydro that's allocated to Idaho. We are
assuming that is available to meet alternative compliance in 2030, but not before using
all the resources we have available to us.
James Gall: Using an annual compliance target mechanism, we actually have enough
clean energy. Assuming this load forecast till about 2038, we have a small deficit in
2038 from a clean energy perspective. Although, if you look at monthly compliance
mechanisms or hourly compliance mechanisms, that would likely be pushed up sooner
on a monthly basis, it would likely be pushed up to about 2035. We haven't yet looked
at the hourly basis yet. We're still working on that, but that could be pushing up our
needs sooner. This doesn't mean that we expect we don't expect renewables to be

Appendix A
selected in our process sooner. There are ITC and PTC considerations. There are
actually energy considerations as well, but this is just an indication of where we're at
from a clean energy perspective.
James Gall: OK, before we go the next slide, are there any questions? OK, alright.
We're doing well on energy, but the last thing I want to talk about capacity, which is
actually something pretty difficult for us to quantify it right now. Our last TAC meeting,
we did go through some loss of load probability analysis and we're continuing to look
at that to see if we have it right because that is actually what I call the most important
assumption in IRPs — what is your resource need? We settled on our energy need.
We're now focusing on capacity and would like some advice from the TAC if you have
any to give us. Again, we've not settled on a planning capacity planning assumption
yet. Like Lori mentioned earlier, we have the 330 megawatts of market we relied on
the past. We're looking at should we keep that the same? Should we increase it?
Should we increase our planning margin as another consideration as well? We're still
running additional LP analysis and we hope to have a recommendation to the TAC for
the next TAC meeting is in July.
James Gall: We do have some questions to see if there's any response or thoughts
on. One is maintenance planning and IRPs. We've traditionally not used maintenance
in our plans. We don't want to go out and build resources for maintenance, but we do
see this come in as a bigger issue because, one, the WRAP does not let you include
resources in your L&R position when they're out on maintenance. We generally don't
want to have resources on maintenance, but it does occur. One question is, should
we plan on the IRP a minimum maintenance amount. For example, we could come up
with a schedule of maintenance in the future and plan for that. But the problem with
that methodology is maintenance changes year-to-year. You may have one particular
unit on or out, but then the next year it's another one. One option is we could consider
a fixed amount of maintenance based on the probability of what types of plants are
likely to be out during a peak event and use that as a planning criteria. For example,
we would add 100 megawatts for likely maintenance. That's one option we've been
thinking about or we could try to plan out what that means it could look like in the
future.
James Gall: Another consideration we have for capacity planning is that we do have
other utilities in our control area that we're responsible for during peak events. For
example, we have third party loads, and we have third party generation in our control
area. For example, on the third-party loads, they're supposed to provide the generation
or the energy for that load on a scheduled basis. But sometimes those schedules turn
out to be wrong. That did happen in the January event, the winter event we had during

Appendix A
the MLK weekend, where one of our extra say two of the loads in our BA under
scheduled and we had to make up for that energy that was not delivered. The flip side
could be said for generation resources in our control area where they schedule a
certain amount of generation, and that generation doesn't materialize. That hasn't
been a big issue for us right now, but it could if additional resources are built in our
control area that are not dynamically scheduled out of our system. We don't
necessarily have a recommendation on what we should plan for on this one, but it's
something we're definitely wrestling with and curious if anybody has any thoughts on
that one.
James Gall: And then the last one, should we be looking at different capacity planning
methodologies? The region and the industry has been using loss of load probability
analysis for the last 20 years. Before that, I believe we used some different technology,
different methodologies on planning margin. And I remember there was a lot of work
done on risk and I'm starting to feel like that might be a better methodology than looking
at loss of load probabilities where we would instead plan for a low water, low VER and
a high load event. That could be an alternative to looking at 5% loss of load probability
because when we run our loss of load probability analysis, we're set up pretty well to
deal with any event besides those events. And when I see that, that tells me we're
planning to fail in those events. And is that something we should be considering?
Should we be planning for something different than something more on the tail risk
area? I'm going to pause there. Are there are any thoughts on the issues that we
brought up? If I don't hear any, we're going to come up with some recommendations
at the next staff meeting. But I'd love to get your feedback if there are any before we
make any decisions. Go ahead, Art.
Commissioner Art Swannack: Yeah, my thought is you should be planning for
maintenance outage because you're running against such a tight supply system and
having that double peak now. It seems like it should be able to calculate what normal
maintenance is and maybe throw in a small risk factor for something extraordinary on
that. And then what was the last one you were talking about just a second ago?
James Gall: Yeah. Should we be planning on a risk? I'd say it had targeted reliability
where we actually plan to meet a low water, low wind, high load event instead of doing
a statistical analysis. The idea is, we estimate what that event looks like, and we plan
resources around the event.
Commissioner Art Swannack: Yeah, my thought that popped in my head is in my
experience over 50 years is when we get dry, we also don't necessarily have wind and

Appendix A
we don't have water. So yeah, you should be doing something that increases the
planning for that kind of risk. Thanks.
James Gall: Appreciate that. I saw Fred's hand up next and we'll go to Sofya.
Fred Heutte: I just want to preface this by saying that I'm a member of the WRAP
Program Review Committee and have been involved in it all along, but I also have to
say it's been difficult to have to provide input into the program development. I just want
to say I've tried but have not always succeeded. The issue of maintenance or outages,
just broadly speaking, either planned or unplanned, whatever terminology you want,
is where I never really was able to get full engagement because it's actually a pretty
important issue and there are lots of layers to it. I won't go into it here because you all
know that stuff pretty well, but I will observe one thing that I'm not sure about is
because the WRAP has a seasonal program, which is fine and does seasonal kind of
aggregate, had qualifying capacity contributions and all the rest of it, which is where
the plan maintenance goes, comes into effect. One, I'm not entirely sure. For example,
if you have a unit that's on maintenance for the first two weeks of the summer season,
you probably don't really care because you're going to have plenty of hydro around to
cover that in this part of June, but later in the summer, if you have to take it offline for
a week, ahead and not have it just be a forced outage. How does that work? My sense
is that if you looked at this basically on a monthly basis and you have to juggle assets
the risk here because of what the program requirements are. And I tell you, having
read the entire program document, I'm still wrestling with some of the details like this.
Trying to figure out, what I'm really saying is, I would not recommend taking a
maintenance headroom adjustment or whatever you want to call it for an entire
season, but rather have it basically be something like monthly. So, you're not
overburdening what you got to deal with. That was my basic input.
James Gall: Thanks. It has been a challenge. If we take a unit out for a week, for
example, like you said, in a seasonal period, we don't get accounted for that month
and it could create some challenges, especially in those shoulder months when we're
typically out on maintenance at our unit. But we also have our hydro. For example, we
could take a unit out during the low event. We don't get accounted. Most of our hydro
are 100 megawatts or less and that's where we're thinking about it. From this
perspective, the hydro units we're taking out in the summer months and the winter
events, that we're considering the larger combined cycles are typically off in the spring.
That's a little bit less of an issue, but it's mostly on the hydro unit side where we're also
looking at. Some of our units, we'll take them out for a year at a time to do major repairs
because they are over 100 years old. Something we're looking at appreciate the
comments there. I'm going to go to Sofya.

Appendix A
Fred Heutte: I just might add one thing, which is, as a member of your program review
committee, I will be very open to hearing suggestions for refining these kinds of
elements, not just the maintenance, but other things in the program design. We got
some more time now since the participants have all said let's wait till 2027 for the
binding program. But like I say, I will be very supportive of fine tuning. You know that
makes sense.
James Gall: OK. Sofya. Your hand disappeared.
Sofya Atitsogbe (UTC): Hi, this is Sofya Atitsogbe with Washington UTC. I'm
personally in support of modeling for maintenance, especially considering that at least
as resources are kind of old and require a lot of maintenance. So, if that happens, we
need to model for it. That's my personal opinion and I wanted to comment on the
alternative capacity planning methodology that Staff is in general in support of
modeling the plausible worst-case scenario, which goes well with low water, high load
event for example. That makes sense for Staff.
James Gall: Yeah. Is your support of looking at it or moving to that type of planning
criteria?
Sofya Atitsogbe (UTC): Definitely looking at it.
James Gall: OK. I'm just checking now on.
Sofya Atitsogbe (UTC): Staff doesn't have a position if we should move to it. Yeah.
James Gall: OK. That's where I check it. OK, alright. I think that is probably something
we need to present at the TAC. What that looks like if we go to that methodology just
to see what the magnitude is and I want to be careful here because we don't want to
gold plate the system. There is a market we can rely on as well. It's just we're wrestling
with is, we did have some close calls recently that we're really paying attention to. And
it's definitely in certain circumstances and it's just a matter of how we want our system
to apply. This is a regional question. The region's trying to figure this out as well, and
we know that the system is tight, but we also don't want to overbuild. Also, there's
some of the resources that we're limited to creates other challenges. We're not allowed
to build gas turbines that could create some challenges as well. Looking at just energy
storage or just renewables, so we're trying to be careful here and thoughtful, but do
the right thing as well to keep our system reliable. Art. I still see your hand up. I don't

Appendix A
know if you had a second comment, or if you forgot to take it down. Right. I guess
maybe Art left for a moment.
James Gall: Are there any last comments before we go over to Dean's presentation?
OK. I guess we will have a proposal at our July meeting for our resource capacity
need. We'll also will try to show a scenario that worst case low water, high load. What
does that look like? I appreciate the comments, especially on maintenance. We'll come
up with a proposal as well for that at the July meeting. OK, we'll move on to Dean.
James Gall: There is a question for me now. Should we test the 330 MW assumption
based on the recent market experience? We are testing what our position, or our
planning margin, would be if we move to 500 MW, we were able to get 330 MW in the
January event. Actually, we're able to get more than that from the market, but you
know I'm not sure we could have gotten it if we had prolonged outages like we saw.
What happened in January was we lost three generation units due to the gas pipeline
compressor station outage. We were able to get replacement energy for that. But as
the weekend continued, we got higher loads, but our generation returned. So, we were
not in deep with the market during the high peak event when other utilities struggled.
We're comfortable with the 330 MW. We're maybe comfortable with going a little
higher, but that's something we're testing. Alright, Dean, go ahead.
Transmission Planning, Dean Spratt
Dean Spratt: Right. Good morning, everybody. Dean Spratt. I'm in our transmission
planning department and I'm discussing today transmission planning studies. A little
bit about our group and then a little bit about generation or connection and supporting
the IRP group. Moving on, and I'll show you really quick. You can stop me anytime
during the presentation, but there'll be time for questions at the end, and we'll be
covering distribution and transmission later in the presentation. Our group, we'll start
with that one. We have lots of rules on the transmission system. That seems like a
layer on the layer, then another layer, but one of them, the first standards of conduct.
This one generally is just stating that we can't share nonpublic transmission
information specifically with our merchant group, but with anybody in real time. There
are merchant employees here today, so I will not be sharing any nonpublic
transmission information. And then our Avista Oasis site, which is Open Access, Same
Time Information System is where that information is posted. If there is any nonpublic
information, it would be posted there and these slides were posted ahead of time and
they are posted on our business integration, integrated resource planning groups
website as well.

Appendix A
Dean Spratt: Today I'm going to talk about our System Planning Group, what we do
and how we do things. Useful information about us and then an overview of some
recent larger projects, and then move on to a second portion which is the generation
interconnection study process we do for the IRP group as far as integrating generation
under transmission grid, talk about our large generation or connection queue, and then
a quick update on our cluster study process we transition to.
Dean Spratt: So, intro to our group. Within our System Planning Group, we tackle our
distribution planning and transmission planning and break that into two halves. They're
usually on a little different time frame and a little different scope of the projects, but
they do overlap quite a bit as well. We try to work together as a team to bring projects
forwards in a timely manner that makes the best sense for the company within
transmission planning. We work on reliable electric service. We're kind of unique in
the sense we have to question earlier about deterministic or probabilistic determination
of what we're going to do and how we do it. We're more on the deterministic side. What
happens if these bad things all happen? We try to put that on a piece of paper and say
from there as a corporation we want to build to that extent or not and make that
judgment call. And it's usually more of a what's best for the system and a balance of
the different areas. What can we get done and what makes the best sense for the next
step, as far as the system reinforcement, so we're held to federal, regional, state, and
local compliance standards.
Dean Spratt: And then there's quite a bit of regional system coordination. Obviously,
our transmission connects really strong with Bonneville Power Administration's, but
also the same story with our neighbors, the internal transfer customers, Kootenai
Electric is a part of. Also as an example on that, a lot of our edges either we serve that
area, or BPA serves that area, or Grant serves that area. We have a handshake with
our neighbors to help them when they have an outage by carrying their load, and vice
versa. If we have an outage, they carry our load, so that's kind of a system
coordination. That's unique to the transmission system. And then our group plans
either transmission or system loads, studies, analysis of those.
Dean Spratt: We're always paying attention to load growth. That's kind of the simple
one. It tends to grow for the most part, then the one that's a little more challenging for
our group is generation mix that's changing over time. And then also changing as
different market influences change the way to dispatch existing generation and then
the other one is just generation dispatch. Also in the last part, as far as our group doing
interconnection studies or ambivalent about the type, we try to think about is it 100
megawatts of whatever it is, be it renewables, we try to not worry about what it is. We
have more focus on how systems perform which is convenient in the IRP studies

Appendix A
because then I don't have to look to James to say what exactly do you want. To put
where you just kind of nicely says I'd like 100 megawatts in this neighborhood. And
you say no, that's going to cost you much. You need to put it in a different
neighborhood. Trying to keep it simplified that way, our bottom line is just performance
or transmission planning as a whole.
Dean Spratt: We focus on the bulk electric system for Avista that's 115 kV and 230
kV. BPA has a 500 kV network that supports us over the top of us that does long
distance transmission, transport. FERC and NERC look at the local electric system,
anything above 100 kV. That discounts the sub transmission system. Avista really
doesn't run sub transmission we're either transmission or distribution, as opposed to
other companies with a larger 69 or 46 kV system. We identify issues where this spoke
electric systems can't reliably deliver power to come to our customers and then alert
to that as we figure out how we're going to fix it. Officially, that's called the corrective
action plan. We have a system assessment performed every other year. Within that is
the projects that we believe would be the best alternative fixes to problems as soon
as we get through the system assessment. We jump into a more focused project study
where we look at a handful of really distinct alternatives and figure out which is the
best to bring forward within the company. Those are mandated and described in
NERC's TPL standards. And then I was going to always like to fall back to this. We
live in a world of NERC mandatory standards. It really became apparent after the
Energy Policy Act of 2005.
Dean Spratt: Just a quick overview of the NERC TPL standard. I'm not to go into the
detail below, but I think it's one of the longest standards within the NERC suite of
standards as far as specifying how and what we're going to look at for seasonal
studies. The years we're going to look at, 1-year, 5-year, and 10-year, I think that's
going to move out to 20 is a new change to be happening TPL standards. Then, once
we figure out what the world looks like, then we start to beat it up as the way to think
about it, the thing that really hammers the system for our point of view. We usually
start out with the P0, and this is the classification with the TPO, which is everything
online and the world's great and we turn it with a single facility outage, lock out a
transformer. We check everything across our system, then we hit it a little harder with
the multiple facility outage, like a bus or breaker failure for detection system failure,
double circuit outage, and we'll move on to overlapping combinations. We take a look
at what happens if I lose an autotransformer, and then a second large autotransformer
area, or one whole generating facility followed by another generating facility. We tend
to push the system pretty hard to see where it squeaks and then go out of the TPL
standard. This is what we're supposed to do, so that system shall remain stable. This
is kind of joking.

Appendix A
Dean Spratt: The big three, there's only two listed here, but if something happens,
NERC expects that our system won't cascade into all the other systems, and we knock
out the Western Interconnect. That's kind of an obvious one. Realistically, we're not
even supposed to know our neighbors without knowing that we're going to knock down
our neighbors. That's part of what we're checking where the edges are. Facility rating
shot, I cheated. This is kind of a straightforward one. You shouldn't overlook your
equipment, stay adequate, equipment shouldn't fail or fault. And then it's kind of a nice
summary here and object to the planning process and minimize the likelihood and
magnitude and non-consequential load loss following planning events. We look at
what could happen. The idea is we really shouldn't be knocking out customers
because we didn't plan for it and that's what naturally occurring that if you have a line
trip to lockout and you drop 3 substations, that's going to happen because they're on
that line. But if we have a line trip, we shouldn't have to shed load at yet another
substation for that loss. That's the drive. That's what we're up to.
Dean Spratt: I put this in because it helps to clarify something that does get lost in the
mix right now. 24/7 we have transmission operators and distribution operators in real
time watching systems and ready to act. If we do have an event via windstorm or just
a simple line outage, they have a little bit more flexibility in their scope and the
transmission standards tied to that. If they need to, they can shed load. If they need
to, they can overload equipment so they can operate to do the best on the system in
the real time based on what could be happening. Taking a step back from a planning
point of view, looking 5 and 10 years in the future, we're trying to build a system that
they can operate and maintain that also doesn't have something that's predictable that
knocks out load that they shouldn't have to deal with. We're trying to get ahead of
where they're operating to.
Dean Spratt: We pay attention to their operations on a pretty regular basis to find
where the weak spots in our current system make and sure that we're putting patches
on that over time, and then also solving for load growth and large load additions or
generation removals. The standards are our road map early on in the Western
Interconnect, there was Western Systems Working Council in 1967, 40 different
electrical power systems. They didn't have control areas or balancing authorities at
that time. The Portland Generals and the Avistas all sat around and said, hey, we
should establish a set of general standards to operate to make sure I don't bump into
your system. We don't bump into my system and we kind of have a good handle on
how our systems are going to operate. OK, through the 2000s, when Western Electric
Coordinating Council became its own entity. And there's a couple reasons for that. But

Appendix A
again, as opposed to just a subset of electric utilities, now every electric utility within
the Western Interconnect adhere to some common guidelines and rules.
Dean Spratt: Then just after that, North American Electric Reliability Council, NERC,
came up with standards from 1968, but they were enforced starting in 2006, but
officially in 2007. This became a new set of rules and standards that spread out across
the nation. Something that might be happening in New York and something that's
happening in the State of Washington have to perform the same general requirements.
That's the road map of our standards. Over time, we'll move into what's the result of
that. We go through the study process, we check out the alternatives, we look at the
non-wires, looked at generation, batteries, whatever we can do out of that mix in
yellow.
Dean Spratt: This is a pretty busy slide. I'm just going to talk about a couple of the
high points. In yellow, these are system reinforcements over the last decade. Roughly
speaking, going to start in the top right-hand corner just to talk to one that brought
Noxon-Cabinet 115 kV. This is an area that we share with BPA. It has 115 kV line
serving about 220 megawatts. Starting in about the year 2000, we had realized, us
and BPA that our aligned conductor wasn't strong enough to carry that load under N
minus 1 or minus 1 minus 1. We slowly reinforced that system to carry the load through
the 2010s and the 2015s, finished up those projects, and have operated reliably. Since
we're starting to the spot where the load is starting to push the system now, it's not a
thermal issue. It's turning into a voltage lapse, this issue, so we'll be going back to that
area to add some reactive support. We've talked about some generation
reinforcements, some alternate solutions as far as batteries or so we're starting to kick
around what we can do up in that area. We have portions of it, 115 kV line that could
be completed that would add a fourth line of the system, which adds some reliability.
That's probably going to be the wires solution we'll bring forward, but it will be verified
against a handful of the other alternatives.
Dean Spratt: And I moved to, in this picture, the middle of the map, the green colored
boxes. These are just through the kind of official means. All three of these projects
knocked on the door, said we'd like to integrate generation onto your system and then
not even knowing where the generation was going to go at that time. We started
studies and then either it could have been sold off system or it could have been
purchased for a long-term agreement on our system. And the three that we are
referencing this morning; Adam Neilson Solar which is 20 megawatts out in the Big
Bend area; Rattlesnake Flat 144 MW wind facility in the Big Bend area, then the first
large renewable put on the system was Palouse Wind which is kind of on the Palouse,
when you said Moscow-Pullman area and our system little over 100 megawatts.

Appendix A
Dean Spratt: That's a general kind of snapshot of reinforcements. This is transmission
specific. If you looked in any one of these areas, there's quite a few distribution
reinforcements and then also kind of the handshake between distribution and
transmission, some new substation reinforcements to carry load in this area of these
areas, I should say. Whenever we look at any transmission project, we look at anything
we can do. So, when I say can do, we try to think of all the tools and the toolbox to fix
a problem. We always check the feasibility of alternate transmission solutions. That's
the low hanging or the obvious answer for a planning point of view. But we also bring
in non-wires solutions, batteries generation. We try to think of all the things we can put
in the mix, then grab which is the most prudent at the moment based on a handful of
factors and move forward with the project and then work through that with the
corporation to finalize the project and move on to building whatever infrastructure is
required to meet load needs.
Dean Spratt: A quick example of a non-wires alternative is batteries. That's always on
the list. That's a simple, straightforward one. He'd say it that way. They're not. They're
super simple, but at a certain scale they become pretty obvious. In the Moscow
Pullman area, this example, we have two auto transformers which are the large 230
kV to 115 kV sources for our system. Our 230 kV is a main grid system that moves
generation around the area and feeds load centers. We step it down to 115 kV for load
service, so again there's two of those in the Moscow-Pullman area. Part of our studies
and transmission planning is a T minus 1 minus 1, which is just a multiple community
or overlapping cadency. So, loss of the transformer. So, we might have a transformer
out for maintenance and then as it's out, the second transformer that feeds that area
could have the bushing fail. So, both transformers are out and specifically in the
Moscow-Pullman area, that would be lights out for both cities to two colleges down
there. It's a pretty big hit as far as exposure. The total load for that area is 125
megawatts. We could put a battery that could last some amount of time, but we're
talking now cost benefit analysis, the battery would have to be. Our backup stuff,
typically when we have batteries on the system, usually they charge overnight and
discharge 12 to 16 hours during the next day. That's a standard sized battery.
Dean Spratt: We talked about transformer outages, they can be weeks to months.
So, whatever that extra resource that we'd call on has to not just make it through the
next day or the next peak cycle, it would have to make it through the next week and
on to potentially a month's worth of time. If it was a large failure of the second
transformer and the maintenance was no long duration maintenance outage. We look
at what it costs you, but batteries against that project is a solution and compared to
what it costs. But that third transformed area, so this project's not in place yet. This will

Appendix A
be worked on over the next couple of years, but a transformer just off the shelf is about
a $2.5 million dollar investment and then probably another $2.5 to $3 million to
integrate it. So about $5 million would be into a third transformer to feed the area and
we bow to the N minus one or two minus one 1, minus 1 outage issue. For this specific
use and quick overview of that and I'm going to stop there for quick questions because
we're in the middle point of what I was presenting. And then I'm going to try to be
respectful with Damon's time. So, if there are no questions on my zip through the
second half to the end, we will have more time for questions.
Dean Spratt: Not seeing any hands, I'm going to keep on going through the generation
interconnection process. Obviously, we do the load studies. We do that on a regular
basis. The other thing that comes in that's kind of out of our control specifically is how
many people want to knock on Avista's transmission door, saying we'd like to drop off
some new generation for Avista specifically or for external parties. So, two sources,
it's going to developers and then internal IRP requests, regardless of our kind of
feasibility study for the IRP group to figure out roughly how much it cost to integrate
power onto the system. Everybody that wants to truly integrate around the system has
to go through it. Open Access Transmission Tariff process that's pulled out and we're
always refining that and making that for firms as time goes by. In fact, it's becoming
more challenging, which is good from a planning point of view because a lot of the
answers are questions going in, but we still have to go through the process. Typical
process: hold the spoken meeting, outline a study plan, update the WECC approved
cases for our interconnection studies, analyze the system against the standards, and
then publish findings. Recommendations are pretty straightforward. Some surprise us.
Dean Spratt: Recently, I'm going to bring this up, we transitioned to a cluster study
process. It's a FERC now mandated process, but it's an optional process in the past.
The precursor to the cluster study process with serial interconnection process, there's
a little bit of detail here, but the next slides got a picture that makes it a little bit more
clear. The serial process, the first project to come in at the top, project number one,
we had 45 days to do a feasibility study followed by a system impacts study followed
by facility study. We'd write a large generation interconnection agreement and then
we'd repeat the cycle. We had twenty of these on the books. We would have to go
through that full cycle and the full cycle was roughly about three months. As you can
see in the chart below, from the old days on call it in 2014-ish time, the number of
interconnections. They came in and we could manage within our shop. As time went
forward, roughly 2017 into 2018, we started to see spillover. We couldn't get all the
2017 projects done. So, a couple went into 2018, then we had a larger handful of
projects in 2018, plus the spillovers turned into 2019, right around 2018-19. We were
looking at the reality and said we have an optional cluster study process. We really

Appendix A
should go to bat and convert our company to the cluster system, cluster study process,
which can be a lengthy process. We transitioned over and obviously it knocked our
numbers down to about 20 and that's been manageable. We hired some extra staff to
do that as well.
Dean Spratt: This just talks about the cluster study style that we've settled on. This is
the queue that's active right now. The queue is on the left hand side or the stuff that
was from the older serial process: our Post Falls reinforcement, Kettle Falls
reinforcements are rebuilds are in that and those are probably moving forwards.
The other ones may or may not move forwards, the TCS or the transition cluster.
When we transition to the cluster study process, second one on that list, the TCS-14
is moving forward, which is a really large wind farm, 375 megawatts with a couple
hundred megawatts of batteries. If I remember correctly, like 190 then the CS was the
first true cluster study cycle. In 2023 we have 4 projects that are still working through
the process.
Dean Spratt: Then the 2024 cluster study cycles that list. Right now we're working
through that as we as we speak and then these are the estimates for the IRP group.
This is if you drop off generation of new sites, so I'll just say really quick out in the Big
Bend area, we only have a 115 kV system there, so it takes 230 kV reinforcement to
be able to put any generation. That's why the larger numbers are on that column, and
then this point, existing generation sites that are on Avista's transmission system. So,
these happen to be a little bit stiffer. Areas that already have built for some generation,
so again the possible bit more straightforward, and then I'm going to skip this example
and top to questions and I'm going to say James has a quick slide at the end of this
questions to kind of talk. I'm going to hand it over to James if I don't see questions and
then take the last slide and he can give me the nod when he wants to see the last
slide.
Dean Spratt: Just while people are thinking of questions, the costs that are shown on
the previous couple of slides, those are what we're using in our IRP analysis for each
of our resource options. If we get a large amount of resource selection, for example in
the Big Bend area, it would trigger a major resource build or I should say a
transmission build. And what we're finding is, these transmission constraints actually
influence what resources get picked in the IRP process. They're important
assumptions. But what we're finding, at least in the preliminary analysis, is that we
need more transmission and the latter half of the plan and this study work is
instrumental into trying to help us figure out what the options are we have that are
realistic. Given the situation, because this, you know we're rebuilding the Big Bend
area, the $200 million, you know that's if all things go well. It could take a decade or

Appendix A
longer to build these and cost more. Any questions on transmission? Kelly has a
question. Go ahead, Kelly.
Kelly Dengel: Just a short one on one of those interconnection slides there was Post
Falls Hydro listed at 115 megawatts. Can you explain that one?
Dean Spratt: I do. I think it's on the queue. I'm sorry James probably tackled this as
well, but Post Falls hydro is just that and an older plant. We've had a plan to rebuild
the whole plant kind of back and forth and I think we're back to the drawing board for
a new kind of reinforcement there, but it's still in the queue. I think it's going to get
pulled shortly, if not already. Yeah, I think it might be pulled as well. And I think the
same thing for the Kettle Falls queue position there. That was for the upgrade that we
were looking at doing out of the last RFP. That is, since it got cancelled, so I think
those two Avista projects will be pulled. OK, alright.
Kelly Dengel: Thank you.
James Gall: Let's go to the last slide. I want to talk just briefly on the North Plains
Connector, you may have seen this in the news. I think Clearing Up had an article on
it, but there is a large transmission project that's being developed that connects the
Western Interconnect with the Eastern Interconnect via Colstrip. The idea behind this
line would be to utilize the Colstrip transmission system to bring power West or even
East to help us with the market liquidity, we would connect with both MISO and SPP.
think Portland General Electric is committed to this project. We're evaluating this
project whether we'd like to commit to the idea, at least for this IRP, is to include this
as a resource option in our modeling. The big challenge we have is there's not
necessarily a resource behind this. So, you're treating this as a market resource and
it's also a market resource that is connected to a transmission leg that is limited by
how much generation we would likely have at that market. We will be studying this in
the IRP as a capacity only resource that's got limitations based upon what generation
gets cited in our IRP at Colstrip. It is a 2033 or later project, so we're going to be
modeling it as an option after that period and look at it just as a capacity resource.
There will be opportunities to arbitrage markets between the two areas when we're
long. Or when we're short between the two areas, we're not going to have time to
model that in the IRP, but we would likely will look at that later. But it's something I
want to bring to the TAC as something we're looking at. I do see Fred with his hand
up. Good, Fred.
Fred Heutte: Yeah. Really glad to hear that you're going to be taking a look at this.
mean, there's a long way from here to there. It's a big build. It's a lot of money. It's a

Appendix A
whole lot of siting, et cetera. We've talked to the Grid United team, Michael Skelly and
his team. They're very capable, he used to run clean line, which is now building a
couple of big DC projects. The time frame on this I presume is like early to mid-2030s.
See, like you said, 2033. That fits in really well with the bigger picture. I just really
encourage Avista to keep looking at this. One of the big advantages of this is it gives
access to both of the big midcontinental markets. You have both SPP and MISO. That
means that this would then have access, assuming that Avista, we would like Avista
to join the EDAM of course because that's going to be a very big market then you
would have access to 60% plus of 2/3 of the country. And I think that's really important,
especially in these peak winter events, or summer events even, but certainly in the
winter events, one of the things that I've done a little bit of an analysis of from the
January freeze was looking at what happened with wind. Did the Columbia Gorge is
kind of a separate issue. There are specific issues there, but from Eastern Washington
on east all the way, you get a big surge of wind when the big cold air mass comes in
from the Arctic and then it dies off for a couple days. And then that whole front moves
on the front edge of it and the wind keeps moving to the east, and I've documented
this now in the Northwest, in SPP and MISO. It's something that we can draw on if you
have this kind of connector to where the wind is going to be at any given moment in
those kinds of events. So just wanted to point that out because there is an issue with
wind kind of pausing or ceasing during the very coldest period. But the bigger market
footprint you can access the better off you are. And of course, the Southwest and the
winter also will have a lot of surplus. Just want to say again, I'm really glad to hear
you're looking at this one.
James Gall: Thank you. Sofya, go ahead.
Sofya Atitsogbe (UTC): Yeah, echoing lots of what Fred has just said. To me it looks
like a lot of diversification opportunity. That would be at least two or three time zones.
The solar would be at a different time. There would be an opportunity to draw from
there and you have more options for wind. It sounds, especially since it's North Dakota.
So that sounds like a good hedge strategy, absolutely.
James Gall: Yeah. Thank you. Again, we're going to be modeling this as an option, to
see if the model picks it, and then we'll go from there. I guess we'll be talking about
this in July when we show the selection. We'll see if it makes the mix or not, but we do
see a lot of positives with it. Unfortunately, we can't model it I think as well as we like
in the time frame we have without delaying the IRP because we see really two different
value streams. One is this diversity benefit that, I think Sofya has brought up, and then
there's a capacity benefit during a peak event, which we can model fairly easily and
quickly in this IRP. That diversity benefit is going to take a little bit more time. So, if it

Appendix A
makes it in the cut from a capacity only benefit, I think that's a good sign that this is a
worthwhile project. I don't want to leave Damon with a no time. Let's shift to Damon's
presentation on microgrids. While Damon is putting this up on the screen, we've had
a lot of interest in microgrids. We're not quite in a position to model them in an IRP, at
least we're not going to distribution planning IRP system yet, but we want to just talk
about what they are and what benefits they can provide. There is a transmission
planning process that we have called a DPAG and this is kind of an intro to that side
of the public process. So, with that, I'll give it to Damon.
Distribution Planning, Damon Fisher
Damon Fisher: Thanks again, my name is Damon Fisher, with System Planning and
today I'm going to speak about microgrids. I'm not an expert in microgrids by any shape
or form, but they are there are something of interest in the business of distribution
system planning.
Damon Fisher: Let's get to it. This is a boilerplate slide that you've seen several times
already. I don't know that I need to speak to it too much, but distribution planning, we're
looking out ten years in the future. We're doing a plan. The runway length for
distribution facilities is getting longer and longer. The power transformers and things
like that are becoming quite long lead time items. So, I think over five years we're
getting way out there for our transformers and things like that. So, any capacity issues
that are coming up on the on the grid need to be identified as soon as possible.
Damon Fisher: We've got a 10-year plan that we're working on a 2-year cycle. We do
a system assessment. From our assessment, we develop projects, capital projects to
do in the future and during that process we consider these things. So, what is a
microgrid seems obvious, but it's the same as a macro grid, but smaller, it's self-similar.
I'm thinking about this. If you're familiar with the fractal, a little picture of 1 there, it's a
mathematical curiosity. No matter how close you zoom into that picture, it looks the
same. You keep zooming in, keep zooming in, keep zooming in. It keeps repeating
itself somewhere. That's what a microgrid is. It needs to perform just like a macro grid
and the same issues it needs to maintain voltage and frequency respect. Thermal
limits load equals generation, right? That's a rule in the Systems. You can't violate
that, and the equipment's protected, particularly generators and stuff like that.
Otherwise, they can be damaged, just like on the macro grid. So, you're either
shedding, shedding load, or turning generation off in some way, shape or form
whenever to protect the system from damage. You still have to do that at a microgrid.
Damon Fisher: We were just talking about this, I think about a line going from the
orange to the green there, a DC line. The Western interconnection has a heartbeat.

Appendix A
The Eastern Interconnection has a heartbeat, and so does the Texas interconnection,
and those heartbeats shall not mix. These things function on their own. If you look at
the continental United States as a grid, there's, maybe 3 microgrids in it. You'd like to
think of it that way. There are DC interconnections that exist between the Western
interconnection and the Eastern interconnection. I'm not exactly sure what their
function is, but they are there so they can talk to each other, but you can only talk to
each other in DC form, right? Because DC has no heartbeat. DC is bivalent. It's my
understanding that Alberta up there, and maybe even BC, can island themselves from
the Western Interconnection system if they wanted to. Alberta could be a microgrid.
That's how big it could be. That's not what we're talking about here. We're talking about
distribution.
Damon Fisher: What's in a microgrid? The major equipment is all very similar to a
macro grid. This is very similar to the way the system is today, the transmission
system, the microgrid controller. There's a lot of controls that have to happen and
these are local, sophisticated controls and communications among other pieces and
parts that are in that microgrid. Microgrids could be an Air Force Base. It could be a
building, but this all needs to happen. OK, generation of some sort, it could be
renewable it could be thermal fuel cells, which generation it could be on the system
and then storage or some dispatchable source. This is kind of important, but
something that can follow the load and be asked to do something. That can't be your
only thing. You went with the battery. That will work with a dispatchable source like a
diesel generator, that will work, but that's important, that might be more of a
functionality thing. I don't know. But storage and dispatchable sources are important,
and then a grid disconnect switch. A point of common coupling with the grid.
Damon Fisher: There's a point, on one side is the grid proper and on the other side
is the microgrid proper. And that's a very important thing to do. No one definition of a
microgrid is that it can operate grid connected. All the little components of the microgrid
function. Well, perform and do what they need to do. However, the controller wants to
do it. Does it still function with that grid disconnection? Close that point of common
coupling. There are definitions of a microgrid that say that it still needs to work right
with that switch closed. If that switch, if it doesn't, and that switch is open, then you're
maybe thinking now you're moving over into a backup situation. Hospitals, even Avista,
here we have backup generators. They turn on after that switch is, we're disconnected
from the from the grid. That's probably the most common way if you want to fit that into
your definition of microgrid, is a backup power source. It's how it has been done in the
past and typically that is driven by the customer. The customer decides that they have
facilities that they need to power. If power goes out and they take care of it, spend the
money and make that happen.

Appendix A
Damon Fisher: Major functionality of a microgrid would be its black start capable. So,
it can it turn itself on, if disconnected from the grid for whatever reason. Power goes
out on the grid that switch is open. Everything's black. There's no power. Can it turn
on and create a microgrid and serve load? That's an important piece of the puzzle. It's
not always possible. We have generation facilities that can't turn on without power,
surprising, but that's true.
Damon Fisher: OK, it needs to be able to island. It needs to be able to respectfully
disconnect and connect to the grid without causing problems. The way that works
typically is that that grid disconnect switch, the point of common coupling, the microgrid
controller will manipulate low generation or whatever, such that the power flow across
that switch is 0, and once that happens, it can open everybody on the microgrid.
Doesn't know this happened. They just continue doing what they're doing, but the
microgrid is no longer connected to the grid, no longer operating with the grid, and
great synchronization is really important. After doing that and running as a microgrid
for a while, how do you connect back up? Well, you need to be synchronized, so the
heartbeats need to become the same again. Like I mentioned, heartbeat says
frequency and phase. The frequency needs to be the same and the angle. We need
to be synchronized before that switch closes. At that point of common coupling and
then another piece function at least managed demand. The demand on the microgrid
needs to be controllable in the sense that, well, this is not an important building. I need
to shut that off or turn it on or the microgrid controller needs to have control over that
in some way, shape or form and depending on what the goals of the microgrid are,
which are varied and very significant.
Damon Fisher: Why does somebody do a microgrid? Resilience is probably, and I
mentioned backup power. Backup power is a resilience play. OK, so you got a critical
load or essential service that you cannot tolerate an outage. Maybe it's an assembly
line or something, some process that needs to go, hospital, critical load. Things like
that. So that's a resilience plan. Then there's an economic plane. That would be, a
demand charge shifting, taking control over your bills if the billing structure, the rate
structure for this kind of thing and not all of them do. Maybe you can defer or avoid
demand charges and energy arbitrage, other utility services that you may provide the
local utility and climate goals.
Damon Fisher: Typically, at least, conceptually these microgrids in the future are
going to have renewable generation of some sort. Put on a solar roof and that kind of
stuff. These will help folks with microgrids, it can help folks sneak climate goals either
prescribed or self-determined climate goals. And then, if you have difficulty serving

Appendix A
load or getting service because you're isolated, you're on it literally, on an island. If
you just sit on the middle of nowhere, you can set up a microgrid to power yourself.
Whatever yourself is, some resorts in the middle of the mountains or whatever it
happens to be. It becomes prohibitively expensive to drag wires to your facility. So
how does it take to get it? Is it a resource?
Damon Fisher: This is the place we talk about resources. A microgrid could be
resource in a sense that it's kind of a black box. It operates that way and the utility can
ask it for things and then you can ask it for capacity. And then the black box will talk
to itself. Have a conversation with itself and say yes I can help you with that or I can't
help you with that. It all depends on how that microgrid is set up, and those can be
driven by incentives and agreements between the microgrid owner and the utility.
Damon Fisher: Maybe the microgrid owner has to demand response agreement with
utility. And so, you've been called upon. They have promised to do something, so they
could set up their controller to do it right, or if they have internal things that they want
to do, they got to maintain a state of charge on their battery for some reason or
whatever. The grid won't violate the rules that it's been given the microgrid, so it can't
be a resource. I don't think that the DER that are involved in these things that's need
to be in a microgrid in order to still be a resource. You can still call upon these things.
think the microgrid piece is it's an opinion thing. Microgrid piece, really it feels to me
like a big resilience point thing. Do you really need resilience then? This is what you
do if you just want to have DERs and that kind of thing. They can still function as a
resource to the grid, but you don't have all the complications or expense. This one has
a couple of micro, well we have one microgrid and one in the works. we have the WSU
Spokane Campus demonstration pilot. I don't know a lot about this. I know that they've
islanded it successfully and so it's more of a playground for the R&D group that they
do stuff with it. It's not used for any particular reason other than learning. That's what
is functioning, however, we have a project out for bid for the MLK Center, which is a
Community Center. For a microgrid, that's 115 kW DC solar array battery and natural
gas generator. Approximate cost for this is $2.5 million and there were grants applied
for, but it was a grant applied for by the MLK Center, and then we are providing
matching funds. Alright, some funding source. I don't know exactly where that's coming
from. A Named Community Fund, thank you.
James Gall: You have a question? She says what's Avista's ultimate goal with
microgrids?
Damon Fisher: At this point? It's the same as everything else. We're learning about
these things and there is no official goal that I'm aware of. But right now, I think the

Appendix A
more we learn, the more we will be able to look at these things as solutions to particular
problems. I know we have some problems on the distribution grid that these might
actually pencil out on. They haven't been applied to that, but so it's going to be. I'll
describe it as this, microgrids will just be another tool in the toolbox to fix, to mitigate,
distribution issues. There's a lot of money out there on the federal side for microgrids.
The problem is Avista can't actually apply for that money. The money has to go to
somewhere like the MLK Center, a tribe, some other group. They initially apply for it,
and then we can do matching funds and funding. We can do some things to help on
it, but it's not something that we can actually drive. There's a hand up, go ahead.
Brewer, Molly (UTC): Thank you.
Joshua Dennis (UTC): Hi, Joshua Dennis with the Washington UTC. I don't see any
mention of the Spokane Microgrid. Here it was mentioned in the BCP, and I was
wondering what the progress would is on that.
Damon Fisher: The Spokane microgrid with a tribe? I'm not aware of what this is. I'm
not sure what the status of that is.
Joshua Dennis (UTC): Uh, yes.
James Gall: I know there's work going on to keep a few buildings energized as a
microgrid that's moving forward. I don't know exactly where it's at in the process. I'm s
going to check if there are any folks online that could give a brief update on that one.
don't. No one's responding, so unfortunately Joshua we will have to get back to you
on that one.
Kevin Holland: Hey, James.
Joshua Dennis (UTC): I guess that raises a second question and I guess with this
being a toolbox that Avista has to mitigate distribution issues, what would Avista's
ownership model preference be?
Damon Fisher: Very good question. There are some I think, and somebody correct
me if I'm incorrect, but if a third party were to own this, they would need to be the
customer. They would not be able to have a microgrid and sell. If they had a campus,
some sort of business campus or something, where there were other renters on the
site, they wouldn't be able to sell to those other folks. A microgrid for them may be
problematic. I think because they're not a utility. From an ownership point of view, from
a planning point of view, these things would be something that we would mitigate and

Appendix A
feed or should probably. A very long feeder out in the middle of nowhere. This is the
distance, the separation thing, to get to get past voltage issues or loading issues and
things like that. This is something that would be probably owned by the utility. It could
be and I think it's case by case basis, but Kevin you came on, I think he was saying.
Kevin Holland: Yeah, actually, can you hear me?
James Gall: Yep.
Kevin Holland: Yeah, I think I think that's exactly right. I think a lot of these in terms
of what the ownership are and devising the divisional lines between customer owned
facility components and Avista owned facility components will be potentially variable
by project. But obviously I think along with what was said, the applications will be
different depending. It's another tool in the toolbox that we can use and therefore I
think as it applies in different situations, and depending on what the goal of the
customer and the coordination with Avista leads to, I think the structures could be
different, but obviously having this MILK resiliency project and some of the other ones
that were conceptually in different phases will provide us with a lot of insight. I think
John Gibson probably is a good reference to point us in a direction. I know he's not on
the call today, but we could certainly ask some additional questions of John because
his group has been intimately involved in putting this together and crafting some of the
intricacies of these types of projects, but they'll be different for different applications.
think that's exactly right that it provides us with a tool in the toolbox that we can apply
in different usage and situations in terms of whether it's a grid resiliency program,
whether it's a resiliency program for that customer in and of themselves from a tribal
perspective. Whether it's energy, independence and sovereignty, so different
applications for different uses.
Joshua Dennis (UTC): Thank you.
James Gall: Going to Sofya.
Sofya Atitsogbe (UTC): Data sets. Thank you. Avista recently filed the affiliated
interest filing for the Connected Communities of Spokane. As I understand, this is also
a microgrid project. Is that correct? My understanding is it's downtown Spokane that
the one of the new Avista buildings are part of it. It's part of it. Could you give an update
on that project?
James Gall: I'm trying to see if there's anybody in the room that can, I know enough

Appendix A
to be dangerous, but I'm not going to say anything because, Kevin, I don't know if you
know anything more than I do.
Sofya Atitsogbe (UTC): A lot of thoughts.
Kevin Holland: Yeah, James, I think you and I are kind of in the same boat. It's a very
unique project in terms of the component tree and how it's self-sustaining and yet
potentially also helping the grid. But the project in and of itself has very little
connectivity. This sounds odd, but a small amount of connectivity to the Energy Supply
group and so we would probably need to defer to someone like Latisha Hill or
potentially John Gibson, again to give an update on the Connected Communities
project as a whole. Nicole Hydzik is moving forward, but I know with that particular
facility that were involved in downtown and the three buildings I think are two or three
buildings and that's sort of an incubator type situation that continues to mature.
Sofya Atitsogbe (UTC): That wouldn't be a question that I will just comment on that.
As part of CETA, resiliency is very important for the State of Washington.
James Gall: Sofya, catch up. Go ahead.
Sofya Atitsogbe (UTC): I think lots of people will be keeping a close eye on Avista's
learnings, among other things, from the microgrid pilots. We would like to see
information about what challenges Avista has presently in resiliency planning, and
that's rates, what lessons are learned and what is to do in that regard. Thank you.
James Gall: Thanks. We'll try to do this at the next TAC meeting. We'll see if we can
get an update on both the Spokane Tribe project and the Connected Communities.
But we do have two minutes left. But we can go a little bit longer if you guys can stick
around. We definitely can. We might lose our room momentarily, so we'll see how that
goes. But game to go ahead and see what we can get done.
Damon Fisher: If you look at this diagram, this is an actual diagram that was sent out
with the resiliency center. You could see all the components and pieces, what you
don't see on here is the gas generator, which I believe came after some study was
done in terms of a requirement of it lasting longer. So, the microgrids can last that
amount of time or forever. The difference of cost could be significant. If not, it's more
stuff. So now that the requirement change, I don't know the change or whatever there
is some discovery but now there's a natural gas generator in the mix here. This is the
actual Center, the top of the roof, to the white part is the roof. That's where the solar
would go. And then they get red roof there. I believe this is an outline police station or

Appendix A
some sort of secure what they do there. So, how does how does this help Avista?
Well, what it could do, it's not really from a service point of view, from a capacity or it's
not quite that useful from the distribution grid point of view. This is the actual feeder
it's on, this is last summer's peak load. I think the temperature there is 102 degrees on
that feeder. It's got to go all the way up to the green line there to get to 80% utilized.
That's quite a bit of room on it still, but let's assume it didn't, and so what you could do
is this. It could call them and say, hey, you can you help us out here with some capacity
issue, a great constraint on the transformer feeder. And then all the way up to the
system wide you maybe you can ask for a resource.
Sofya Atitsogbe (UTC): I don't think we would want to spend a lot of time investigating
which schools are open but take a little bit out of there and give up a little bit.
Damon Fisher: That's how it could happen. Well, this is the resiliency advantage. The
user utilizes all their resources in a more optimized way because nobody has the same
goals with their microgrid and then they have flexibility and autonomy with their billing
and then then it opens it up for grid resource options. This vintage, they are costly. I
don't know if you saw $2.5 million for half a MW of battery storage for the MLK
resiliency play. It's kind of expensive. I don't know if there's a particular thing about the
MLK thing that makes it so expensive, but just for reference, a brand new 60 MW six
feeder substation is going for about $11 or $12 million on our system. So that's $2.5
million. The owner of the microgrid, utility or otherwise, has extra cost for ongoing
maintenance and local expertise to maintain it. Some of this was actually brought up
regulatory policy, contractual complications. It does complicate things, but that's for
the business to do is get complicated, I guess. So those things at all, typically here
down.
Damon Fisher: The last thing I have to say is, the DPAG, Distribution Planning
Advisory Group, is meeting July 24th. I'm not sure if everybody on here gets an invite.
No, but that does not say what we will be talking about. I don't know, hosting capacity
maps and improving and we currently have. The TAC has been told about the DPAG
and we've tried to do it but if you want to be on the DPAG you can contact me, and I
can get the information to it.
James Gall: Just do it through the regular IRP channels and we'll make sure that gets
to Damon's group. Alright, that's all I have for over time. We thank you for sticking with
us. We will see you at our modeling workshop, if you care to join us. Otherwise, we'll
see you after the Fourth of July holiday in our next TAC meeting. Thank you. Have a
great day.

Appendix A
Sofya Atitsogbe: Thank you for the presentation.
Joshua Dennis (UTC): Thank you.

Appendix A
,1
2025 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 10 Agenda
Tuesday, June 18, 2024
Virtual Meeting — 8:30 am to 10:00 am PTZ
Topic Staff
Introductions John Lyons
Preferred Resource Strategy Results Planning Team
Resource Adequacy
Washington Customer Benefit Indicator Impacts
Resiliency Metrics
Microsoft Teams meeting
Join on your computer, mobile app or room device
Click here to join the meeting
Meeting ID: 264 797 739 040
Passcode: M LVkp8
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Or call in (audio only)
[phone]„525313571# United States, Spokane
Phone Conference ID: 525 313 571#
Find a local number I Reset PIN
Learn More I Meeting options

�I�r r/ISTA
2025 IRP TAC 10 Introductions
John Lyons, Ph.D.
Technical Advisory Committee Meeting No. 10
July 16, 2024

Appendix A
Today's Agenda
Introductions, John Lyons
Preferred Resource Strategy Results, Planning Team
Resource Adequacy
Washington Customer Benefit Indicator Impacts
Resiliency Metrics
2

Appendix A
Remaining 2025 Electric IRP TAC Schedule
• TAC 11 : July 30, 2024: 8:30 to 10:00 (PTZ)
o Preferred Resource Strategy Results
o Portfolio Scenario Analysis
o LOLP Study Results
• TAC 12: August 13, 2024: 8:30 to 10:00 (PTZ)
o Preferred Resource Strategy Results (continued)
o Portfolio Scenario Analysis (continued)
o LOLP Study Results (continued)
o QF Avoided Cost
• September 2, 2024- Draft IRP Released to TAC.
• Virtual Public Meeting- Natural Gas & Electric IRP (September 2024)
o Recorded presentation
o Daytime comment and question session (12pm to 1 pm- PST)
o Evening comment and question session (6pm to 7pm- PST)
3 ins

2025 Electric IRP Document Appendix
Chapter/Sub Chapter TAC Date
Executive Summary October 1, 2024
1. Introduction, Stakeholder Involvement, and Process Changes October 1, 2024
2. Economic and Load Forecast September 3, 2024
a. Economic Conditions
b. Avista Energy & Peak Load Forecasts
C. Load Forecast Scenarios
3. Existing Supply Resources October 1, 2024
a. Avista Resources
b. Contractual Resources and Obligations
C. Customer Generation Overview
4. Long-Term Position September 3, 2024
a. Regional Capacity Requirements
b. Energy Planning Requirements
C. Reserves and Flexibility Assessment
d. Variable Energy Resource Integration Stud
5. Distributed Energy Resources Options Se tember 3, 2024
a. Energy Efficiency Potential
b. Demand Response Potential
C. Generating and Energy Storage Resource Options and Potential
d. Named Community Actions
e. Distributed Energy Resources Study Conclusions
6. Supply-Side Resource Options September 3, 2024
a. New Resource Options
b. Avista Plant Upgrade Opportunities
C. Non-Energy Impacts
7. Transmission Planning & Distribution September 3, 2024
a. Overview of Avista's Transmission System
b. Transmission Construction Costs and Integration
C. Merchant Transmission
d. Overview of Avista's Distribution System
8. Market Analysis October 1, 2024
a. Wholesale Natural Gas Market Price Forecast
b. Wholesale Electric Market Price Forecast
C. Scenario Analysis
9. Preferred Resource Strategy September 3, 2024
a. Preferred Resource Strategy
b. Market Exposure Analysis
C. Avoided Cost
10. Portfolio Scenarios October 1, 2024
a. Portfolio Scenarios
b. Market Scenario Impacts
11. Washington Clean Energy Action Plan CEAP September 3, 2024
a. Decision Making Process
b. Resource Need
C. Resource Selection
d. Customer Benefit Indicators
12. Action Plan October 1, 2024

Appendix Appendix A
Chapter/Sub Chapter Proposed
Com letion Draft
TAC Presentations Alread Available January 2, 2025
Work Plan Alread Available January 2, 2025
AEG EE/DR Potential Assessment September 3, 2024
10- ear Transmission/Distribution Plan ?
Transmission Generation Integration Study 3, 2024
DER Study Se tember 3, 2024
Public Input and Results Data (Alread Available) October 1, 2024
Confidential Inputs and Models January 2, 2025
Historical Generation Operation Data Confidential January 2, 2025
New Resource Transmission Table Janua 2, 2025
Resource Portfolio Summary October 1, 2024
Washington State Avoided Costs January 2, 2025
Public Comments January 2, 2025

���r r/ISTA
2025 Electric Integrated Resource Plan
Draft Preferred Resource Strategy
James Gall & Mike Hermanson
Technical Advisory Committee Meeting No. 10
July 16, 2024

DRAFT
Appendix A
LOLI I Study Update
• During subsequent analysis after the June 4, 2024 TAC Meeting it was determined some industrial
loads were double counted — both in the hourly load model that is an input to the reliability model and
the reliability model itself
• The net result of this correction reduces the quantity of dispatchable generation to reach our LOLP
Standard of 0.05
1 MW AdditionalUpdated LO with
LP
Dispatch . . -
Gen — Draft corrected industrial
' - • June 4, 2024loads
LOLP �10.40M��Nr 5.0% ME
LOLE E 0.32 ' 0.1 E
r
LOLH ro3.66 1.56 _
LOLEV I 0.83 0.333
EUE (with reserves) 783 268.4
EUE (without reserves) 768 256
Implied Planning Margin 23.8% 23.8%
2 OEM

DRAFT
Appendix A
Resource Adequacy Assumptions Maintenance Adjustment
400
345
350
300
• Winter PRM : 24% (was 22%� 250 227
l 200 160
— Uses 5% LOLP and 330 MW of market Q 150 118
100 93 81
• Summer PRM : 16% 54 38 50
— Based on single largest contingency Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
• Maintenance adder
— Idea is to include adjustment to L&R position for units likely to be taken on
maintenance
— Averages actual maintenance 2014-2024 & forecast 2025-2045 schedules
• History shows significant outages in winter months, forecast does not- this splits
history and the forecast.
— Weighted average of outages (% of month x QCC)
3

DRAFT
Appendix A
Resource Position
Monthly Peak Hour Position Monthly Energy Position
Capacity 2 3 4 5 6 7 9 10 11 12 Energy 1 � 2 3 4 5 6 7 8 9 10 11 12
2026 (40) 08 288 369 243 136 9 (22) 271 247 153 4 2026( (26) 122 170 345 706 518 173 74 198 170 59 16
2027 (3) 46 333 429 306 198 65 33 327 296 194 44 2027\ (4) )48 199 372 753 556 220 129 251 213 90 50
2028 (2) 40 324 424 305 192 7 27 315 292 189 37 2028 (10) �89 199 365 747 553 213 123 252 217 93 45
2029 1 7 333 428 309 191 6 337 301 197 53 2029 /_f 81 224 392 763 566 215 118 256 225 102 61
2030 (55) 9 267 358 266 130 (3) (33) 264 246 131 (15) 20W� 10 79 225 385 757 564 212 117 251 225 100 62
2031 (62) 86 268 360 265 122 (11) (39) 276 245 132 (14) X31 13 89 234 388 771 581 225 120 261 226 103 66
2032 (71) 77 54 350 264 99 (17) (50) 256 234 118 (28) /2032 17 134 240 396 771 582 217 118 254 225 97 65
2033 (107) 41 2 318 232 111 (25) (58) 257 204 80 (69) 2033 11 95 242 390 768 573 208 108 250 223 100 64
2034 (230) (76) 105 210 136 14 (117) (150) 159 99 (25) (183) 2034 (48) 56 194 334 698 511 155 56 207 181 40 5
2035 (225) (76) 102 09 130 33 (128) (155) 152 98 (24) (183) 2035 (69) 46 184 328 692 501 142 41 191 164 27 (2)
2036 (236) (83) 99 2 1 126 10 (132) (162) 138 90 (35) (1 2036 (80) 80 175 316 680 486 127 29 179 151 6 (25)
2037 (297) (139) 46 154 84 (24) (175) (207) 120 45 (85) 46) 2037 (95) 30 160 297 668 474 113 11 167 144 (10) (39)
203 (365) (201) (13) 102 36 (87) (234) (258) 68 (10) (15 (316) 2038 (114) 10 138 280 641 441 67 (20) 145 122 (28) (63)
203 (398) (231) (43) 78 7 (116) (277) (303) 45 (39) 8) (348) 2039 (133) (1) 127 262 625 421 46 (39) 134 108 (41) (78)
20 (473) (303) (107) 19 (4 (189) (343) (375) (17) (96) (245) (417) 2040 (168) (13) 81 216 581 355 (11) (96) 83 55 (85) (147)
20 1 (525) (351) (157) (27) (72) (197) (381) (415) (64) (1 ) (290) (474) 2041 (250) (141) 9 139 513 274 (106) (176) 12 (15) (163) (220)
2 2 (838) (666) (471) (263) (276) 71) (657) (695) (326) 426) (604) (789) 2042 (527) (407) (250) (39) 332 91 (370) (431) (246) (271) (419) (494)
2 43 (910) (736) (538) (324) (326) (4 ) (684) (721) (36 (481) (665) (858) 2043 (587) (468) (319) (108) 281 38 (424) (482) (296) (326) (488) (568)
2 44 (992) (814) (612) (388) (383) (553 (741) (787) 8) (548) (741) (935) 2044 (619) (450) (346) (136) 259 11 (462) (513) (318) (346) (513) (600)
45 (1,291) (1,115) (904) (674) (574) (792) (996) 117
(652) (813) (1,033) (1,246) 2045 (866) (733) (578) (310) 101 (143) (672) (725) (533) (565) (744) (836)
Northeast "retire" Market is allowed to meet this target
Propose waiver for RFP requirement
4

DRAFT
Appendix A
Preferred Resource Strategy out on Julyj Oth)
Nameplate MW 2026 -juj 202R groa 2045
Shared System Resource
Mrkt/Trans 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Natural Gas 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Solar 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Wind 0 0 0 0 0 100 100 200 0 0 0 0 0 0 0 0 0 0 0 0
Storage 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 25 0
PtoG 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Nuclear 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Geothermal 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Biomass 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 10 0
RNG 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Washington
M rkt/Trans 40 4 10 0 0 0 0 0 0 0 0 50 0 0 50 50 50 50 0 50
Natural Gas 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Solar 0 1 1 1 1 1 101 1 1 1 1 0 1 1 ' 1 1 1 1 183 1
Wind 0 0 0 200 200 100 0 0 0 0 0 0 0 0 0 140 0 120 0 200
Storage 0 0 0 0 0 0 50 0 0 0 0 0 0 0 0 0 0 0 91 62
PtoG 0 0 0 0 0 0 0 0 0 0 0 0 90 0 0 0 195 0 94 0
Nuclear 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 153
Geothermal 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 20
Biomass 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
RNG 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Idaho
Mrkt/Trans 0 0 0 0 0 0 0 0 0 0 0 0 0 0 _ 0 0 0 0 0 0
Natural Gas 0 0 0 0 99 0 0 0 0 0 0 91 0 0 _ 0 0 124 0 0 0
Solar 0 0 0 0 0 0 0 0 0 0 0 0 0 0 _ 0 0 0 0 _ 0 0
Wind 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Storage 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 25 0
PtoG 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Nuclear 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Geothermal 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
5 Biomass 0 0 0 0 0 0 0 0 0 0 0 0 0 0 _ 0 0 0 0 0 0
RNG 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

DRAFT
Appendix A
Preferred Resource Strate ( Updated)
JjMbb.jP28 202 2036 2037 2038 2039 2040 2041_&2�04043 2044 2045
Shared System Resource
Mrkt/Trans 40 4 10 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Natural Gas 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Solar 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Wind 0 0 0 0 0 100 100 200 0 0 0 0 0 0 0 0 0 0 0 0
Storage 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
PtoG 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Nuclear 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Geothermal 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Biomass 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 10 0
RNG 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
DR 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Washington
Mrkt/Trans 0 0 0 0 0 0 0 0 0 0 0 50 0 0 50 50 50 50 0 50
Natural Gas 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Solar 0 1 1 1 1 1 101 1 1 1 1 1 1 1 1 1 1 1 200 5
Wind 0 0 0 200 200 100 0 0 0 0 0 0 0 0 0 140 0 120 0 200
Storage 0 0 0 0 0 0 50 0 0 0 0 0 0 0 0 0 0 0 104 62
PtoG 0 0 0 0 0 0 0 0 0 0 0 0 90 0 0 0 196 0 94 0
Nuclear 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 150
Geothermal 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 20
Biomass 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
RNG 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Idaho
Mrkt/Trans 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Natural Gas 0 0 0 0 99 0 0 0 0 0 0 90 0 0 0 0 124 0 0 0
Solar 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Wind 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Storage 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 35 0
PtoG 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Nuclear 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Geothermal 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Biomass 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
6 RNG 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Appendix A
Named Community Investment Fund Considerations
• NCIF project spending on future resources size and type is unknown.
• IRP accounts for these potential projects by forcing the model to select excess energy efficiency and DERs
• The table below is the estimated selection assuming
• $2 million spending on energy efficiency
• $400k annual credit toward DERs
• Spending limits increase each year due to inflation
PeriodTime Distribution Level Distribution Level EnergV EnergV EfficiencV
StorageSolar 2026-2035 600 kW/year Not selected 1,444 MWh/year
2036-2045 900 kW/year 4 M W (2044) 1,150 MWh/yea r

DRAFT
Appendix A
Long Term Resource Changes
Resource 2026-30 2031-35 2036-40 2041-45 Total
Natural Gas 99 0 90 124 313
Natural Gas Retirements (64) 0 (36) 456) 556
Thermal Total 35 0 55 333 242
Power to Gas CT 0 0 90 196 287
Hydrogen 0 0 0 94 94
Power to Gas Total 0 0 90 291 381
Northwest Wind 400 300 0 460 1,160
Montana Wind 0 200 0 0 200
Wind PPA Expirations 0 0 145 105 25L
Wind Total 400 500 (145) 355 1,110
Distributed Solar 2 4 3 7 15
Utility Scale Solar 0 100 0 200 300
Solar PPA Expirations 0 0 20 0 20
Solar Total 2 104 18 206 295
Rate Program 20 7 4 0 31
Direct Load Control 13 20 10 18 61
Demand Response Total 33 27 14 18 92
Short-Duration Storage 4hr 0 50 0 104 154
Mid-Duration Storage 8-24 hr 0 0 0 35 35
Long-Duration Storage >24hr tl
0 0 62 62
EnergyStorage Total 50 0 201 251
Hydropower 0 0 0 0
Hydropower Contract Expirations 88 0 0
H dropower Total 88 0 0
Regional Transmission 0 0 100 200 300
Nuclear 0 0 0 150 150
Biomass 0 0 0 10 10
Geothermal 0 0 0 20 20
Market 53 0 0 0 53
Other Total 0 0 100 380 480
All Resource Total 459 593 97 1,119 2,267
8 Additions 1 588 681 297 1,680 3,246
Subtractions 76 88 201 561 926

DRAFT
Appendix A
PRS Resource Adequacy
• The PRS for the listed year is used as the resources available along with market purchases and sales,
and reliability metrics are calculated.
LOLP 0.5% 2.3%
LOLE 0.01 0.05
LOLH 0.075 0.528
LOLEV 0.019 0.128
EUE (with reserves) 6.7 103.4
EUE (without reserves) 6 103
9

DRAFT
Appendix A
Clean Energy Transformation Act Compliance
1,400
Clean Gen =< monthly net load
Jurisdictional REC Purchases
1,200 Clean Gen > monthly net load
Idaho Hydro
REC Sales
1,000 —Net Retail Load
——— Primary Compliance Target
800
�do
L
600
Q
400
200
c0 f� 00 M O CO ti 00 N Lf)
It
CD CD CD CD MO MO MO MO COO 0p 0 CD O
N N N N N N N N N N N N N
10

DRAFT
Appendix A
Clean Energy Forecast as Percent of Load
140%
120% ■ Existing New
100%
0 21% 13% 13° 39/0 42% 32% ° 75%
30% 54%
.080 /o � Fm m /0 12%
O 11%
60% IF
Pr
O
V 40% % 79% 80% 77% 78% 0
1170 0 71% 66% 68°
L
9L 20%
0% •
O C E O C E O C E O C E O C E
O O O N O 1-1 N O N O a)
Cu 4-
(n _r_ U) _r_ CO -r- U) _r_ U)
ccu Cu m N
2026 2030 2035 2040 2045
11

DRAFT
Appendix A
Average Energy Rate Forecast ( Nominal)
Question: Should the PRS be constrained to the 2% cost cap?
$0.30
— — Electric Washington Exceeds CETA
Cost Cap
$0.25 — —Electric Idaho
$0.20
s
$0.15
CD
CL
69- mom
$0.10 - -
$0.05
$0.00
C0 r- 00 O O N M 't LO cfl � 00 O O N CO IZI- LO
N N N N M CO CO M M M CO CO CO CO NT 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
12

DRAFT
Appendix A
Net System Greenhouse Gas Emissions
1.8
1.6 ■Emissons "Sold"
■Net Emissions
1.4 —
1.2
c
c
0
1.0
U
W 0.8
0
0.6
0.4
0.2
0.0
2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
13

DRAFT
Appendix A
Transmission Consideratir ­
• Rathdrum Area: New natural gas CTs begin in 2030, these are likely located
in North Idaho, new transmission will be required , if projects continue to be
sited in the area additional reinforcement is needed .
• Off-System Imports : Need to increase connections to markets/areas to
reach additional wind to import by 2045
• North Plains Corridor: 300 MW of transmission to MISO/SPP is selected
late in the study, this considers capacity value only. If the project has
significant energy value, the project could be selected earlier.
14

DRAFT
Appendix A
Demand Response
Customer Segment Washington WA: Total Idaho ID: Total
Start Year Potential Start Year Potential
Electric Vehicle TOU Commercial 2026 8.8 2029 0.9
Battery Energy Storage All 2026 10.4 2029 2.8
Peak Time Rebate Residential/Sm. Com. 2026 6.0 2029 4.2
Variable Peak Pricing Large Commercial 2033 5.4 2031 1 .8
Third Party Contracts Large Commercial 2035 20.0 2040 6.6
Behavioral Residential/Sm. Com. 2037 1 .9 2040 1 .3
Time of Use Rates Residential/Sm. Com. 2039 2.5 2038 1 .7
Smart Appliances Residential/Sm. Com. 2042 2.5 n/a
CTA WH Residential/Sm. Com. 2042 5.6 n/
Central A/C Residential/Sm. Com. 2043 9.8 n/7
Total MW by 2045 72.9 am
Assumptions:
• Current industrial contract remains
• Idaho AM by 2029
15 • Total savings assumes projects do not overlap into other programs ins

DRAFT
Appendix A
Energy Ef Bv Sector & State
1,400
■ID ■WA Total 1,2111,239
• New energy efficiency meets 9.8% of 2045 system load 1,200 1,097
1,053 1,1331,172
• Washington Biannual target to be calculated later 1,000 946 1,000
882
;n 813
0 800 734
r 655
R
600 568
1,400 LM
0 480
■Residential ■Commercial ■Industrial Total 1,2111,23 393
400
1,200 1,0971,1331,172 253 319
1,053 177
1,000 200 110
1,000 946 52 •, ' •� �,
y 813 0 _ _
L (D f-- CO 0) C. N M V In (0 r- CO O CD NM V U)
N N N N CO M CO M M M M (M CO CO I- V It 'IT V It 800 734 0 00 0 00 0 0 0 00 0 00 00 0 00 0
N N N N N N N N N N N N N N N N N N N N
655
M 600 568
480
393
400 319
253
177
200 110
52
CO f- 00 O O N M 't Cn CO r- 00 O O N CO �t (n
N N N N CO M CO M CO CO CO CO CO CO d' T V V V
O O O O O O O O O O O O O O O O O O O O
CV N N N N N CV N N N N N N N N N N N N N
16

DRAFT
Appendix A
Energy Efficiency Supply Curves (2045)
Washington Idaho
$500 $500
$450 $450
r
$400 $400
$350 $350
U $300 i- $300
$250 $250
t t
� $200 � ?� $200
$150 $150
6n. $100 6-0. $100
$50 $50
$0are $0
0 200 400 600 800 1,000 1,200 1,400 1,600 1,800 0 200 400 600 800 1,000 1,200 1,400 1,600 1,800
Gigawatt Hours Gigawatt Hours
17

DRAFT
Appendix A
2035 Top Measure Savings (GWh)
Row Measure State 2035 Row Measure State 2035
1 Linear Lighting WA 81.34 1 Linear Lighting ID 43.34
2 Windows - High Efficiency (ENERGY STAR 7.0) WA 27.98 2 High-Bay Lighting ID 12.70
3 High-Bay Lighting WA 25.00 3 Engine Block Heater Controls ID 11.05
4 Building Shell -Air Sealing (Infiltration Control) WA 20.12 4 Insulation - Ducting ID 8.04
5 Water Heater- Pipe Insulation WA 19.88 5 Water Heater- Low-Flow Showerheads ID 7.58
6 Insulation - Ducting WA 19.61 6 Ducting - Repair and Sealing ID 6.75
7 Ducting - Repair and Sealing WA 17.70 7 Water Heater- Pipe Insulation ID 5.97
8 Engine Block Heater Controls WA 17.69 8 Insulation - Ceiling Installation ID 5.96
9 Ductless Mini Split Heat Pump WA 17.56 9 Ducting - Repair and Sealing -Aerosol ID 5.00
10 Air-Source Heat Pump WA 16.04 10 Air-Source Heat Pump ID 4.91
11 Serer WA 14.71 11 Lodging - Guest Room Controls ID 4.69
12 Water Heater(<= 55 Gal) WA 13.69 12 Personal Computers ID 4.40
13 Office Equipment -Advanced Power Strips WA 10.97 13 Windows - Low-e Storm Addition ID 4.34
14 Home Energy Reports WA 10.43 14 Ventilation -Variable Speed Control ID 4.27
15 Insulation - Ceiling Installation WA 9.26 15 Home Energy Reports ID 4.24
16 Ducting - Repair and Sealing -Aerosol WA 8.66 16 Grocery - Display Case- LED Lighting ID 3.89
17 Lodging - Guest Room Controls WA 8.62 17 TVs ID 3.81
18 Ventilation -Variable Speed Control WA 8.60 18 Retrocommissioning ID 3.67
19 Advanced Industrial Motors WA 7.81 19 Clothes Washer- CEE Tier 2 ID 3.60
20 Insulation -Wall Sheathing WA 7.46 20 Fan System - Equipment Upgrade ID 3.40
21 TVs WA 6.93 21 Refrigeration - High Efficiency Compressor ID 3.28
22 Windows - Low-e Storm Addition WA 6.63 22 Advanced New Construction Designs ID 2.98
23 Insulation -Ceiling Upgrade WA 6.26 23 Kitchen Ventilation -Advanced Controls ID 2.80
24 Kitchen Ventilation -Advanced Controls WA 5.89 24 HVAC- Energy Recovery Ventilator ID 2.66
25 Personal Computers WA 5.81 25 Water Heater(<= 55 Gal) ID 2.59
18

DRAFT
Appendix A
Washington Energy Burden CBI
#2a: WA Customers with Excess Energy Burden #2b: Percent of WA Customers with Excess Energy Burden
(Before Energy Assistance) (Before Energy Assistance)
70,000 25.0%
60,000
20.0%
50,000
40,000 15.0%
30,000 10.0%
20,000
5.0%
10,000
0 0.0%
CD 1� 00 O O r N M --t 0 W t` M O O r N M q 0 O 1- 00 O O r N M le 0 O n 00 O O r N M le 0
N N N N Cl) M M M M Cl M CO M M le I* le le N N N N Cl) M M Cl) M Cl) M M M Cl) 'IT It 11 It 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
#2c: Average Excess Energy Burden
(Before Energy Assistance)
$2,500
$2,000
$1,500 ,
$1,000
$500
$0
O ti 00 O O r N M Ln cc 1- 00 O O r N M I LO
N N N N C) M Cl) M CM CO) M M M M ICT ICT It ql V V
O O O O O O O O O O O O O O O O O O O O
19 N N N N N N N N N N N N N N N N N N N N

DRAFT
Appendix A
DER Additions CBI
#5a: Total MWh of DER <5MW in
Named Communities
200,000
180,000
t 160,000
?� 140,000
� 120,000
100,000
80,000
60,000
40,000
20,000
0
O 1- 00 O O r N M IqT LO Ia 1- 00 01 O r N M ICT LO
N N N N M M M M M M M M M M 11 1* It I�r IT It
O O O O O O Cl 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
#5b: Total MWh Capability of DER Storage <5MW in Named
Communities
60.0
50.0
t
40.0
30.0
20.0
10.0
0.0 �_
co ti 00 M O r N M O ti 00 O O r N M It IA
20 N N N N M M M M M M M M M M I I I* It
CDO CD O O O O O O CD O O CD Cl O O O CD O O
N N N N N N N N N N N N N N N N N N N N

DRAFT
Appendix A
WA Low Income/Named Community Investments CBI
#6: Approximate Low Income/Named Community Investment and
Benefits
$80
$70 Annual Utility Benefits
Annual NEI Benefits
$60
Annual Investment
to $50
c
$40
$30
$20
$10
$0 to I� 00 O CO N M IV to to ti 00 O O N M IV to
N N N N M M M CO M M M M M M qe 11 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
21

DRAFT
Appendix A
Reserve Margin CBI
#7: Energy Availability- Reserve Margin
40%
■Winter Summer
35%
> 30%
M
Q 25%
C
i 0 20%
d � 1
a 15%
4)
L
10%
N
5%
0%
w ti 00 M O N M 14 LO w 1- CO M O r N M le LO
N N N N M M M M M M M M M M � V le le le
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
Notes:
• Regional Transmission not included in Reserve Margin
22 0
Demand Response reduced from peak load

DRAFT
Appendix A
Generation Location CBI
#8: Generation in WA and/or Connected Transmission System
(as a Percent of System Load)
100%
80% 80% 80% 81% 83% 81% 79% o 0 0 0 77% 77% 77% 77% 77% o 0 76% o
80% 77/0 76/0 76/0 76/0 75/0 76/0 75/o
J
p 60%
V 40%
L
20%
0%
to r- 00 M O N M lq* LO to 1�- 00 M O N M le LO
N N N N M M M M M M M M M M It le le le
CD O Q O O O O O O O O O O O O t) O CD O Q
N N N N N N N N N N N N N N N N N N N N
23

DRAFT
Appendix A
Washington Air Emissions CBI
#9a: S02 #9b: NOx
5 500
4 400
y y
H3 H 300
v v
L L
d 2 0 200
L
1 100
L0 I� CO M O N M -It 0 W f.- W M O N M � 0
O r- CO M CD M -It W n M M CDN M 11 Ln N N N N Cl M M M M M M M CM CO V It le V
N N N N Cl M M Cl M M M M Cl) M 't It 11 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
#9c: Mercury #9d: VOC
0.05 30
25
0.04
to C 20
C O
0 0.03 H
v L 15
L �
0.02 10
0.01 5
tO I-- OO M O � N M l* LOCO Ih OO M O N Cl) Ln
O ti CO M O N M Ln t0 1- 00 T O N Cl) Ln N N N N Cl) M Cl) M M M M M M M 1 11 l 'q
N N N N M M M M M M M M M M le v v v It 1-* O Cl O O Cl O Cl O O O O O O O O O O O O Cl
O O O O O O O O O O O O O O O O O O Cl O N N N N N N N N N N N N N N N N N N N N
24 N N N N N N N N N N N N N N N N N N N N

DRAFT
Appendix A
WA Greenhouse Gas Emissions CBI
#10a: Greenhouse Gas Emissions
1.2
■Direct Emissions ■Net Emissions
1.0
c
0
g 0.8
c
0.6
L
0.4
0.2
_ I
to n 00 M O r N M le In CO n 00 M O r N M V In
N N N N M M M M M M M M M M l le I* le 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
#10b: Regional Greenhouse Gas Emissions
12.0
10.0 10.3 10.2 10.2 10.3 10.1
9.8 9.8 9.7 9.7 9.7 9.7 9.7 9.6 9.6 9.6 9.5 9.5 9.4 9.3
8.8
N 8.0
C
i°
U 6.0
N
4.0
C
O
- 2.0
40 t� 00 O1 O N M IA O n W M O N M N
N N N N M M M M M M M M M M a 7 -q a
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
■Waste Management ■Agriculture ■Transportation
25 ■Residential&Commerical Fuels ■Electric Power Serving Washington ■Electric Power Serving Idaho
■Large Sources Total

DRAFT
Appendix A
Job Creation ( Direct and Induced)
Jobs Created From Resource Selection
1,000 904
900
800 760
700 644 664
600 500479 496 511 529
386412
400 286 321 357
300 157 198 250
200 76 117
100 23 48 -
0
w ti 00 O O r N M le Ln CO 1- 00 a) O N M le LO
N N N N M M M M M M M M M M le le le le le
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
Job estimates based on spending to job relationship today using INPLAN
26

DRAFT
Appendix A
Resource Diversity ( Resource Resiliencv Metrics)
Facility Diversity Fuel Diversity
3,500 3,500
■Winter ■Summer
■Winter Summer
3,000 3,000
2,500 2,500
c 2,000 C 2,000
m m
= 1,500 = 1,500
1,000 1,000
500 500
O n W O O N M V CO c0 n a0 O O N M V CO r— W W O N M -It M CO r` w M O N CI) 7 Ln
N N N N CO c`') CI) M M CO M CI) Cl) M C) V V V V V N N N N M M M M M M CO M M M V V V V V V
CD CD CD CD O O CD CD CD CD CD CD CD O O CD CD CD O O CD O O O O O O O O O O O O O O O O CDN N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N
Transmission Diversity
3,500
■Winter ■Summer
• Metric Meaning
3,000
<1,500 Competitive Marketplace 2,500
1,500-2,500 Moderately Concentrated c 2,000
0
Cn
= 1,500
>2,500 Highly Concentrated
1,000
500
27 N N M O O N M CO In n CO O O N M V n
N N N N CO M M CO CO M CO co CO CO V V V V V V
CD O C. O O O O O O O O O O CD O O CD O CD
N N N N N N N N N N N N N N N N N N N N

Appendix A
Avista 2025 Electric IRP
TAC 10 Meeting Notes
July 16, 2024
Attendees:
Sofya, Atitsogbe, UTC; John Barber, Customer; Shawn Bonfield, Avista; Kim Boynton,
Avista; Michael Brutocao, Avista; Logan Callen, City of Spokane; Katie Chamberlain,
Renewable NW; Kelly Dengel, Avista; Joshua Dennis, UTC; Mike Dillon, Avista;
Michele Drake, Avista; Jean Marie Dreyer, Public Counsel; Michael Eldred, IPUC;
Rendall Farley, Avista; Ryan Finesilver, Avista; Damon Fisher, Avista; Grant Forsyth,
Avista; James Gall, Avista; Bill Garry; Konstantine Geranios, UTC; Leona Haley,
Avista; Jared Hansen, Idaho Power; Lori Hermanson, Avista; Mike Hermanson,
Avista; Fred Heutte, NW Energy Coalition; Erin Heuvel, Avista; Annu John, Fortis; Erik
Lee, Avista; Seungjae Lee, IPUC; Kimberly Loskot, IPUC; Mike Louis, IPUC; John
Lyons, Avista; Ana Matthews, Avista; Ian McGetrick, Idaho Power; Heather Moline,
UTC; Molly Morgan, UTC; Tomas Morrissey, NWPCC; Austin Oglesby, Avista; Kaitlyn
Olson, PSE; Tom Pardee, Avista; Meghan Pinch, Avista; Jared Schmautz, Avista; Xin
Shane, Avista; John Calvin Slagboom, WSU; Nathan South; Darrell Soyars, Avista;
Collins Sprague, Avista; Dean Spratt, Avista; Victoria Stephens, IPUC; Briana
Stockdale, Avista; Jason Talford, IPUC; Andrea Talty, PSE; Brandon Taylor, PSE;
Charlee Thompson, NW Energy Coalition; Tyler Tobin, PSE; Taylor Vallas, Invenergy;
Bill Will, WASEIA; Greta Zink, Avista.
Introductions, John Lyons
John Lyons: Alright, welcome to the 10th TAC meeting. Hopefully everyone had a
good time off for the Fourth of July and getting that week off for the meeting here. We
have a pretty full schedule today. We're going to be talking all things Preferred
Resource Strategy results and then some subtopics on resource adequacy, the
Customer Benefit Indicator impact study for Washington and resiliency metrics. Right
now we're going to talk a little bit about schedule because we are coming up on when
the draft is going to be due fairly soon.
James Gall: Alright, I guess that's my cue to talk about the schedule. We're in the
middle of July and we do have a draft due to the TAC and the Commissions on
September 1 st or the Monday after. We don't think we can get a complete draft done
by that time, but we're committing to a schedule that has certain chapters done by the
September 3rd timeline and then we'll continue with the rest of the chapters on October
1st. And what's on the screen right now is a list of all the chapters that we provided.
Some of the subheadings, and we're going to provide this document to the TAC after
the meeting, it'll be included in the slide deck, but the idea is that chapters. The

Appendix A
economic load forecast would be on time. The L&R chapter, distributed energy
resource option chapter, which includes energy efficiency and demand response.
Supply side options, transmission planning, Preferred Resource Strategy would all be
available along with the CEAP. The draft of those on September 3rd and then the
remaining chapters would be available by the end of the next month, and also including
the Action Plan by the end of the month. Also, we have a number of appendices that
we will have different deadlines proposed for when they would be released. Some of
those would be available in September, some in October, and then some in January
at the normal filing time. I do know we have a draft, or a comments on the draft IRP.
There's any comments due back to us on the around the middle of November, I don't
anticipate changing that schedule. And then I do know that there's at least Washington
has a process for commenting on the draft that will probably occur sometime in
December. I'm going to pause there. If there's any thoughts brought up, I know this is
maybe a surprise that was not in the slide deck that we sent out last week. OK, not
hearing any comments. I think it's maybe a good time to make like, do we have Molly?
Yep. Molly, go ahead.
Molly Morgan (UTC): If I was just going to, I'm sorry, appreciate you showing, getting
specific about what's coming. We spoke about this already. I think this looks fine. I just
wanted to check in about the Work Plan. You note, I think November 15t", as the date
that you would want comments back from TAC members. Is that still what you're
thinking? I'm just wondering with things coming a bit later, is there going to be flexibility
on that. We'll have to fit in an open meeting after that as well.
James Gall: Yeah, that's a good question. I don't think we should change that date
just because of the majority of the IRP that is typically, I'd say people question or more
controversial is all going to be available. And the expected timeline, I'd say lesser
important chapters that are coming later. So, I wouldn't propose the change that.
Molly Morgan (UTC): OK. We would for the open meeting. We'll just have to all
coordinate about that early because that'll probably happen sometime early December
and that can be a busy time for everybody. Yeah, just flagging that we should.
James Gall: OK.
Molly Morgan (UTC): Yeah. Just start thinking about when we can make that happen.
James Gall: Yeah. We do have, I think two additional TAC meetings on schedule and
maybe it would be good on the last TAC meeting if we could have a date locked in. I

Appendix A
don't know. Is that too soon? That'd be mid-August. Is that too soon to try to scope
that out or should that be later?
Molly Morgan (UTC): That's a good question. I was thinking maybe a little later than
that, maybe by sometime in September we could do that, and it'll just let you know
depending on if the Commissioners want it as a recessed open meeting, I'm guessing.
So, since those December meetings are rather busy already, I think I'd probably shoot
for some time in September— ironing that out.
Draft Preferred Resource Strategy, James Gall
James Gall: OK, alright. Any other comments? OK, I don't want to apologize for
wanting to not pause too much. We do have a lot of content and I think we're going to
have some interesting discussion with the Preferred Resource Strategy. So, let's move
to that. We'll pull that up one second here. Hopefully everybody sees this slide.
OK. The plan today is to go through what we call our draft Preferred Resource
Strategy. It is slightly updated from what we sent out last week. And we're going to
show a slide that shows what it was last week, what it is this week, and then we are
planning on having another TAC meeting in two weeks. We'll probably show this again,
if there's any changes, we'll go through that. But I'm trying to lock this down at the next
TAC meeting, so if you have thoughts and comments on this draft, we'd like to hear
those today or very shortly thereafter. Let's get started with this. Mikes going to start
us off on a recap on resource adequacy and then we'll get to the resource strategy.
OK.
James Gall: On June 4th at the TAC meeting, we presented the results of our loss of
load probability study and subsequent to that we are doing some rechecking and the
process to do this study is kind of a two-step process. We have two different models.
We have a model that develops an hourly mode, and we also have the model that
does the reliability testing, and in that process we had industrial loads both in the hourly
model and then also in the reliability model. And so, it doubled that, so we ended up
with basically too much load in our first version. And as you can see, the first column
shows what was presented on June 4t". The LOLP was 10.4%, we're aiming at 5%
and so we need to add 176 and 167 megawatts of extra dispatchable resources to get
that down to 5%. We have now corrected that and got the loads the way they should
be. And with that, we only need 50 megawatts of dispatchable generation, and the
implied planning margin that we calculate from that is the same. The real difference is
that we needed less dispatchable generation to meet that 5% loss of load target and
so that was going forward with that and adding. We're now testing the Preferred
Resource Strategy and different scenarios through the same process and being
attuned to the intricacies of adding our industrial loads in different locations when

Appendix A
you're using a multiple model train to get your answer. OK, so let's go to the next slide.
And Fred has a question. Fred, go ahead.
Fred Heutte: Fred here at Northwest Energy Coalition. Could you just say what
implied planning margin is?
James Gall: I was going to get to that on the next slide.
Fred Heutte: OK, that's fine.
James Gall: Yep. OK. When we run our existing portfolio through our reliability model,
the idea is to create a planning margin that we need to include into our PRiSM model.
Think of it as we have our existing system, you're comparing that existing system to
your future loads, if you're resource deficit, you're adding perfect capacity resources
to develop a planning reserve margin. And based on the study that Mike was working
on, that planning margin in the winter is 24% last IRP, we're at 22%. And what that
means is if you look at our expected load, our 1-in-2 load future, we would add 24%
to that and that would cover forced outages, it would cover poor hydro to some extent
and would cover extreme loads to some extent. And that assumes we would still rely
on 330 megawatts of market. It does not assume that we would never have an outage
or be more than 330 megawatts deficit. It just means that in 95% of the cases we could
meet 100% of the load. At that level, there's still 5% probability that we would not meet,
load or have to buy more than 330 megawatts from the market. In our in our model
which we do have out there on our website, we're using 24% for winter planning
margin, 16% for the summer. The 16% metric is based on our single largest
contingency, which is the Coyote Springs 2 plant, and then we have another adder to
that and that is maintenance. That's something we covered in our last TAC meeting,
we wanted to include an adder for maintenance. But the one problem we were talking
about last time was we don't necessarily know long term when our maintenance is
going to occur. We have some idea. We know we're going to try to move schedules
during non-peak months, but sometimes we do have to take units out at the peak
months.
James Gall: We looked at history and we looked at a forecast as well of the things we
know about and we've done some analysis on those outages. That's the chart on the
upper right corner on how many megawatts we would be adding to our resource need
for those maintenance periods. It's mostly in April, may a little bit in October. We're
trying to avoid peak months in the winter and peak months in the summer, but a little
bit will likely occur. For our final IRP, our assumptions are going to be again, we're

Appendix A
reading this as winter or planning reserve margin 24%, some were 16% and that
includes on top of that, a small amount of maintenance in the peak periods.
James Gall: OK, what does that mean for resource needs? These are the table of our
resource deficits. But on the left is our peak hour deficit by month and year, and on
the right is our energy deficit. Both of these do include adjustments for reserves.
On the one on the left, planning reserve margin is included. Now on energy, on the
right, we include a contingency reserve for the event of bad water or higher loads or
bad production out of our VERs system. What this shows is in 2026, we are deficit 40
megawatts in January and we're deficit 22 megawatts in August. And that shrinks,
actually, the next two years because there's a sale contract that we have in 2026 that
goes away and that's why we go back to a smaller deficit and then because of these
small deficits and the one large deficit, we're proposing to use the market to meet
these requirements. In our Preferred Resource Strategy, you'll see there is a market
purchase to cover these deficits. And then in 2030 is when we start to see our official
long term deficit beginning. And in this case, in the capacity side where in the peak
hour position winter is the driving period followed by summer, which is just slightly less
deficit in the longer period of times. Energy is a little different story. We do have, or
actually barely, even in the winter months, in the summer months in the spring, months
where we're obviously very long on energy position. So, when our model tries to solve
for these deficits, it's looking at each month on an energy point of view and a capacity
point of view to solve these deficits.
James Gall: And then I just wanted to point out also in 2030, we do expect our first
natural gas plant to retire. That's our Northeast Combustion Turbine and we're
expecting that to retire in 2030, which is a change from the last time IRP from 2035 to
2030. There is a small probability that it could retire earlier than that depending on its
emissions testing that it's undergoing for meeting the air quality requirements in the
state of or in the county of Spokane, alright. I'm not going to cover this too much.
James Gall: This is the resource strategy we sent out last week. We did make some
changes to the strategy. The big change was moving the market purchase that showed
up under the Washington category to the system category and I'll cover that in a
second. But I'll just moved up to the new Preferred Resource Strategy. We do have
those market purchases, I moved those over to the shared system. The big change in
the model from last IRP, or last week to this week, is having the market purchases at
least in the short term as a system resource and the previous version of the model
that was done by state. I didn't think that was appropriate given that we don't have
resource allocation by state right now.

Appendix A
James Gall: The second major change is we put in a credit for DER resources for
T&D benefits to the system. That's something we've included in energy efficiency in
the past. We thought it was appropriate to include that credit for DER Solar and DER
batteries and demand response, so those changes do have an effect on the Preferred
Resource Strategies around $28.00 per kilowatt-year. And the resulting change was
that is a little bit more demand response and a little bit more distributed solar. Some
of those occur later in the study. It's not a big impact early on, so how this Preferred
Resource Strategy works is on the top there's a table that we call shared system
resources. These are resources that are picked for both states and we would allocate
that capacity or that energy between each state using our existing PT ratio, which is
around 65% Washington and 35% Idaho. The bottom two tables show resources that
are specifically picked for Washington or for Idaho. But just a caveat, this is somewhat
of a pretend land of what is driving the resource. When we actually get to cost recovery
and how resources are allocated and real life. Right now, we are still under a PT ratio
resource allocation. We do not split our resources up by state at this time. Now, that
doesn't mean we won't in the future, but as of now, that is not the case. But we're just
trying to illustrate which states are the drivers for the resources and which states and
which resources really make sense for both systems.
James Gall: Starting with Washington, actually I'm going to back up, starting with the
shared system where we have the market resources which we covered. There are
around 400 megawatts of wind generation that occurs in that 2031 - 2033 period. And
that follows the Washington wind that you see a little bit earlier on the wind resources
and somewhat solar. What we're finding in this version of the IRP is the ITC and the
PTC are driving selections early before need. So, when the PTC and ITC go away in
2033 is what our model assumes. I don't know if it will or not, but the model sees an
opportunity to get lower cost for renewables. The model is picking as much wind and
solar as it can prior to building major transmission systems. That is why we see so
much wind early in the study. We did limit the amount of wind per year to 200
megawatts, otherwise it would try to build all the wind at one time, which didn't seem
practical to us. We're assuming a layering on of wind in this resource strategy
beginning in 2029 ending in 2033, but that will be solely dependent on what can be
acquired in the future with a minimal transmission cost. If we reran this model with less
when available at cheaper interconnection cost, it would probably pick less. There is
from a future operational point of view, this strategy could change depending upon
what resources are really available when we go out to bid.
James Gall: The last resource to cover on the shared resources is a 10 MW biomass
later on in the time period that is really related to Kettle Falls. You might recall in prior
IRP's we had a 10 MW upgrade. Earlier on we worked with a third party to get that

Appendix A
done, that's ended, and we really don't see that as an upgrade opportunity in the short
run. But in the longer run, when we're looking at repowering that plant at some point
in the future, we likely to see an upgrade there so that's what the 10 megawatts at the
end of the period is. Moving to Washington, the near-term selections are solar and
distributed energy resource solar, and what this really is related to is one part of the
Named Community Fund and one part community solar where tax credits are available
for community solar. We also have a Named Community Fund. We know that there
will be solar to some extent done in the future in our system using those different funds.
This is taking that future solar that we honestly don't know what that future looks like
into account. It's a little bit less than 1 MW a year, but we do want to reflect there will
be some type of community based solar in our system, so that is what's represented
there. We do see a solar facility picked in 2032 that does have a battery attached to it.
That's why you see a 50 MW storage facility at the same time, as though 100 MW
solar facility in 2032.
James Gall: And we did cover a little bit on wind. The strategy there is for Washington
as well as there are different locations selected in the model. I didn't provide the full
detail on this version. It isn't our model, but we have 200 megawatts of Montana wind
selected and then the remaining of it is either off system, wheeling that wind in on
maybe the Bonneville system, and then some located on the business system. I think
that limit is around 500 megawatts and then later on in the portfolio for Washington,
we do start to see those 50 MW market transmission purchase. What that is, is that
transmission line we talked about last week associated to move power in from MISO
or from SPP that connects in Colstrip. We allow the model to pick it in any increments
of 50 MW and because we didn't have all the value streams for that that soon to be
the best case to test whether or not it made sense, but it did get picked at its full 300
MW need is just choosing it over a longer period of time. We may refine that
assumption in the next week or two as we get some more information on that
transmission line, but that is what those 50-megawatt selections are referring to is that
transmission line connection at Colstrip.
James Gall: We do have,just like in the last IRP, power-to-gas or ammonia selections.
Those are basically CTs that run on ammonia. It is selected in 2038. That's the 90
megawatts selected again later in 2042 and the 94 megawatts associated with that
line item in 2044 is actually Coyote Springs cofiring with hydrogen and that was
selected. There are some challenges with that selection where we have to actually be
able to get hydrogen delivered to Coyote. But if Coyote is going to continue to be
operating for serving Washington customers, we'd likely need to have a green fuel
source. If it's possible to get hydrogen delivered there, it would make sense to co-fire
at that facility. We can do around 30% hydrogen at that facility.

Appendix A
James Gall: Wrapping up on the Washington side and 2045, we do see a lot of
acquisitions to replace lost capacity of Rathdrum and the rest of Coyote Springs.
Along with trying to serve 100% clean energy in Washington, which has some
challenges, when you're looking at it from serving 100% all the time and we're going
to get to some of the financial challenges with that in a little bit. But we do see nuclear
energy selected, we do see iron oxide battery selected. It takes a lot of different
resources to get to 100% by 2045 and there will be costs associated with that when
we get to that slide. But this is the first time we have actually seen nuclear get picked
in Avista's IRP, at least in the Preferred Resource Strategy.
James Gall: Moving to Idaho, Idaho is a little bit simpler. We've seen mainly natural
gas CTs picked for Idaho. They really follow when resource deficits began.
When we see 2030, we see a selection there and then that selection serves the needs
for the next several years. We have some lumpiness and then you see another one in
2037 and then another in 2042 when Lancaster goes away and then a small solar
facility, storage facility late in the period.
James Gall: I think I've heard some. So go ahead, there's a question in the chat. It's
from Nathan. So, the model is saying the power-to-gas is less expensive than solar
plus battery from 2038 on. That is correct. What is going on in that situation is we do
have significant winter needs and 4-hour batteries, even with solar do not provide us
the expected QCC which is qualifying capacity credit in the winter months. We have a
system. Let's say you have a sustained cold weather event that we're trying to serve
a battery plus solar could not do that where an ammonia backed, or a hydrogen backed
with storage long term storage could serve that customer for that load.
Nathan South: Thank you. So, the model is limited itself to a 4-hour battery duration.
James Gall: No, we gave it a 4-hour, an 8-hour, and a 16-hour.
Nathan South: OK.
James Gall: What we do is we assign a QCC value for each duration. The longer the
duration, the higher qualifying capacity credit it gets.
Nathan South: Got it. OK. Thank you.
James Gall: Yep. Fred has a question. Go ahead Fred.

Appendix A
Fred Heutte: Yeah, actually I have a few questions. I don't want to break from this
page, and we can come back to it, but I have a question back on slides three and four.
On slide three, I'm just trying to get a better bearing on what you mean by market here,
330 megawatts of market and is that day ahead real time? Is that advanced
purchases? What kind of market is that?
James Gall: They'll be day ahead real time.
Fred Heutte: OK. And in that regard, and I'm not trying to pin down any real direct
numbers here, especially from the experience in January, is that within a reasonable
range?
James Gall: Yes. And maybe the reason why I say yes is when we lost our turbines
on Friday and Saturday morning, we actually were able to buy I think 500 megawatts.
Wen we got our turbines back, we were not in a resource deficit position anymore. We
were actually fairly even. Could we have gotten 330 MW? I don't know that answer.
Fred Heutte: Yeah. It's not a complete. Yeah, completely for sure thing. OK, got it.
And of course, the situation is changing across the region pretty constantly, so all kinds
of issues on that, but I think that seems pretty reasonable. On the next slide, slide 4,
just a quick question, the top row there where it says 1 to 12, 1 wasn't clear about what
those are.
James Gall: Yep. All those are months, January through December.
Fred Heutte: OK.
James Gall: Yep, I can fix that.
Fred Heutte: OK, good. That makes sense.
James Gall: I'll fix that.
Fred Heutte: It seems obvious now that you say it. I just don't know why I didn't pick
that up, and you may have actually said it, so sorry about that.
James Gall: Yep.
Fred Heutte: And now to the Preferred Resource Strategy. I did have a question and

Appendix A
now I'm missing it a little bit. Oh yes, the market in transmission. So that's the Northern
Plains Connector transmission. It's a very interesting project. Of course, where I live
here in Portland, PGE has signed a kind of development agreement, and I think Puget
is looking at that pretty closely. Have you been in contact with the developer on that?
James Gall: Yes, we have.
Fred Heutte: OK, like any big project like that, there are lots of ifs, but it is a very
interesting project and I thought what was most interesting was you said it gives you
some access to wind and MISO, actually it also connects, that project configuration as
understand it, also connects into SPP it's one of the interesting things about it. So,
you really do get a much bigger access to a very wide market and one of the things
we notice, that I noticed, in January was that as these big cold events come through
that caused the high demand, first you get in any locale, you get a little bit of a wind
surge when the big front comes through. And then as the front moves toward the east,
the wind dies off where you are, but further east there's more wind. I did look at MISO
and SPP for the January period and found that actually does happen. So, I think that's
a realistic approach in terms of expanding access to wind resources, in the winter
especially, and it makes a lot of sense. The Northern Plains Connector is a big
expensive line, but it would have benefits all year-round in terms of access, not huge.
mean, it's a couple thousand megawatts. I guess you've got huge market size on the
West side and in the Eastern Interconnection, but it could be very valuable.
James Gall: Yeah. I'm going to briefly cover how we modeled that one and that might
change. For this first draft, we model it as a capacity only resource and we let it pick it
in 50 MW increments at any time after I think 2036. We do not at that time we've done
the study, we don't have the arbitrage value or opportunities to market power between
the different hubs. We looked at it only from a capacity resource. And what I mean by
only capacity resource, think about it as connecting at Colstrip and we have capacity
associated with the wind that's in Colstrip. So, we're only giving it a capacity credit
based on the remaining capacity above what the Montana wind provides us. It has a
small capacity value we're accounting for that it's still picked, but we're not accounting
yet for any of the market opportunity that's there. And with that, I would imagine if we
had that value, we would see that consolidate more into an earlier selection. Where
would it actually show up in reality? We can't take 50 megawatts a year. We're going
to have to take it likely all at once when it's completed, so we may have a revision on
that selection in the next version of this, but we still don't have that arbitrage value yet.
Fred Heutte: OK. Yeah, that makes a lot of sense actually. I would say I'm pleased to

Appendix A
see you're thinking about this in a kind of big picture sense and trying to look at this
step by step, that makes a lot of sense.
James Gall: Yep. I have a little bit of caution on modeling specific projects because
we've done that in the past and we've been burned where the costs were much higher,
or the project couldn't get done. That's another consideration. Should we even include
it in the final plan? Because there is no other resource in this strategy that's related to
it as a specific resource. That's another concern that I have, because we don't know if
it'll actually materialize and should that belong in an IRP or not.
Fred Heutte: Yeah. I see that point, given the track record of this particular developer,
though I think you know a lot of the good United people including the CEO came from
Clean Line and they've shown some capability here. That gives me a little bit more
reassurances I guess. What year is the model allowed to start picking that?
James Gall: I can't remember if it's 2036 or 2037, but it's in that period.
Fred Heutte: Yeah, that seems reasonable. I think you could probably get a little
earlier, but it's a really big project, it'll take a long time.
James Gall: Thanks for the comments. Any other comments coming through?
OK. And I'll just pause there. If there's anything else that comes to mind before we get
to the results. OK. And just wanted to remind everybody in two weeks that our next
TAC meeting will probably cover this again. If there are any changes, we'll cover those.
If not, we'll probably cover how this compares to some of the scenarios we're going to
show next time and actually I believe at the next TAC meeting. After that, we're going
to continue this theme of results for the next two TAC meetings and then, as we start
writing this up in the draft document.
James Gall: OK. I did cover a little bit on the community solar Named Community
Investments. I just wanted to cover this slide; this one might be new as well. It's really
regarding how we handle the unknown of the Named Community Investment Fund.
We have $5 million a year that goes into this fund and lots of different projects could
come out of it. There is a portion of it that has community-based proposals. There are
energy efficiency proposals. There's potentially a reliability proposal. We don't know
what's going to happen with this these dollars, so we try to include what we can by
incenting the model to pick resources that could be picked, and we do that by putting
constraints on them all to spend a certain amount of money. We do have it spend $2
million a year on energy efficiency and how it's credits towards DERs, that's around
$400,000. And what the result of those adjustments are, is we do see 600 kilowatts of

Appendix A
solar added a year until 2036, and it goes up to 900. We do see a little bit of distribution
levels, energy storage in the last half of the IRP, and then we do see increases in
energy efficiency that are pretty significant actually compared to the last plan. So that's
1,400 MW hours a year in the first 10 years and it drops down a little bit in the last 10
years. But we are trying to account for unknowns that fund will create.
James Gall: This is another interesting way to look at how our resource strategy is
going to change. We have new resources in the top of each section and then
retirements as well. You can see our natural gas retirement, net retirement, is around
242 megawatts. Although we have some additions, we have quite a bit of retirements.
We have additions and power-to-gas or hydrogen as well. It's nearly 400 megawatts
over the period. You can see how our wind changes we have between the Northwest
wind, Montana wind, and our PPAs. And then we have 300 MW net additional solar.
Then they have demand response. There are 92 megawatts, which we haven't
covered demand response yet, but that's a precursor to what I'm going to get to in the
next couple of slides, the demand response. An additional 250 megawatts of storage,
we will be losing 100 megawatts of hydro, and then down the last section is the other
resources that are being acquired between the regional transmission we just talked
about, nuclear, biomass and geothermal and a little bit of market in the early periods.
James Gall: That is our draft strategy at this time and let's get into some of the other
results. Wanted to just check in on what we've done on resource adequacy for these
two strategies. Mike, do you want to cover this?
Mike Hermanson: Yeah, this is looking at the 2030 Preferred Resource Strategy and
then also the 2045 strategy. So, what we do is take our current fleet of resources and
contracts and obligations and put them into our reliability model. Use 2030 load and
the results are 0.5% LOLP and as a reminder 5% is our target, so we're well below
that and also well below the LOLE that's used regionally, is 0.1. So, we are actually
one quarter of magnitude below that. And we also use the 2045 resource strategy that
James has just been going over and come up with an LOLP of 2.3% and LOLEV .05%.
Some of the other metrics we went over in the June 4t" TAC that you can refer back
to, those are some of the metrics that are associated with duration and magnitude that
the Northwest Power Council is integrating into their reliability modeling and that's the
reason they don't really have any targets for utility specific applications because each
utility has different needs and systems that they're operating and loads reacting to.
The bottom line is that the Preferred Resource Strategy is adequate to meet the
reliability standards that we've set for ourselves, and we will be doing scenario analysis
with the different scenarios that are tested, the different aspects of the resource
strategy: different loads, different weather futures, etcetera. We have the whole list of

Appendix A
them that's out there. I can recite them, but yes, basic message is we are resource
adequate for this Preferred Resource Strategy.
James Gall: And before we go to Fred, I'd say one of the reasons why the metrics are
so low is this, the lumpiness of resources in 2030. We have some wind coming online,
but a larger natural gas facility than I guess what would be required to get exactly the
5%. That's going to drive that 2030. If you looked at this at 2035, it might be closer to
5% because you have the loads that are growing to offset that lumpiness of resources
and actually the same thing actually occurs in 2045. There's some lumpiness as well
that is occurring. Fred, still got his hand up? Go ahead.
Fred Heutte: Yeah, a quick one, just if I'm looking at the numbers for EUE with
reserves without reserves, they're very close together. What does that tell you about?
And I'm not quite clear about reserves, what reserves means here in this situation. Or
maybe a better way to ask this is at what point do you become concerned about what
the E value is? I presume this is well within what you're looking for.
James Gall: Yeah. I'll answer, maybe your first question first with and without reserve.
Our model can trigger an outage if it's a reserves miss or a delivery risk or an out miss.
So, you have so to be 100% compliant for every hour you have to meet all of your
reserve requirements and all of your energy requirements. We do have cases where
it doesn't occur very often that we could miss the reserve requirement. That's what the
difference is there. As far as what's acceptable, I don't think we have a metric of what's
acceptable. You can see, obviously in 2045 it's significantly high. I guess we'd have to
compare that to what our case was with adding though that 50 megawatts of perfect
capacity, if we go back to slide, I'll go back to in one second, it'd be 103 MW hours
and then in that perfect case we had 268. So, we're still lower there. I guess you may
argue maybe 268 is that the right value. It looks like we do have a typo there on the
one above it. What the fix is for that? Yes. There's a target where you have been only
really targeting that 5% LOLP, and also looking at LOLE at the same time, so we don't
really have a target.
Fred Heutte: OK. Yeah, that makes sense. I'm just thinking an operational sense.
So this basically, if I'm understanding this, if you have well, no, I think you explained it
pretty well, that's fine. I was trying to relate it to what happens if you get into a 1-in-2
situation, but that's probably you can't go directly to that kind of thing with this kind of
model.
James Gall: Yeah. And what we're really looking at here is, are we near 5% or not?
And if we were away, let's say we were 10% LOLP, we would know we probably had

Appendix A
overstated our QCC values. Given that we're below, you can almost argue we've
understated them a little bit. But in 2045, 1 said there's some lumpiness and resource
acquisition, but this is telling us we're kind of in the right ballpark of judging our
reliability metrics for each resource is what happens is we're running separate models.
So, you're running a capacity expansion model separately from your resource
adequacy model, so you have to make assumptions on how well each resource is
going to perform. This is basically showing it's performing where a little bit, maybe
conservative, slightly conservative, on our assumptions for how well each of those
resources will perform.
Fred Heutte: Yeah. Well, you don't want to overbuild, but on the other hand, you want
to be a little bit long. I think that makes sense.
James Gall: Yeah. OK. Alright. Let's move on. Unless there's any other questions.
OK, I know we have about 45 minutes left. That should be plenty of time. The first item
I wanted to cover is how we compare it to CETA, and this is looking at CETA from an
annual and four-year metric point of view. How this works is the dotted line is the CETA
target that the model is trying to meet from a primary compliance point of view and the
black line is the compliance point of view from the 100% for Washington. That 100%
would really start in 2030. Before 2030, that Black Line is just a reference line and you
can see the green bar is how much generation would count towards primary
compliance and then in blue is how much would count is, over that we call it net
monthly load. So, there's been proposals that if your generation exceeds your load,
you would not be able to count that towards primary compliance.
So, that blue represents how much energy is above our load. It is still generation, we'd
own, but it would not count towards primary compliance. Those rules are not final yet,
but it's just illustrative of how our model is looking at this. We have the primary
compliance that is equal to our load or less. And if it's over our load, it counts towards
alternative compliance. So, what this does is it creates a very long position for
renewables, partly because the model is trying to acquire renewables early for the
PTC in the IRA before expirations. But we do expect because of this goal of 100%
every hour of the day in 2045, you can see we're going to have a tremendous amount
of excess generation to meet that 2045 target which makes you wonder why, but all
can explain a little bit. Think of it as you have your highest load period in January for
example, and in order to serve that load in January, you really have two options. You
either build a lot of renewables to hope you have generation show up available in those
hours, or you build a lot of long duration batteries to meet that load. Or maybe the third
case is you build a bunch of nuclear plants. And what this strategy really unfolded is
it's a diversification of those three things. One is you build a lot of renewables, and
you'll have a probability of some of them helping you out in your peak months. Two,

Appendix A
you build quite a bit of long duration storage, which is your ammonia turbines, and
then three is you have a little bit of nuclear. This approach is a little bit of everything
rather than relying on one of those three things to help you meet that 2045 target, at
least for Washington, OK.
James Gall: If you look at energy as a function of our load today, we're around 80%
clean energy. And then by 2030, as a system, we're going to be closer to 90% and
then you can see as you march forward, we're well in excess of 100%, right, 110% by
2045 because of those instances I'm talking about where you can see Washington has
a significant over production of renewable energy compared to its load. And then Idaho
is around 70%. In this strategy, over produce renewables to ensure that you have
enough generation in the critical months when you need it, but also having some
diversification on that with nuclear and long duration storage using power-to-gas.
James Gall: OK, so what does this do for rates and how should we include rates in
the model? I have some questions for the TAC on this. This is our rate forecast. Again,
this is not what it will be. This is how the strategy affects rates when you leave
everything constant. So, how we look at this is we have a power cost forecast in our
model and what we do is we take that power cost forecast and add that to a
representation of all remaining costs that we don't model. And we know that all
remaining costs we don't model will increase over time, so we escalate that. We're
trying to understand is how are our costs affecting the average rate of a customer. We
calculate that amount for Washington and Idaho. You can see Washington rates are
a little bit higher than Idaho today. We don't need to get into reasons why that is, but
on the Idaho side it's a fairly constant growth. On the Washington side, it actually
follows the same pattern. This last IRP, there was a little bit of a separation going on.
We're not seeing that this time, but by 2045, we do expect to see a radical price
increase due to meeting that 100% 2045 requirement. We did see this in the last IRP
as well, a little bit less dramatic, but it did occur. We have not been modeling the 2%
cost cap in the IRPs and I guess maybe a question to the TAC is if we should be and
how should we be modeling or creating a portfolio for CETA from a clean energy
perspective, or should we be modeling it from a perspective of considering the cost
cap, or not. We could be showing a scenario that has that cost cap constraint in there
but it's really what do we want to have as our resource strategy, something that meets
the law, but not the cost cap and the law. Or do we reflect that and say, yeah, there's
a cost cap, we're not going to be able to stay under that and our resource strategy
should be something that's more in line with where we think it will be because of that
cost cap. I want to pause there if there's any thoughts. There's someone in chat. OK,
go ahead.

Appendix A
Molly Morgan (UTC): I don't know. Maybe you said this and I missed it, but why is it
just in the last year that you're exceeding the cost cap? Is outlook an intentional
decision or how does that work out?
James Gall: The reason why has to do with the magnitude of resource changes by
2045. You have gas facilities still available to Washington until 2045. In 2045, even
though you're adding renewable energy, you're losing a significant amount of capacity.
You have to replace that capacity in that year. Now if we had resources retiring earlier
on and you were doing that over time you would see maybe the same endpoint, but
more gradually to that end point, but yeah.
Molly Morgan (UTC): Yeah. OK, that's kind of what I was thinking it was. And so,
you're asking if you modeled the preferred resource strategy with the 2% cost cap the
whole time, that would be the scenario where you would not have that spike at the last
year.
James Gall: You would not, and you would not meet CETA's 100% requirement.
Molly Morgan (UTC): OK, got it.
James Gall: Yep. I mean based on what we did last IRP, we would probably leave
this how it is. It is 20 years from now and a lot can change. It's something to keep an
eye on. From my perspective, which is to not put the cost cap in maybe look at it as a
scenario, but it's something to keep an eye out on.
Molly Morgan (UTC): So, you're basically saying your model is showing for the entire
range, you cannot meet the CETA cost cap.
James Gall: Correct. And we haven't modeled, we haven't put the constraint on there.
It says OK, you got to stay below the cost cap, so will it do things differently to achieve
staying under 2% a year? I haven't tested that yet, but my expectation is it would not
be able to meet the 2045 target and stay under there.
Molly Morgan (UTC): I feel like we'd at least want to see that as a scenario, just
because that would be a problem if that's really what it's showing. So, we want to know
that.
James Gall: OK, of these costs, nominal or real. These are nominal dollar or nominal
rates, average rates, so not a residential rate, not a commercial rate. Think about it as

Appendix A
total utility cost divided by retail sales, but not adjusted for inflation. It is taking into
account inflation, so inflation is taken out of this, no inflation is included. We include
nominal pricing of resources, non-power costs or increasing at I think a little over 3%
a year. So, this includes inflation. If we took this and then took inflation out, it would be
fairly flat. Until you get to the last year.
Nathan South: That's maybe an important thing to call out on the slide.
James Gall: Yep. OK, we can add that comment OK, right. I'm going to go next to
greenhouse gas emissions. This is starting in 2026. What our system emissions would
look like. Today, we have Colstrip, which these emissions are anywhere from 2.5 to 4
million tons. We don't see that reduction here, but there is a significant reduction before
the 2026 time period and then we do see emissions declining. The decline in emissions
is really related to our expectation of our natural gas resources running less. It's not
necessarily resources going away, even though we have a small gas plant that will be
going away in 2030. But that one really doesn't run. It's there for reserves, but the
reductions are really due to changes in dispatch because the market, or the overall
region, has more renewable energy. If that doesn't occur, you'll likely see flatter
emissions. We do see reductions until the 2030s and then it stays fairly flat, and then
and it drops off a little bit in 2045, and that's because of going away from utilizing
hydrogen at Coyote. And then in 2045, if you're wondering, that's really the Idaho
portion of the portfolio that is remaining. But this is the emissions associated with the
Preferred Resource Strategy from a system point of view. The ones that are, what we
mean by sold versus net, is we're trying to calculate how much emissions in total from
our plants. That's the combination of the two. And then in green represents a number
of system sales that we make, and we just assigned those sales to the portfolio
average emissions. That's what's accounted for in the green. Now, it's possible we
may sell clean energy for those sales and that would have no emissions associated
with it or we may not. We just don't know what that that future looks like. We don't
make assumptions on are we selling clean or are we selling non-clean. But we're just
saying, for our sales, these are the amounts associated with them based on our
system emissions. We can see in 2042, we stopped selling on a net basis, and then
2045, there's a little bit more, but some of these sales are really a result of our resource
position where we were very long in some months. And as you add more and more
clean energy, you're going to be long on an energy basis quite often. On top of that,
we are planning for contingency of energy, which means on, on an average year, you
should be selling excess generation in non-peak events.
James Gall: Alright, so getting back to some of the other resource selections and
related selections. Transmission is a component of our modeling when typically

Appendix A
focused on the generation side, but there are transmission actions that come out of
our resource selection. We'll start with the Rathdrum area. In order for these natural
gas facilities to be built, there will be transmission associated with those. We do model
that transmission. We also model the cost of the gas delivery as well, but on the
transmission point of view, there would have to be transmission additions. If we do cite
additional projects in that area, we'll need additional re-enforcement. So, what those
transmission items are, some of the things that Dean covered in a previous TAC,
meaning those costs associated with those. But in order for this all to happen, we do
interconnect requests and then the transmission group will study those requests based
on the official amount of capacity we're asking for and they'll determine what re-
enforcements are needed.
James Gall: Another long-term thing we need to start thinking about is off system
imports and this is not related to the North Plains Connector, but we do need additional
access to import renewable energy and really just to access markets by 2045. This
will likely mean we will need to build new transmission to other areas off our system
to bring in more renewable energy. There's just not enough either renewable energy
on our system that we have imported or the cost to build additional transmission in our
service area to get to those renewables could be more. We're looking at the model
saying it might be cheaper to build to other markets than to build major transmission
systems in our system. Whatever flavor that turns out, and we will need additional
transmission to meet the amount of wind that is selected in the model. And that 2045
period, the last one we've already covered quite a bit, but the North Plains Connector
that has been selected as well. Ask your question Fred.
Fred Heutte: Yeah, real quick on the new CTs, if those actually go forward, how much
cost or how many line miles roughly do you think would be needed for the
transmission?
James Gall: I think the cost is $14 million. I don't know if it's. I think it's 9 miles built.
It's more of a reconductoring.
Fred Heutte: OK. Yeah, it's not like a 50 mile or 100-mile kind of build.
James Gall: No. Now if you site significantly more transmission in that area or
generation in that area, that would be a case where there would be a major rebuild
and I don't know if Dean is on the call or if somebody from the transmission group
could bail me out on what that looks like. I'm not hearing any. Go ahead.

Appendix A
Dean Spratt: I am but I was in the middle of typing an email. If you'd repeat the
question, sorry.
James Gall: Dean, the question is, what has to be built for adding one unit?
And then wrap them area versus adding several units over there.
Dean Spratt: No, that's perfect. Sorry, I just want to make sure I'm clear on the
question. Right now, that's a specific spot. We have a little bit of overgeneration
currently. When I say overgeneration, when we first had modeled the generation, the
CTs there now typically didn't run in the springtime when the hydro was running. With
the EIM and the market changes we've seen as of late, they're running quite often and
we're at the existing transmission capacity when the CTs are running, the combustion
turbines and the combined cycle at Lancaster is running, and we're having high
transfers East to West because of hydro and high Montana-Northwest flows. So, what
we're running into, and the results are pointing to, is we're going to have to add some
more transmission. Some more transmission capacity to add more generation,
specifically in the Rathdrum area.
Fred Heutte: OK. It sounds like you're getting high utilization. If not, overuse on the
transmission and a little bit more headroom would be needed.
Dean Spratt: That's correct. Right now, proposed a project out of the last system
assessment to put a remedial action scheme to bring generation down under certain
circumstances.
Fred Heutte: OK.
Dean Spratt: I worked with their operations group and right now we just wrote an
operating procedure to manually bring generation down once what we're calling the
West of Lancaster cut plane hits a certain level and we're going to try to operate that
because it's not very often it happens, but it it's been more recent over the last few
years. And then from there, we could entertain a remedial action scheme. Our
operations team is a little concerned because it's a pretty good amount of generation
that could be tripped for an outage in that area, which might drive a transmission
project. We're working through that actually, again, revisiting that with the latest cluster
study entries this cycle. And then we're looking at it again, revisiting it from a load
service point of view as well.
Fred Heutte: OK. Yeah, I didn't realize you were, that Avista had. Maybe I'm not too

Appendix A
surprised that remedial action schemes, so RAS, whatever makes some sense.
Thanks, that was useful detail.
Dean Spratt: Yeah, sorry for missing the extent of the question right off the bat.
Trying to do three things at once. This is never the best technique.
Fred Heutte: No, it's great because I got more than I expected from the answer. So,
appreciate it.
Dean Spratt: Probably should be quieter next time.
James Gall: Thanks, Dean.
Dean Spratt: Thanks guys. Bye.
James Gall: OK. Let's move on to demand response. We got about 20 minutes left or
so. A lot of slides left. Demand response in this IRP is definitely a radical change on
the demand response side. Comparing the last plan, and there are some reasons for
that which we'll get into in a little bit, but we have around 73 megawatts over the 20
years selected in Washington around 20 MW, little less than 20 MW for Idaho. Some
of the reasons for the big changes are a couple of things. One is the programs for
capacity or qualifying capacity credit in the last IRP. We think that as more of a
resource responding to meeting load. In this case, we're thinking of them as a load
reduction, so the net effect of that is they get an additional capacity credit of the
planning reserve margin. They're getting more value than what they were last IRP as
far as capacity credit. Think of it as you needed 100 megawatts, and this could respond
to that 100 megawatts. Now it's taking that off of the 100 MW need. Your planning
margin is calculated net of DR, so that actually moved the needle a little bit on selection
of DR.
James Gall: The other big change was we did assign some distribution and
transmission credits to these projects. Like I mentioned earlier, at the beginning of the
meeting around $28.00, that did add a few more programs selected. The program
selected are electric vehicle time of use rates. That's actually a program we have
piloting right now on the commercial sector, maybe it's not a pilot anymore, but we do
expect around 9 megawatts of savings there with the time period. A battery energy
storage with that is referring to customers that have batteries in the future. We don't
have a lot of batteries in our system right now, but batteries in the future we would do
some aggregation of those batteries and potentially save around 10 megawatts. There
is also a peak time rebate that is a pilot we're taking on right now. It's around 6

Appendix A
megawatts variable peak pricing, which is kind of how it sounds, that we have a
different price during certain periods for certain customers. That's around 5 megawatts
savings. And the 2033 period, you can see there's a gap. We have three programs
that should be initiated early in the IRP period and then we have another section in
the early 2030s, and then more in the 2040s. But in the 2030s, you're starting to get
into variable peak pricing. Your party contracts, which is a third-party aggregator.
Some kind of a behavioral program. Surprisingly, time of use rates actually doesn't
show up until 2039. That was actually a program that showed up earlier in the last IRP.
I think the reason for that change is the expected savings compared to the cost have
changed in this new version of the DER potential study. But it does continue to show
up, just later in the study. Then smart appliances, CTA water heaters in the late 2040s,
and then central air conditioning response as well in the late 2040s. Some of these, it
might be appropriate to look at earlier when we go out to bid. I kind of mentioned a
little bit on an RFP in the future. We're not saying that we would start these programs
later, but some of these programs could be looked at and comparative to those RFP
responses if may be there's costs that could be cheaper than what we're assuming.
We would likely expect some of these options to be studied earlier if there are third
parties that want to propose projects to us. On the audio side, three programs didn't
show up as cost effective, not the last three at the end of the period. But there's also
a delay in some of the earlier projects that is due to AMI not being available in Idaho
until our assumption date of 2029. Fred, go ahead.
Fred Heutte: Yeah, just poking around for the right buttons here to push.
I guess my reaction to this is it seems way under what I would expect both in total
amount and in kind of the onset of the programs. For example, on the CTA water
heaters, the CTA on the shelves now, they were going out now. Every water heater
here in Washington, electric water heater, has to have that device in it and I get that
there are complexities to rolling that kind of program out. But 2042, and then 5.5
megawatts. What I'd like to ask is maybe have a separate side discussion with
whoever on your staff would be good, you or your staff or whoever at the company to
talk a little bit more about the DR here and just get a better handle on what the inputs
are because the model just does what the model does.
James Gall: Yep.
Fred Heutte: I'm thinking more about the inputs when my general thought is the DR
here is competing with the market that we talked about earlier and how does that look?
That's where my thought is going.
James Gall: Yeah. On the CTAs that water is the resistance side non-heat pump, so

Appendix A
the heat pump water heaters, just not a lot of energy there to save at time of peak.
They just don't use anything, so that's the reason why. We could probably arrange a
call to AEG, our consultant on that, who came up with these assumptions. We can
schedule a call with them if you'd like. The other thing to think about is on the individual
program. Some of the reactions that customers take can fall in different categories.
So, when you look at them in total versus individual. Let's just say you're looking at
peak time rebate. If we just did a peak time rebate and nothing else, you could get
more than 6 megawatts. But the problem is that when you have these other programs,
they may show up somewhere else, and that's what we're trying to reflect here in the
total number is, I guess really more important versus where it's allocated out, because
you're going to see higher amounts if you only had one program versus you had
multiple programs. So, like first, you may have some customers with water heaters.
Fred Heutte: Yeah.
James Gall: There's different categories where it could show up on how it's
responsive. You got another comment?
Fred Heutte: Yeah. Appreciate that. I would be happy to meet with you and AEG,
which means that I have to really dig more and really go through all the detail on all
the relevant materials here, which I will do. One thing I would say also is that the kind
of cross program issues you just mentioned. If rate design is one part of it and then
specific programs as the other part, I think what PGE, Portland General Electric, has
done. Now my utility, their flexible load plan has at least given them a framework for
addressing those kinds of issues. And they've done a lot in their smart grid test bed to
see how you can roll out different things and try to encourage customer support for
that and not a lot of confusion because I realize that's a big a big issue here. I would
be very interested in following up with you about this. My general sense is just, for
example on the heat pump or the either electric resistance or heat pump water heaters.
James Gall: Yeah.
Fred Heutte: Yeah, they're not very much one by one, but there's a whole lot of them
out there. And if that kind of program, the other thing about that is it doesn't, I think for
the most part, I wouldn't say 100%. What are yours? Can be operated in such a way
that customer doesn't even know when the program is happening when a call is being
done.
James Gall: Yep.

Appendix A
Fred Heutte: From the experience we had from 2018 with the BPA and other utilities
doing the pilot field test on that, I think it's pretty clear that this is the one demand
response resource that is pretty safe to do in terms of customer impact. It's not like air
conditioning or time of use type thing where you're going to have a little, maybe a little
bit of discomfort if you raise your thermostat. That sort of thing. I just hope that we can
find at least, I would like to get a better understanding of what your inputs are here,
and we can have that discussion.
James Gall: OK.
Fred Heutte: Thanks.
James Gall: Yeah. Just make sure you follow up with me. I wanted to bring up one
comment though on the total, this is a pretty significant total for us, 73 megawatts. If
you add the other 30 MW that we have from industrial, you're at 100 megawatts and
our peak load for just Washington. I'm just doing some numbers off the top of my head
here. It's around 1,400 megawatts. You're at 100 megawatts, divided by 1,400, you're
at 7% of peak load.
Fred Heutte: Yeah, that's actually pretty good. I would agree with you about that. But
the other thing here is about the timing. Waiting until early 2040s for a lot of this or late
mid-2030s to early 2040s.
James Gall: Yeah.
Fred Heutte: That just makes me wonder. It just makes me wonder. Thanks.
James Gall: I'll explain some of that because it's important to get into and it has a lot
to do with our load growth pattern. The forecast I should say, who knows what it will
be? But the load growth is very mild until the mid-2030s, and that's where you're seeing
the wind. The small amount of QCC value you get from the wind and a little bit on the
energy storage with the solar, but you have very mild load growth for peak figure
meeting a lot of your peak growth between the early DR and the renewables. Plus, on
the Idaho side, you have the peaker but the load growth really starts to take off in the
mid-2030s and that's why you're seeing it delayed. If we had load taking off in the early
2020s, 2030s or late 2020s, then you would see it earlier. It's really a function of when
that load takes off.
Fred Heutte: Yeah, I can see that. But I also wonder given where we are right now

Appendix A
across the West and market prices during peak periods right now, it's not a problem
because gas prices are historically low, natural gas prices, and that may not I predict
that that will not in fact persist. The history of gas is very volatile. I expect those prices
to start climbing sometime, but when is always a good guess. One more thing, by the
way, I think I mentioned this before, there is a big demand pull coming real soon on
Canadian gas from the new LNG exports. The big LNG Canada terminal is already
receiving gas. They haven't shipped anything yet. That's 2 billion cubic feet a day.
Your supply is partly coming from BC I guess and maybe some from the Rockies, and
then some from Alberta. It's complicated, but I think that the price pressure on gas is
pretty obvious going forward. The market prices are going to start elevating again in
the near future. I would now not predict, but so I just think that this is worth another
look. Thanks.
James Gall: Appreciate it. Alright, let's go. We have 10 minutes left. A comment from
Leona on that too.
Tom Pardee: She just mentioned Avista's participating in NEEA End Use Load Flex
Project that includes work with the CTA 2045 water heaters.
James Gall: More to come on that. Alright, so we're running out of time, and I have
like 10 slides left. I'm guessing we're not going to get through them all, OK, because
we're going to bring this up again in two weeks. I'll continue this conversation and give
you time to think about what we talked about today. Moving on to energy efficiency,
we are definitely seeing higher energy efficiency amounts compared to the last IRP.
There's just more potential than the previous plan, which was actually a little bit of a
surprise to us. Some of these numbers are really kind of hard to the materialize in our
head, but it's energy efficiency. What was selected compared to what load would be
without energy efficiency, it's around 10% of load. Typically, we also like to show the
biennial target. We're not quite ready to show that yet because we're trying to separate
what's NEEA programs versus what's Avista programs. But we're definitely seeing
Washington is going to higher percentage of energy efficiency compared to Idaho.
Typically, if all things were equal, you'd see about 65% of programs in Washington
and 35% in Idaho. Washington's a little bit higher share of that. I think it's closer to 73-
ish percent, and that's really related to higher avoided costs for the Washington side
of the service territory versus the Idaho side of the service territory. So, we're seeing
more savings in Washington. The breakdown on the left shows you where residential
versus commercial versus industrial, but the real fun part is on the next slide that's
coming up.
James Gall: But from a supply curve point of view, this is actually from more of an

Appendix A
economist's point of view, the more interesting slide, but it shows you that potential
ignoring costs. You have GW hours on the bottom. How much you could actually get
over the next 20 years versus the cost of those measures. And as we call them, the
supply curve, the circled areas represent where we're selecting our quantity of energy
efficiency over that period. In Washington, you're at around $150 per MW hour and
what is driving that is partly the energy savings, the capacity value savings, but a lot
of it is non-energy impacts as well. The avoided cost in Washington, say around $150
from a selection point of view versus an actual of what it cost, we're still calculating
that, but that's the equivalent selection point in Washington. Idaho, we use a UCT
method, but that's around $70 where that crossover point. It's a much lower value
because it does not include non-energy impacts, does not include social cost of carbon
impacts and the 10% Power Council adder. So, you have a much lower avoided cost
point for Idaho.
James Gall: What are the top measures that were selected? This is something we've
never shown before, but I thought it would be interesting to look at. Lighting is still one
of the top measures picked. Windows actually showed up in Washington, and that's
really driven by non-energy impacts. That's why that shows up, same with some of the
other measures that have not appeared in the past. But we do see insulation, water
heating related measures, shell measures, and then, well, you're stuck with heat
pumps in there. More water heating, but you can go through this list if you're interested
in it. Also, in our PRiSM model for those you who want to really dig into the details, we
do have every measure that is available, and you can see whether or not they're picked
or not by state. And if you're interested in that and you need help, give us a call or an
email. We'll help you find those, but this just gets you an idea in the first 10 years the
measures that are being picked. OK.
James Gall: We have two options we can try to go through as much of the CBI results
now, or we can, if there's any comments on energy efficiency, we can cover those
now. But I just want to pause really quick to gauge the audience on where we should
proceed because we only have about 5 minutes left. OK. I'm not hearing any ideas,
so maybe what I'll do is just cover an overall structure of the CBIs and maybe not go
through the slides yet, but we'll pick these up next time. But for CBIs, we have in the
last CEIP a number of metrics that we've committed to modeling in the IRP. And those
are energy burden related items, DER items, low income, community investments and
another one is the reserve margin, generation location, air emissions and greenhouse
gas emissions. Those metrics were all ones we could add to modeling. Those are
shown here when we run scenarios, there's been some requests that we show these
metrics with scenarios we're going to need to try to figure out how to do that in a useful
manner, but we are still committing to these CBIs. We did create two new CBIs as

Appendix A
well. I don't want to call them CBIs because they're not necessarily official CBIs
because that will be figured out later. But we did create a job metric calculation using
the IMPLAN model that we recently acquired. We could see how many jobs are
created based upon the resource selection, that's included in here. And then we also
have resource diversity calculations for those of you have been part of the TAC for the
whole TAC cycle, we were talking about doing some resource diversity or resiliency
metrics. We did create a few of those for this IRP. Regarding facility diversification,
fuel diversification, transmission diversification. We'll get into those next time.
James Gall: We're probably, I guess we do have 5 minutes. We could probably cover
this one, but what we're trying to measure here is using the Herfindahl [Hirschman]
Index. Do we have a diverse set of resources or not? The metrics are if you're over
2,500, you're very concentrated, not very diverse. If you're between 1,500 and 2,500,
you're moderately diverse, and if you're less than 1,500, you're very diverse. And what
we found is that from our generation point of view, we're very diverse. We have lots of
units that not one unit is the main concern or a group of units, but when you get into
transmission, we are getting more consolidated. We only have few areas where
generation is created. We don't have a lot of areas where generation is created. It's
usually north Idaho, it's West, and the Mid-C. We do see some diversification. We're
in that mid-area, but then on fuel diversification, we are towards the higher end earlier
on where we have very few fuel sources. But as you add resources towards 2045, our
fuel mix is getting more diverse. There's less, I guess you can say with resiliency
concerns potentially from that matter, but I'm hearing some it was just confirming that
it's IMPLAN. OK. But this is kind of a new metric. We thought it'd be interesting to
study, and I would say the results of this show, there's not a lot of concern, but there
appears to be some benefits and some of the fuel diversity of our resource selection
compared to where we're at today. Any other comments? I don't want to get into all
these slides. We do have them available. Like I said, we'll cover some of these next
TAC meeting. Anything before we call it a day?
Fred Heutte: Yeah, this is Fred. Just to say, not now, but maybe we can come back
and talk a bit more about this diversity metrics.
James Gall: Get like I said, I don't know if it's useful or not. It's something we thought
we'd try.
Fred Heutte: Well, the idea of it is really good, but it's interesting to see
what it is now and what it might become.
James Gall: Alright. Any other comments? Alright, so next TAC meeting, if there's any

Appendix A
changes to the resource strategy will cover it. We will cover as many scenarios as we
can in the next week as we got to get slides out by Wednesday or Thursday morning.
We'll have a few scenarios. Definitely, we won't have them all by next TAC meeting
and then the next staff meeting. Hopefully we'll have all the scenarios completed. I see
a hand up. Go ahead.
John Calvin Slagboom: Good morning. I have a question about way back at slide
six. It looks like there was 150 megawatts of nuclear projection for 2045. Did I miss
something with regards to that or was that not spoken to?
James Gall: Yep. We did talk about it briefly.
John Calvin Slagboom: OK. Because I was at the Future of Electric Generation
conference with Avista at the SL Conference Center in Pullman and there was some
questions about that. But something like that wasn't on Avista's radar in terms of
something that you were planning for, but it's on the slide. So, I'm just confused. Want
to get some clarification?
James Gall: I could probably explain why. Our last resource strategy, nuclear wasn't
selected. A lot of people, they've not seen our new strategy yet, so they might be
thinking of what we had in our last plan. Now we're continuing that process of every
two years. This is starting point. We've had this strategy out internally for a week, so it
may not be fully communicated to everybody and it's in a draft status right now.
John Calvin Slagboom: OK.
James Gall: Let's say you went to that conference next year and this was our final
strategy and then you might get a different answer.
John Calvin Slagboom: Awesome. Thank you very much. Appreciate that.
James Gall: This is just off the cutting room floor, I guess you could say. OK. We're
at 10 o'clock. I appreciate everybody's time today. Appreciate the interaction and we'll
see you all again in two weeks. And for those of you that are on our gas TAC process,
we'll see you tomorrow.
Chat Notes:
[8:19 AM] Meeting started
[8:57 AM] Nathan South: So the model is saying the PtoG is less expensive than
solar+battery from 2038 on?

Appendix A
[9:25 AM] Nathan South: Are these costs normalized to current dollars?
[9:46 AM] Haley, Leona: Avista is participating in the NEEA End Use Load Flex project
that includes work with the CTA-2045 water heaters.
like 1
[9:56 AM] Fred Heutte (Unverified): presume that "INPLAN" is IMPLAN . . .
[9:56 AM] Pardee, Tom: correct, IMPLAN
[9:57 AM] Fred Heutte (Unverified): no prob : )
[9:58 AM] Molly Morgan (UTC):(Unverified): yes I think its useful to look at
[10:05 AM]: Meeting ended: 1 h 46m 4s Avista's 2025 Electric IRP TAC Meetings
Tuesday, July 16, 2024 8:30 AM - 10:00 AM. 1 h 31 m 23s

A endix A
I ,1
IF
2025 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 11 Agenda
Tuesday, July 30, 2024
Virtual Meeting — 8:30 am to 10:00 am PTZ
Topic Staff
Introductions John Lyons
Connected Communities Program Update Kit Parker
Avista — Spokane Tribe Energy Resiliency
Partnership Update Meghan Pinch
Preferred Resource Strategy Results Planning Team
Avoided Costs James Gall
Remaining TAC Schedule & Scenario Planning James Gall
Microsoft Teams meeting
Join on your computer, mobile app or room device
Click here to join the meeting
Meeting ID: 264 797 739 040
Passcode: MLVkp8
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Or call in (audio only)
[phone]„525313571# United States, Spokane
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���r r/ISTA
2025 IRP TAC 11 Introductions
John Lyons, Ph.D.
Technical Advisory Committee Meeting No. 11
July 30, 2024

Appendix A
Today's Agenda
Introductions, John Lyons
Connected Communities Program Update, Kit Parker
Avista — Spokane Tribe Energy Resiliency Partnership Update, Meghan Pinch
Preferred Resource Strategy Results, Planning Team
Avoided Costs, James Gall
Remaining TAC Schedule and Scenario Planning, James Gall
2

Appendix A
Remaining 2025 Electric IRP TAC Schedule
• TAC 12: August 13, 2024: 8:30 to 10:00 (PTZ) — Scheduled
o Preferred Resource Strategy Results (continued)
o Portfolio Scenario Analysis (continued)
o LOLP Study Results (continued)
o QF Avoided Cost
• Propose to extend TAC 12 meeting to 2.5 hours and move to:
o September 10, 2024, 9:00 am to 11 :30 am (PTZ)
o September 17, 2024, 9:00 am to 11 :30 am (PTZ)
o September 17, 2024, 1 :00 pm to 3:30 pm (PTZ)
• September 2, 2024- Draft IRP Released to TAC with the following chapters:
o Economic and Load Forecast
o Long Term Position
o Distributed Energy Resource Options
o Supply Side Resource Options
o Transmission Planning and Distribution
o Preferred Resource Strategy
o Washington Clean Energy Action Plan
3

Appendix A
Remaining 2025 Electric IRP TAC Schedule
• Virtual Public Meeting- Natural Gas & Electric IRP (Moving to November 2024)
o Recorded presentation
o Daytime comment and question session (12pm to 1 pm- PST)
o Evening comment and question session (6pm to 7pm- PST)
• October 1 , 2024- Remainder of Draft IRP Released to TAC with the following chapters:
o Executive Summary
o Introduction, Interested Party Involvement, and Process Changes
o Existing Supply Resources
o Market Analysis
o Portfolio Scenarios
o Action Plan
4

VISTAW IF
Connected
Kit Parker, Renewables Products and Services Manager
Technical Advisory Committee Meeting No. 11
July 30, 2024
Iedo, Pacific urbanova

Appendix A
Program Objectives EQ 75 = 1 25
• Create flexible load 0 Foster community-based
Buildings and Homes
• Reduce energy costs solutions 50-75 Residential and 25-50 Commercial
• Maintain occupant comfort 0 Develop scalable model
2 . 25mw
During Program Flex Events Flexible Load Created
Flex Event
1-4 hours
k' Grid Peak
Lma
er Thermostat
Set Set Temperature Temperature . . .• . - - . - •
another time in the
ithin a comfortable . .F adjustment
Pacific
Northwest Shifting load to avoid grid peaks
NATIONAL LABORATORY
/III.
,aw=i►1MF.STA edr- Adi'l 7111 f,1STA

Appendix A
Project Timeline
PROJECT PILOT TESTING ANALYZE & REVIEW &
PLANNING ASSESSMENT PHASE EVALUATf. PUBLISH _.,
Strategic planning and Enrollment of first Completion of Aggregation and Finalization of a business
design for delivering participants and testing enrollment and analysis examination of energy model playbook allowing
demand flexibility and of planned energy of preliminary testing efficiency measures and for program replication
energy measures. measures from flex events grid service testing and management
2023 2025 2025 • 2026 2027
July January July July July 19
- - - - - - - - - - - - - - - -
,A0431FIVIsra

�I11 V�sTA
Avista - Spokane Tribe Energy Resiliency
Partnership Update
Meghan Pinch, Manager, Energy Efficiency Programs
Technical Advisory Committee Meeting No. 11
July 30, 2024

Appendix A
Clean Energy Fund Grid Modernization Grant Award Overview
Awarded project: Financial support to design and engineer a clean and resilient
energy storage project in partnership with the Spokane Tribe. The project will
support increased energy resilience and energy sovereignty. Funding does not
include construction of project.
You
Project Funding: $480,000 in total (Avista to provide $240,000 in-kind match to
$240,000 in funding from Department of Commerce).
Grid
Modernization
grants will support
acrossutilities
state in building
_ _ Iand integrating
_ a
. new technologies
that support their
_ r
- _ clean energy
transition plans.
�i'iVISTA

Spokane Tribe Grid Resiliency Station Appendix A
"Switchable" platform that could 34.5 kV SOURCE
enable power to be switched - - �• y
3 Pos.JE 1 1 1 1 1 ^
between three or more stepdown 35kV2ooA ^
circuits in an emergency STORAGE z.SMVA .;.
34.5/13.2kV
2.51VIVA 2.5MVA I Spare storage WiFi Access for Community
34.5/13.2kV 34.5/13.2kV during emergency scenarios
Would replace elevated building 480V/13.2kV
transformers currently behind post
office / trading post 2 Pos.13.2kV
...... .....
S&C Vista w/SEL 4 Pos.13.2kV
for DLM ••••• -•• S&C Vista w/SEL
for DLM
Would create a "critical loads" circuit
to provide power to Tribal Ad m i n Eaton Padmount 3x 10 Eaton Padmount 3x 14) 93xl(D Eaton Padmount
building, Wynecoop Memorial Voltage Regulators 13.2kV Voltage Regulators 13.2kV 2kV Voltage Regulators
all
Health Clinic, and Public Safety IF
W13.2kVLL
buildings during emergencies
EV ACCESS
CIRCUIT#1 CIRCUIT#2 CIRCUIT 3 GENERATOR (FUTURE)
NON CRITICAL NON CRITICAL CRITICAL LOADS � (FUTURE)
Could leverage existing generation
resources to sustain summer loads
for up to 7 days
�ll���sra

Equipment Layout Concept Appendix
a
t Control Enclosure
f
mow t ti--
c
Battery Storage
__T
ELM
s - , f
t + ,
PadmoUnt Equipment
0 I
t-

Appendix A
Recent Activities and Next Steps
• Avista provided technical assistance to the Tribe in applying
for $2.75 million from Department of Commerce Tribal Clean
Energy Grant
• Additional funding been committed from a mix of federal
formula Tribal DOE grants and Avista-provided funding
• Total project costs are expected to be around $6.65 million
• Avista and the Spokane Tribe are considering applying for
additional grant funding for additional scope items
5 A047MISTA

���r r/ISTA
2025 Electric Integrated Resource Plan
Draft Preferred Resource Strategy
James Gall
Technical Advisory Committee Meeting No. 11
July 30, 2024

DRAFT
Appendix A
Preferred Resource Strategy (7/16/2024)
jjjjjjhw -^a6 2027 2028 2036 2037
Shared System Resource
Mrkt/Trans 40 4 10 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Natural Gas 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Solar 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Wind 0 0 0 0 0 100 100 200 0 0 0 0 0 0 0 0 0 0 0 0
Storage 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
PtoG 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Nuclear 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Geothermal 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Biomass 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 10 0
RNG 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
DR 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Washington
Mrkt/Trans 0 0 0 0 0 0 0 0 0 0 0 50 0 0 50 50 50 50 0 50
Natural Gas 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Solar 0 1 1 1 1 1 101 1 1 1 1 1 1 1 1 1 1 1 200 5
Wind 0 0 0 200 200 100 0 0 0 0 0 0 0 0 0 140 0 120 0 200
Storage 0 0 0 0 0 0 50 0 0 0 0 0 0 0 0 0 0 0 104 62
PtoG 0 0 0 0 0 0 0 0 0 0 0 0 90 0 0 0 196 0 94 0
Nuclear 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 150
Geothermal 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 20
Biomass 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
RNG 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Idaho
Mrkt/Trans 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Natural Gas 0 0 0 0 99 0 0 0 0 0 0 90 0 0 0 0 124 0 0 0
Solar 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Wind 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Storage 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 35 0
PtoG 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Nuclear 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Geothermal 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Biomass 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
2 RNG 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Appendix A
Revised Preferred Resource Strategy (2026=35)
20261 2027F 2028 2029 2030 2031 F 20321 20331 20341 2035 Total
Market 25.8 2.5 6.4 - - - - - - - 34.6
Regional Transmission - - - - - - - 198.4 - - 198.4
Natural Gas - - - - - - - - - - -
Solar - 0.5 0.6 0.6 0.7 0.8 0.8 1.0 0.5 0.5 5.9
Wind - - - 200.0 200.0 165.9 66.0 104.0 - - 736.0
Storage - - - - - - - - - - -
Power to Gas - - - - - - - - - - -
Nuclear - - - - - - - - - - -
Geothermal - - - - - - - - - - -
Biomass - - - - - - - - - - -
Total 25.8 3.0 6.9 200.6 200.7 166.7 66.8 303.4 0.5 0.5 974.9
Cumulative Demand-Side Management I
~7$,000 MWh
Demand Response MW 0.5 1.4 3.0 4.9 7.2 8.7 9.4 10.2 11.1 12.4
Energy Efficiency aMW 3.4 7.1 11.2 15.8 19.7 24.0 29.2 34.5 39.8 44.5 Biannual EE Target
Market 13.6 1.3 3.3 - - - - - - - tlRe ional Transmission - - - - - - - 101.6 - -Natural Gas - - - - 90.2 - - - - -
Solar - - - - - - - I - - - -
Wind - - - - - 34.1 34.0 53.3 - - 121.4
Storage - - - - - - - - - - -
Power to Gas - - - - - - - - - - -
Nuclear - - - - - - - - - - -
Geothermal - - - - - - - - - - -
Biomass - - - - - - - - - - -
Total 13.6 1.3 3.3 - 90.2 34.1 34.0 155.0 - - 331.5
Cumulative Demand-Side Management
Demand Response MW - - - 0.1 0.3 0.7 1.0 1.2 1.3 1.3
Energy Efficiency aMW 1.2 2.6 4.1 5.9 7.2 8.6 10.5 12.6 14.5 16.3
3

Appendix A
Revised Preferred Resource Strategy (2036=45
2036 2037 2038 2039 20401 20411 20431 2044, 20451 Total
Market - - - - - - - - - --Regional Transmission - - - - - - - - - - -
Natural Gas - - - - - - - - - - -
Solar 0.5 0.5 0.5 0.5 0.5 0.5 0.5 180.5 120.5 0.6 305.1
Wind - - - - - 140.0 - 120.0 108.4 200.0 568.4
Storage - - - - - - - 90.0 86.1 85.3 261.4
Power to Gas - - - - 90.2 - 209.8 - - 94.3 394.3
Nuclear - - - - - - - - - 100.0 100.0
Geothermal - - - - - - - - - 20.0 20.0
Biomass - - - - - - - - - 64.4 64.4
Total 0.5 0.5 0.5 0.5 90.7 140.5 210.3 390.5 314.9 564.6 1,713.E
Cumulative Demand-Side Management
Demand Response MW 13.6 15.1 18.8 26.5 31.9 36.6 40.6 44.6 48.4 51.6
Energy Efficiency aMW 49.1 53.5 57.E 61.1 64.4 67.E 70.0 72.7 75.2 77.3
Idaho (MW- Nameplate)
Market - - - - - - - - - --Regional Transmission - - - - - - - - - - -
Natural Gas - - - - 90.2 - 94.9 - - - 185.1
Solar - - - - - - - - - - -
Wind - - - - - - - - - --Storage - - - - - - - - - - -
Power to Gas - - - - - - - - - - -
Nuclear - - - - - - - - - - -
Geothermal - - - - - - - - - - -
Biomass - - - - - - - - - 3.2 3.2
Total - - - - 90.2 - 94.9 - - 3.2
Cumulative Demand-Side Management
Demand Response MW 1.4 1.4 1.7 2.1 2.5 2.9 3.7 5.8 8.7 10.6
Energy Efficiency aMW 18.21 20.0 21.7 23.2 1 24.61 25.9 27.0 28.21 29.3 30.4
4

Appendix A
North Plains Connector
Oliver
1 1 County
i;eerll r... 1 1 1 LLAUt
1 `
1 rA_EN: TM
Dickr su i I n,an
I �Blsrnarck
• I - 1 1 1- /y
Jd1 — 1 I _
-————ti � bbiEs ciry •-' t c[ Nrnwxe I I � �
� 1 CJ61FA ti tu.Ny I � I UJMi —,V r
1 1 • �
I 1
I
1
1
I 1
345 W AC Segment : _ _ _ : Project's route is under active development
5W W oc Segment and is subject to change.
At the 7/16/2024 TAC Meeting: 300 MW of this resource was selected between 2037-45. It was
discussed this resource cannot be acquired in increments and not all benefits were modeled at this
time
5

Appendix A
Wind Selection Observations
• 850 MW of wind is selected between 2029-2033, this is a financially
beneficial early action taking advantage of IRA benefits and low PPA prices.
— If tax credits change or low priced PPA terms do not materialize, this selection will
change.
— Avista has limited transmission to integrate new wind in the service territory, if wind
projects are exported off system, the PRS selection will reduce.
• Concerned with Montana Wind winter QCC could underestimate need for
winter capability.
• Additional wind could be economic for Idaho customers, but the model
allocates to Washington due to limited options to meet long-term CETA goals.
7

DRAFT
Appendix A
Demand Response
Customer Segment Washington Idaho
Start Year Start Year
Electric Vehicle TOU Commercial 2026 8.8 2029 0.7
Battery Energy Storage All 2026 10.4 2035 1 .5
Variable Peak Pricing Large Commercial 2026 5.4 2029 1 .7
Peak Time Rebate Residential/Sm. Com. 2035 5.5 2040 4.0
Behavioral Residential/Sm. Com. 2038 1 .9 2043 1 .0
Time of Use Rates Residential/Sm. Com. 2038 2.5 n/a
Third Party Contracts Large Commercial 2039 18.0 2044 3.1
CTA ERWH Residential/Sm. Com. 2041 3.4 n/a
Central A/C Residential/Sm. Com. 2043 5.2 n/a
Total MW by 2045 (Highest of Summer/Winter) 61 .2 12.0
Assumptions:
• Current industrial contract remains
• Idaho AMI by 2029
• Total savings assumes projects do not overlap into other programs
8 • Totals include ramped savings to 2045, based on the time period the program was selected

Appendix A
EnergyEfficiencyTop Measure Types
Row Measure State 2035 Row Measure State 2035
1 Linear Lighting WA 81.34 1 Linear Lighting ID 43.34
2 Windows - High Efficiency (ENERGY STAR 7.0) WA 27.98 2 High-Bay Lighting ID 12.70
3 High-Bay Lighting WA 25.00 3 Water Heater- Pipe Insulation ID 7.90
4 Water Heater- Pipe Insulation WA 18.13 4 Ducting - Repair and Sealing ID 6.75
5 Ducting - Repair and Sealing WA 17.70 5 Insulation -Ceiling Installation ID 5.96
6 Ductless Mini Split Heat Pump WA 17.11 6 Air-Source Heat Pump ID 4.91
7 Air-Source Heat Pump WA 16.05 7 Lodging - Guest Room Controls ID 4.69
8 Water Heater(<= 55 Gal) WA 13.69 8 Windows - Low-e Storm Addition ID 4.34
9 Home Energy Reports WA 10.43 9 Ventilation -Variable Speed Control ID 4.27
10 Insulation - Ceiling Installation WA 9.26 10 Home Energy Reports ID 4.24
11 Ventilation -Variable Speed Control WA 8.60 11 Grocery - Display Case - LED Lighting ID 3.89
12 Advanced Industrial Motors WA 7.81 12 Clothes Washer- CEE Tier 2 ID 3.60
13 Insulation -Wall Sheathing WA 7.46 13 Fan System - Equipment Upgrade ID 3.40
14 Windows - Low-e Storm Addition WA 6.63 14 Refrigeration - High Efficiency Compressor ID 3.24
15 Building Shell -Air Sealing (Infiltration Control) WA 6.03 15 Kitchen Ventilation -Advanced Controls ID 2.75
16 Kitchen Ventilation -Advanced Controls WA 5.89 16 HVAC - Energy Recovery Ventilator ID 2.66
17 Clothes Washer-CEE Tier 2 WA 5.70 17 Water Heater(<= 55 Gal) ID 2.59
18 Strategic Energy Management WA 5.38 18 General Service Lighting ID 2.17
19 Insulation - Ceiling Upgrade WA 5.16 19 Ventilation - Demand Controlled ID 2.07
20 General Service Lighting WA 4.90 20 Insulation - Ceiling Upgrade ID 1.69
21 Pumping System - System Optimization WA 4.89 21 Area Lighting ID 1.68
22 HVAC - Energy Recovery Ventilator WA 4.77 22 Water Heater- Faucet Aerators ID 1.48
23 Fan System - Equipment Upgrade WA 4.54 23 Furnace - Conversion to Air-Source Heat Pump ID 1.32
24 Connected Thermostat - ENERGY STAR (1.0) WA 4.49 24 Pumping System -System Optimization ID _ 1.27
25 Refrigeration - High Efficiency Compressor WA 3.98 25 Refrigeration - High Efficiency Evaporator Fan Motors ID 1.26
9

DRAFT
Appendix A
Avista Transmission Considerations
• Rathdrum Area: New natural gas CTs begin in 2030, these are likely located
in North Idaho, new transmission will be required , if projects continue to be
sited in the area additional reinforcement is needed .
• Off-System Imports : Need to increase connections to markets/areas to
reach additional wind to import by 2045.
• If within system renewables are exported off system , additional transmission
within Avista BA will be needed .
10

Appendix A
Clean Energy Forecast
140%
120% ■Existing New
100%
21% 13% 12% °
38% 28% 35
G
g0% 11% /o
J u%
4— 60%
O
V40% 1% 77% 79% 80% 77% 78% 75% 2% 73% 71% 66% 68%
i 60% 54/o° 6°
IL 20%
0% L"d
O c E O c E O c E O c E O C E
CO
U CO U U U)
m Cu Cu m m
3: 3: 3: 3: 3:
2026 2030 2035 2040 2045
11

Appendix A
Average Energy Rate Forecast
$0.30
—Electric Washington
$0.25 — —Electric Idaho
$0.20
00
am
$0.15CD
Q � —
$0.10
$0.05
$0.00
CD 1­ 00 M U') C9 r— 00 O O N M Nt LO
N N N N CY C''� C'"i Cr) %� CO CO M M M 't :T I: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
12 Assumes non-modelled cost increase by 3.8% per year

DRAFT
Appendix A
Washington Energy Burden CBI
#2a: WA Customers with Excess Energy Burden #2b: Percent of WA Customers with Excess Energy Burden
(Before Energy Assistance) (Before Energy Assistance)
70,000 25.0%
60,000
20.0%
50,000
15.0%
40,000
30,000 10.0%
20,000
10,000 5.0%
0 0.0% IIIHIIIIIIH-1111111
CO r CO O) O N M V N to h CO O O N M 1 0 CO 00 O O N M 'IT 0 O 1� CO C) O N M 1 M)
N N N N M M M M M M M M M M It It I* It 11 It N N N N M M M Cl M M M M M M I* lzr 11 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
#2c: Average Excess Energy Burden
(Before Energy Assistance)
$2,500
$2,000
$1,500
$1,000
$500
$0
CO 1- 00 M O N CO) LO CO 1%- 00 M O N CO) LO
N N N N Cl) M M M M M Cl) M M M
13 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

DRAFT
Appendix A
DER Additions CBI
#5a: Total MWh of DER <5MW in
Named Communities
200,000
180,000
� 160,000
?� 140,000
120,000
100,000
80,000
60,000
40,000 lip
20,000
0
W h 00 O O r N M le W (O ti 00 O O r N M le W)
N N N N M M M M M M M M M M 1 le 11 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
#5b: Total MWh Capability of DER Storage <5MW in Named
Communities
3.0
2.5
2.0
1.5
1.0
0.5
0.0
to 1- 00 M O r N M 41 w 1- 00 M O r N M le w
N N N N M M M M M M OM M M M le le le le le le
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
14

DRAFT
Appendix A
WA Low Income/Named Community Investments CBI
#6: Approximate Low Income/Named Community Investment and
Benefits
$70
Annual Utility Benefits
$60
Annual NEI Benefits
$50 —Annual Investment
c $40
O
$30
$20
$10
CO ti 00 M O N M Iq Ln W ti 00 M O r N M Iq LA
N N N N M M M M M M M M M M I* I* 1* 14 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
15

DRAFT
Appendix A
Reserve Margin CBI
#7: Energy Availability- Reserve Margin
35%
■Winter Summer
ca
d 30%
d
G 25%
Q
20% 'd
i J
a 15%
as
L 10%
5%
0% -
�C ti O O O T N M 14 U) CO ti O O O r N M It 0
N N N N M M M M M M M M M M IV 11 NT It 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
Notes:
• Regional Transmission not included in Reserve Margin
16 0
Demand Response reduced from peak load

DRAFT
Appendix A
Generation Location CBI
#8: Generation in WA and/or Connected Transmission System
(as a Percent of Generation)
100%
80% 80% 80% 81% 83% 81% 79% o o a o 0 0 0 0 0 0
(� 80% 77/0 76/0 76/0 76/0 76/0 76/0 76/0 77/0 77/0 75% 76/0 75% 74%
J
p 60%
V 40%
L
20%
0%
(0 f- 00 O N M 'Cr LO w 1- 00 0) O N M ICT V)
N N N N M M M M M M M M M M 1 1* 11 11 V
O O O O O O O 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 N N N N N N N N
17

DRAFT
Appendix A
Washington Air Emissions CBI
#9a: S02 #9b: NOx
5 500
4 400
N N
H3 H 300
2 t�
'L 'L
2 200
1 100
0 = = M = — — — — — — — —
IIIIIIIIIIIIIIHIIII
t0 f` CO O O N M � N t0 f` 00 Cn O N M � LO 0 _
N N N N Cl M M M M 01 M M M M V � V 't It It t0 r- O O O N Cl It U) w r 00 O O N M � 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 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
#9c: Mercury
#9d: VOC
0.05
30
0.04 25
to 20
c
0 0.03
2
C v 15
0.02
10
0.01
■ 5
0.00 -
t0 r- 00 O O N PM le to tO h 00 M O N M le to W h 00 M O r N M t to CO t• 00 O O c- N CO V to
N N N N M M M M M M M M Cl) M I 'Cr 7 le le N N N N M M M M M M M M M M It 'q le IT 'e
O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O
18

DRAFT
Appendix A
WA Greenhouse Gas Emissions CBI
#10a: Greenhouse Gas Emissions
1.2
■Direct Emissions ■Net Emissions
w 1.0
c
0
0.8
N
C
H 0.6
.L
M 0.4
0.2
CO
f-- CO 0 O � N M It O O n M O O � N M � U')
N N N N M M M M M M M M M M 't It It
CD CD O O O O O O O O CD O CD 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
#10b: Regional Greenhouse Gas Emissions
12.0
10.0 10.3 10.2 10.2 10.3 10.1
9.8 9.8 9.7 9.7 9.7 9.7 9.7 9.7 9.7 9.6 9.6 9.5 9.4 9.3 8.8
� 8.0
H
0 6.0
L
4.0
C
0
2.0
t0 r� OD OA O N M V LL7 CO r� OD C1 O N M -4 Ln
N N N N M M M M M M M Cl) Cl) M V -q V 11 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
■Waste Management ■Agriculture ■Transportation '
19 ■Residential&Commerical Fuels ■Electric Power Serving Washington ■Electric Power Serving Idaho
■Large Sources Total

DRAFT
Appendix A
Job Creation ( Direct and Induced)
Jobs Created From Resource Selection
900
798
800
700 575 616
600 531
500 392 412
400 263 283 299 314 332
300 160 188 216 241
200 96 128
00 19 39 62
CO ti CO 0) O r N M I LO CD Il- CO M O r N M 1* LO
N N N N M M M M M M M M M M q qqT 44 IT 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
Job estimates based on spending to job relationship today using INPLAN
20

DRAFT
Appendix A
Resource Diversity ( Resource Resiliency Metrics)
Facility Diversity Fuel Diversity
3,500 3,500
■Winter ■Summer ■Winter ■Summer
3,000 3,000
2,500 — 2,500
C 2,000 C 2,000
in <A
= 1,500 = 1,500
1,000 1,000
500 500
(fl � 00 O O N M V LO (0 N O O N CO V Ln (0 rl- 0D O O N CO V Ln (0 1- W O O N M V Ln
N N N N cM M M (`') CO 0M (`') (`') cM (`') V V -V N N N N (`) 0M (`) M (`) CO m (- M 7 V V It
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
Transmission Diversity
3,500
■Winter ■Summer
- Metric Meaning 3,000
<1,500 Competitive Marketplace 2,500
c 2,000
1,500-2,500 Moderately Concentrated
= 1,500
>2,500 Highly Concentrated 1,000
500
21 CO P- CO O O N CO V (0 n CO M O N M V
0 o a o 0 0 0 0 0 o a o 0 0 0 a 0 0 0 0
N N N N N N N N N N N N N N N N N N N N

Appendix A
Avoided Costs
Washington Idaho
Clean Clean
Flat On-Peak Off-Peak Capacity Capacity Flat On-Peak Off-Peak Capacity Capacity
Energy Energy Energy Premium Premium Energy Energy Energy Premium Premium
Year ($/MWh) ($/MWh) ($/MWh) ($/kW-Yr) ($/kW-Yr) Year ($/MWh) ($/MWh) ($/MWh) ($/kW-Yr) ($/kW-Yr)
2026 $41.98 $40.46 $43.12 $0.0 $0.0 2026 $41.61 $40.42 $42.50 $0.0 $0.0
2027 $38.14 $38.58 $37.82 $0.0 $0.0 2027 $37.88 $38.70 $37.26 $0.0 $0.0
2028 $35.40 $37.03 $34.18 $0.0 $0.0 2028 $35.13 $37.19 $33.57 $0.0 $0.0
2029 $35.04 $36.64 $33.84 $0.0 $0.0 2029 $34.57 $36.64 $33.01 $0.0 $0.0
2030 $39.18 $40.90 $37.89 $27.2 $82.4 2030 $38.56 $40.85 $36.84 $27.2 $0.0
2031 $44.10 $46.40 $42.38 $27.8 $84.1 2031 $43.00 $45.74 $40.96 $27.8 $0.0
2032 $44.33 $47.09 $42.27 $28.3 $85.8 2032 $42.74 $45.92 $40.36 $28.3 $0.0
2033 $45.40 $48.29 $43.23 $28.9 $87.5 2033 $43.82 $47.20 $41.29 $28.9 $0.0
2034 $45.55 $48.72 $43.17 $29.5 $59.8 2034 $43.92 $47.54 $41.19 $29.5 $0.0
2035 $46.71 $49.96 $44.27 $30.0 $61.0 2035 $44.93 $48.59 $42.18 $30.0 $0.0
2036 $46.40 $49.74 $43.90 $30.6 $62.2 2036 $44.50 $48.21 $41.72 $30.6 $0.0
2037 $47.66 $51.45 $44.82 $31.3 $63.4 2037 $45.69 $49.82 $42.61 $31.3 $0.0
2038 $47.77 $51.51 $44.98 $31.9 $64.7 2038 $45.66 $49.68 $42.64 $31.9 $0.0
2039 $48.48 $52.35 $45.58 $32.5 $66.0 2039 $46.29 $50.42 $43.19 $32.5 $0.0
2040 $49.59 $53.79 $46.43 $33.2 $67.3 2040 $47.28 $51.69 $43.96 $33.2 $0.0
2041 $50.01 $54.44 $46.68 $33.8 $68.6 2041 $47.66 $52.29 $44.19 $33.8 $0.0
2042 $52.31 $56.90 $48.88 $34.5 $70.0 2042 $49.92 $54.68 $46.35 $34.5 $0.0
2043 $52.97 $57.66 $49.45 $35.2 $71.4 2043 $50.52 $55.38 $46.88 $35.2 $0.0
2044 1 $53.841 $58.611 $50.271 $35.91 $72.8 2044 $51.24 $56.12 $47.581 $35.91 $0.0
2045 1 $55.071 $59.831 $51.481 $36.61 $74.3 2045 $52.391 $57.261 $48.711 $36.61 $0.0
20 r Levelizedl $44.13 1 $46.60 1 $42.27 1 $21.28 1 $49.93 20 yr Levelized $42.78 1 $45.62 1 $40.65 1 $21.28 $0.00
Capacity Credit is lower due to margin from wind projects, CT capacity payment is -$90/kW-yr
22

Appendix A
Portfolio Scenarios (includes changes)
g )
Methodology Load Scenarios Resource Availability
Alternative Lowest Reasonable Cost Low Growth Clean Resource Portfolio by 2045 17% PRM (replaces lower WRAP
[only used for 2026-2029] PRM scenario)
Baseline Least Cost Portfolio High Growth 500 MW Nuclear in 2030 30% PRM (replaces 0% LOLP
[excludes CETA] scenario)
Minimal Viable CETA Target RCP 8.5 Weather Power to Gas Unavailable Maximum Washington Customer
-AL Benefit
Maximum Viable CETA Target 80% Washington Building Nu p­;;F Gast Sens+t+v+ty PRS w/ CCA repealed
Electrification by 2045
PRS Constrained to the 2% Cost 80% Washington Building ug, nGG on De nand Response
Cap (replaces unconstrained cost Electrification by 2045 & High
cap) Transportation Electrification
Scenario M6
80% Washington Building Regional Transmission not Available
Electrification by 2045 & High
Transportation Electrification
Scenario with RCP 8.5 Weather
Extreme Building/Transportation Northeast Early Retirement 'Fr
Electrification for Washington & Idaho
w/o new Natural Gas CTs
Data Center in 2030 On-System Wind Limited to 200 MW
No IRA Tax Incentives
23 "Proposed Portfolio Changes in Red .

Appendix A
Avista 2025 Electric IRP
TAC Meeting No. 11
July 30, 2024, 8:30 am to 10:00 am (PTZ)
Participants:
Andres Alvarez, Creative Renewables Solutions; Soya Atitsogbe, UTC; John Barber,
Magneglide; Shawn Bonfield, Avista; Kim Boynton, Avista; Michael Brutocao, Avista;
Katie Chamberlain, Renewable NW; Josie Cummings, Avista; Kelly Dengel, Avista;
Joshua Dennis, UTC; Diedesch, Avista; Mike Dillon, Avista; Jean Marie Dreyer, Public
Counsel; Michael Eldred, IPUC; Rendall Farley, Avista; Grant Forsyth, Avista; Leona
Haley, Avista; Lori Hermanson, Avista; Mike Hermanson, Avista; Fred Heutte, NW
Energy Coalition; Annu John, Fortis BC; Bill Garry; Konstantine Geranios, UTC; Clint
Kalich, Avista; Alexandra Karpoff, PSE; Mary Kulas; Seungjae Lee, IPUC; Kimberly
Loskot, IPUC; John Lyons, Avista, Ian McGetrick, Idaho Power; Molly Morgan UTC;
Tomas Morrissey, NWPCC; Austin Oglesby, Avista; Kaitryn Olson, PSE; Michael Ott,
IPUC; Tom Pardee, Avista; Kit Parker, Avista; Meghan Pinch, Avista; John Rothlin,
Avista; Jared Schmautz, Avista; John Calvin Slagboom, WSU; Darrell Soyars, Avista;
Dean Spratt, Avista; Dillon Stambler, Creative Renewable Solutions; Lisa Stites, Grant
County PUD; Jason Talford, IPUC; Charlee Thompson, NW Energy Coalition; Bill Will,
WASEIA; Rachel Wilson, Form Energy; Yao Yin, IPUC.
Introductions, John Lyons
John Lyons: We will give it another minute here and then we'll get started. OK,
welcome again to the 11t" TAC meeting. We're up to 30 people now, so I think we're
ready to get moving to the first slide James. Today we've got a couple of different
things to go through on the Connected Communities program update and the
partnership with the Spokane Tribe that centers on resiliency that came up two TAC
meetings ago and we kind of bumbled our way through it without knowing what it is.
So, we brought the experts in so they can give you a short presentation about what's
going on with those projects. Then we are back on the Preferred Resource Strategy
results, and I think are we locked down now. James, maybe we're locked down on the
Preferred Resource Strategy. And then James is going to talk about the avoided cost.
We'll follow up in the end with the remaining TAC schedule and scenario planning.
John Lyons: Next slide. We are scheduled right now to have an August 13t" meeting
on our two-week schedule to go over the PRS portfolio analysis, LOLP study results,
some additional work on that, and the QF avoided cost. What we're proposing is we
cancel that August 13t" meeting and have another meeting on either September 10t"
or the 17t". Oh yeah, they're both 9:00 to 11:30, so it'll be another hour on those
meetings, so we can have a little more time to finish up modeling and time for people
to digest things. We'll give you some time to think about if you the 10t" or the 17t"works
for you on that. September 2nd, we will have the first release of the IRP draft and it'll

Appendix A
have those chapters in there. And then the next page in October we will have the
remaining chapters sent out. And then also in September, we have our virtual public
meeting that's more for the general public, so they can provide input, ask questions
about the TAC.
James Gall: John. That one is going to get moved out to November. OK.
John Lyons: We are going to move that to November. OK, cool. We'll update that on
the final slide was just asking if we had a date pinned down for that. So, virtual public
meeting which should be getting moved to November, October 1 st, will be the rest of
those chapters that we weren't quite able to get to by September 1 st. Any other things
you want to chat about, James?
James Gall: Yeah. Just one quick thing given that we only have an hour and a half
today and a lot of material. John did mention we'd like to cancel the August 13'
meeting, but if we don't get through all the material, we can have that meeting opened
up for finishing up anything we didn't get through today, or if there's any more dialogue
we want to have, we can leave that space open for that if we need to. Our goal really
is just to not create any new work. Right now, we're trying to draft up a majority of the
IRP over the next 4 '/2 weeks before we release the draft and then give us a little bit of
time to get all the scenarios completed and documented as well. We just needed a
little work with the schedule. This is I'd say an abbreviated IRP timeline. Normally we
have about two years to complete and we're doing it in less than a year and a half and
we're starting to feel that crunch now, so I appreciate patience and understanding. Any
questions before we move on? OK.
Connected Communities, Kit Parker
James Gall: Kit, are you a ready and able to share your slides?
Kit Parker: I am. I guess so. Let me see. Would you like me to share my slides then?
James Gall: I would love that, if you could share your slides.
Kit Parker: Kit Parker: OK, give me a second. I'll pull them up.
James Gall: I don't know if you've lost your feed or what happened. Might have lost
Kit. OK, so looks like we lost Kit. Oh, there she's back.
Kit Parker: I came back. I'm so sorry. Can you hear me now?

Appendix A
James Gall: OK, we can hear you. Yeah.
Kit Parker: OK, apologies for that. OK. And now I will share this screen that should
come through OK.
James Gall: We can see it.
Kit Parker: OK.
James Gall: Yeah, it's all yours.
Kit Parker: Thanks for your patience. My name is Kit Parker. I am the Renewables
and Storage Product Manager and I'm also the Program Manager for this program
called Connected Communities. I'm joined by Mike Diedesch. He's the Manager of the
Energy Innovation Lab, and he's also on this call. I'm going to talk through what our
Connected Communities program entails and our current state. What's our current
status? If you look at this slide, you'll see there are four logos on the bottom, and these
are all of the partners who are working together for this iteration of Connected
Communities.
Kit Parker: Connected Communities is a DOE grant and they awarded 10. There were
10 programs that were awarded through this first round of Connected Communities
funding, and Edo is the purple and green here. Edo is the prime recipient, so they
receive the funds from the DOE and then we are the subrecipients along with
Urbanova and then Pacific Northwest is also partnered in there as well. This is the
team that is putting together Connected Communities.
Kit Parker: The gist of our Connected Communities program is basically demand
flexibility. We're looking at if we give products, basically grid connected products that
are on the customer side of the meter, if we give these products to the customer. You
could think of the smart thermostat as the primary product that we're working with,
although there's an element of residential batteries that customers can be eligible for.
If we give these to the customer, or in the case of the battery, we provide a rebate that
helps them get these products, can we then have connected access to that asset with
the ability to adjust the set points specifically for the thermostat? Can we adjust those
set points during a grid event which we call a flex event and move those assets in a
way that does not affect customer comfort but also provides benefit to the grid. Our
range here for the smart thermostats is between one and four degrees. It's actually
mostly going to be around a 2-degree temperature setpoint change. An example that

Appendix A
you could think of would be if there's a heat dome and we have maybe 100 smart
thermostats out across a particular substation. What is the grid impact? If Avista is
able to then adjust the set point of those thermostats by 1 to 3 degrees during a heat
dome event, or some other grid event, what is the material impact to the grid and how
significant are those benefits?
Kit Parker: Taking a quick look, what you see here is this precooling concept and this
is the program Connected Communities is looking at both residential, small, medium
business and commercial C&I, and we've picked the Third and Hatch substation for a
couple of reasons. One is that it's approaching its capacity, so it's a fairly constrained
substation, but it also has a very diverse set of customers that are served by this Third
and Hatch substation. This particular substation and that diversity means there are
residential, and we've got lots of different types of customers who are residential
customers. We've got part of Rockwood which would be higher income, single family.
We've got the Logan and East Central neighborhoods, which are going to be lower
income and maybe more multifamily. So, a lot of residential diversity, but there's also
a lot of commercial diversity served by this particular substation as well. And if you
think of Sprague, the little strip of Sprague, down by the U District, there are lots of
small businesses served by the substation there. But there are also a lot of academic
buildings. The hospitals are on this feeder on this substation and commercial and
industrial, so bigger commercial plants or commercial customers as well. By doing this
demand flexibility program on the Third and Hatch substation, we're able to test how
lots of different customers respond.
Kit Parker: One of the things we're learning is what type of incentives, or how do you
need to compensate customers in order for them to be comfortable with relinquishing
some control over their thermostats or their batteries? And we always emphasize that
during an event, a customer always has the ability to go back to their thermostat and
set it back to whatever they would prefer. The goal is that they can't actually tell is that
it's their comfort is not affected, but if they don't want to participate in that event, they
always maintain the ability to opt out of the flex event. OK. I'll pause, are there any
questions? I don't know if Mike wants to add anything. OK. This is a five-year program,
and we are kind of in this early.
James Gall: You have a hand up, Sofya.
Kit Parker: Yeah. Oh, great.
Sofya Atitsogbe (UTC): Yeah, sure. Hackett, this is Sofya with Washington UTC.
Could you go back one slide?

Appendix A
Kit Parker: Yes.
Sofya Atitsogbe (UTC): OK. You mentioned that this is a joint project with a bunch of
companies. What is the plan for this substation? Does that mean it will defer the
upgrade of the substation? Or what is the goal of that project?
Kit Parker: I'll pause to see if Mike, if you want to take that, but I'm happy to jump in.
Michael Diedesch: Yeah, I would say that for this substation, this is a demonstration
of how we could achieve that deferral using these different methods. So rather than
just looking at grid side assets, this is our way of demonstrating how customer side
assets could participate in that sort of thing. It's unique among the Connected
Communities projects where Avista is, I believe, the only one who's got a locational
based demand flexibility program and that is the main reason why we are doing it.
Location based is for that concept of customer participation in reducing our distribution
constraints, which can defer capital projects.
Sofya Atitsogbe (UTC): Thank you. Do you have an approximation of either the cost
you're planning to defer or the constraint you're planning to relieve with that project.
Michael Diedesch: And not off the top of my head though, but I could.
research that and get back to you.
Sofya Atitsogbe (UTC): Sure. Thank you.
Michael Diedesch: Yep.
Kit Parker: Anything else before I move on? Awesome. Thanks for the question. OK,
so this is a five-year program and we're kind of between the pilot assessment and the
testing phase. The first year of the program was basically studying this particular
feeder, looking at the customer data in terms of usage and capacity, looking at the
different products that were available and based on the particular constraints of this
feeder and the customer behaviors, which product packages do we think would have
the most material impact. And then, testing. The first year was a lot of modeling to
figure out how we wanted to structure the program. Now we're into this pilot
assessment phase, which has a big enrollment component. This is where we're going
out and we are beginning to engage to recruit customers. We're going to have
residential, small and medium business, and C&I — commercial and industrial
customers. We have just launched recruitment trying to get folks enrolled into this

Appendix A
program. Behind the scenes, they're also working on getting all of the technology in
place so that we will actually be able to dispatch assets during particular events.
Kit Parker: The next phase will be the testing phase, where we'll pilot basically with a
handful of customers, do the end-to-end testing, making sure that the system works,
making sure that everything is responding the way that we would expect. And then this
4t" year is full program deployment where we are analyzing and evaluating how the
program works. What is working well? What is not working? Making any modifications
that we need for this particular program to be as successful as possible. This final year
is where we will summarize, basically do a report and summarize all of our learnings
and make a recommendation for how the program might be scaled in the future. Any
questions on this? OK. John, James, this is my last slide. I'll turn it back over to you.
James Gall: Thank you, Kit. And if there are any questions that come up later,
hopefully you can hang out for a little bit. But, in the meantime, we'll move over to
Megan.
Kit Parker: Thank you. Sure.
Spokane Tribe Energy Resiliency Partnership Update, Meghan Pinch
James Gall: Megan's can share her screen as well. She's shaking her head. She's
next to me in the room, so it makes it a lot easier to communicate. Alright, go ahead
Meghan, whenever you're ready.
Meghan Pinch: Hi everybody I'm here to give an update on the partnership between
Avista and the Spokane Tribe on an energy resiliency project we've been working on.
Back in the Fall of 2022, Avista entered into a contract with the Washington State
Department of Commerce to receive some funding to design a grid resiliency solution
for the Spokane Tribe. At that time, we also entered into an MOU with the Spokane
Tribe to jointly create this project. The reason that Avista got engaged with because
the tribe had a big fire in 2016. A wildfire that caused a lot of damage beyond maybe
what it would have because they had a lot of their pump equipment, and their
firefighting equipment was disabled. They didn't have power to adequately fight the
fire, so they lost a lot more structures and a lot more timber than they would have, and
that was the beginning of their Children of the Sun Solar Initiative and also their desire
to have more resiliency during wildfire events. So, that wildfire outage scenario has
really been the governing principle. The idea has been that the request from the Tribe
was to design a resiliency solution that could power their critical loads.
There have been some buildings identified that count as critical loads for up to seven
days during a wildfire outage.

Appendix A
Meghan Pinch: A caveat is that seven days includes existing generation resources.
There is a diesel generator that is a part of the administrative buildings, backup
infrastructure, a propane generator and some solar generation assets already on site.
The concept that we've come up with over the last two years of working closely with
the Tribe through reviewing some of their planning documents and a series of design
workshops with tribal leaders and public safety leaders is this concept here, I'm not an
engineer, but I'm learning how to read these diagrams based on this project and I also
want to say the Innovation Lab, Mike's team who you just heard from, has been really
involved in designing this concept and modeling the scenarios we've been talking
about. Anyhow, the concept is the switchable platform that could enable power during
emergencies to be shifted to critical loads and we see it in the diagram. It's demarcated
as circuit 3.
Meghan Pinch: The concept is that three buildings that have been designated as
critical loads: the Tribal Administrative Building, the Wynecoop Memorial Health Clinic,
and the Public Safety Building would be the three buildings that would be prioritized
on this circuit during emergencies. The other important piece of the design concept is
that this concept which we're calling the resiliency station, would replace a set of
existing stepdown circuits that are currently routed through elevated building
transformers. They're in a place right now that the Tribe would like to redevelop, so
we think it's an elegant solution and that solves that problem and also gives a lot more
reliable infrastructure. So, what you see here also is that the critical load cycle will
have a battery that will back up and then it will also have some expandability so that if
the Tribe wanted to, at some point, bring in bigger scale of generation or even add EV
charging or any other sort of grid infrastructure. This would be a platform, an
expandable platform, that would allow them to do that. The innovation lab has done
quite a bit of modeling, and the idea is that we would prioritize the battery ahead of the
diesel generator so that the carbon footprint would be lower. We're confident that this
design for summertime loads of those three buildings will enable us to hit that seven-
day outage duration goal in most scenarios.
Meghan Pinch: It's pretty exciting. We're really excited about the concept. Also, if you
prefer pictures of what this could look like, this is a very rudimentary concept of what
the equipment layout could be. This is the site also and it's in Wellpinit right behind the
Wellpinit Trading Post. There would be a fence enclosure, probably a concrete
masonry wall. And there would be a controls enclosure. The idea is that at some point
we could also make that an interpretive or teaching center, because we anticipate this
concept will have a lot of buzz and a lot of people will want to come visit and learn
about it. There's also going to be some training needs in terms of training workforce to
operate the microgrid. There would be battery storage and then the pad mount

Appendix A
equipment would also be behind the enclosure and that would be how we would
replace the current distribution infrastructure.
Meghan Pinch: I'm going to pause for any questions about the concept. OK. Well, still
open to questions if they should come up in terms of recent activities and next steps.
We matured the design enough over the last six months that we thought confident to
go ahead and apply for construction funding. Avista works closely to provide technical
assistance to the Tribe, who recently submitted an application a couple weeks ago to
the Department of Commerce's Tribal Clean Energy Grant Fund and the maximum
award amount, there is $2.7 million. We went ahead and supported an application for
that total amount, and it is a really critical piece of the overall estimated cost. At this
point, we anticipate the project costs are going to be around $6.5 million. The addition
to the $2.75 million from the Department of Commerce, if that is awarded, which we
should hear about in the next couple months, the gap between those two numbers will
be provided by a mix of Avista provided funding through the Named Community
Investment Fund and the Spokane Tribe has been awarded a Department of Energy
Grid Resiliency Grant. We're still working through the details of which pieces would
come from which funding source, but we feel confident that we can hit that $6.65
million in funds. The caveat here is that number doesn't include some additional scope
items that would really make the project above and beyond. For example, maybe
public EV charging or that interpretive center idea that I discussed. At this point, those
two components are not in the total project costs. We are currently looking for
additional funding to support those additional scope items and that is the update.
James Gall: Any questions for Meghan? Appreciate Meghan and Kit joining us today.
We do get questions that we're not experts on and we appreciate the ability to bring
folks in to help with those questions as they come in. Thank you again, and we're going
to transition to our normal scheduled program of talking about the IRP and just bear
with me one second while I switch screens.
Kit Parker: Thanks for having us.
Draft Preferred Resource Strategy, James Gall
James Gall: Hopefully everybody sees the Preferred Resource Strategy, which I do,
and we have about an hour, and I think that will be enough time to get through this
slide deck where we won't need next week, but feel free to ask questions as we go
along either in chat or raise your hand. Lori is going to be watching out for any
messages. And like John mentioned, we are trying to lock down a Preferred Resource
Strategy. We are planning on sending out a draft document at the end of next month
and we think we've nailed it down there. There are plausible changes that could

Appendix A
happen in the next several months that would require us to change this, but based on
the information we have now, we think we're going to stick with what we have shared
today, unless there's some excellent comments that would have us revise our strategy.
James Gall: To start off I just have this slide as a reference. This is our strategy that
we showed at the last TAC meeting and there's been one major change since then
and that has to do with the transmission line that you see halfway down that 50
megawatts that show up between 2037 and 2045 that had to do with the agreed United
Transmission line from Colstrip to the North Dakota area and the big change where
we're proposing that you're going to see in the next slide has to do with how that project
would come to fruition. We can't necessarily just grab any size of that project that we
want at any time. It's kind of a one and done type of deal and so our proposed strategy
is to move that resource as a selected resource in 2033 and you're going to see that,
this new layout of the resource strategy.
James Gall: This is just showing 2026 through 2035, and you see regional
transmission; 198 megawatts for Washington and 101.6 megawatts for Idaho.
That assumes that resource is in place by 2033. The reason for that change has to do
with a couple things. Like I mentioned earlier, it's you can't acquire it at any time and
the second reason is when we're looking at that resource from a modeling perspective,
we're really first testing whether or not it's makes sense from a conceptual point of
view of helping out with capacity needs. And then we did not look at resiliency but
arbitrage of our markets between MISO, SPP and the Pacific Northwest. And so that
value stream was not in the analysis and when we started looking at placing arbitrage
values in the analysis, that resource became more and more economic. I think it
provides pretty good justification of putting that resource in all of the scenarios that we
studied. There is an effort underway internally to look at that arbitrage value that will
be probably provided at a later time, maybe even outside the IRP process. But at this
time, we're not committing to the project. We're just looking at it from an IRP
perspective. This looks to be attractive, and we want to ensure that if we do pursue
that project, we know what the impacts are to the rest of the portfolio.
James Gall: That change then had a cascading effect on other resources that were
picked in the strategy. This strategy we're showing today has those cascading
changes. Before I continue, are there any questions? No questions in the chat? And
then I'm going to have a I think a slide detailing what that transmission line looks like,
a little more. OK, this resource strategy includes around 78,000 MW hours of energy
efficiency in the first two years for the biennial target. That's an increase from the last
IRP. I think we're getting close to finalizing that number now. That's going to probably
go to the Energy Efficiency Advisory Group. There'll be more discussion on that

Appendix A
assumption and result in that process, but this is a preliminary look at that target for
generation resources. The first need is really to begin some type of community solar
projects beginning in 2027. You see those flow out through the whole time period for
Washington State and that is a placeholder resource for what could come out of the
Named Community Investment Fund, similar to the projects that Meghan and Kit
already talked about. There could be projects that fit in that category we don't know
about. We want to make sure we account for generation that could be in the portfolio
in the future, so that we don't necessarily overbuild something else or at least in the
academic modeling of the IRP.
James Gall: The first major resource in the IRP is a 200 MW wind facility in 2029.
That's similar to what we saw in the last version of this a couple weeks ago. I even
went back and looked at the 2023 IRP and it seems to be there's a common theme
that we'll need wind, even in that IRP wind was setting within 2030, we had 200
megawatts, but there is definitely a string of wind beginning in 2029 all the way through
2033 when the tax credits expire. We are seeing wind selected in both states, both
Washington and Idaho, largely due to the expected low cost of wind energy which I
think we have a slide on that, on the risk of this assumption in the IRP. But I'll get into
other resource selections in the first 10 years. I'd like to go over the Idaho category, a
natural gas turbine, which would be something that's like Rathdrum Unit 3, shows up
in 2030. Again, we are splitting up our resource strategy between states. They have
different planning requirements. They also have different energy and capacity needs,
but the one challenge we have, at least for right now, is all of our resources are not
assigned to each state.
James Gall: The IRP is a little bit of an academic exercise where it shows needs of
each state. But when resources are acquired and accounted for, they are split between
the two states on a, we call it a PT ratio basis, which is based upon load. Right now,
Washington is a little bit under 65% of our load and Idaho is the remaining. Those
costs are typically split out between those two amounts as time goes on, though what
we've seen at least in this IRP is the loads are growing faster in Washington due to
electrification of transportation and buildings. And that PT ratio, or amount of ratio that
gets allocated between cost change, and so that would mean that Washington would
have a higher percentage of the existing resources in the future. Also in this IRP we
assume locational demand like demand response is allocated by state. PURPA
resources as well and Idaho actually has a little bit greater deficit in the early years
than Washington due to that assumption. Moving on to other items, I've noticed in this
first ten years is we do have a significant amount of DR programs beginning over the
next 10 years, it's around 12 megawatts by the end of the decade of selection in
Washington, a little over 1 MW and Idaho and those are through beginning of programs

Appendix A
that are expected to increase over time. I have a slide a little bit later on those
programs and when they would likely begin. Before I move on, are there any
questions? Rachel's got her hand up. Go ahead, Rachel.
Rachel Wilson: Thanks James. This is Rachel Wilson from Form Energy. I'm a little
surprised about the lack of storage in this first 10-year planning period. It seems a little
counter to some of the trends in resource planning and a little bit of a surprising result.
I'm wondering if you might speak to that a little bit.
James Gall: I'm happy to. I've been looking at quite a bit on this strategy. Why is there
no storage and there are a couple of reasons why. The first reason I would say is slow
load growth, it is the big one where the wind and the demand response is able to
capture most of the capacity increases along with the natural gas resource for Idaho.
I ran a scenario where we had needs earlier. Let's say if there was a need of 50
megawatts continually beginning in 2026, we would see energy storage selected. So,
it's a really a matter of timing of when you're in resource need versus how much time
you have to develop something else. And in our case, developing a third unit at
Rathdrum appears to be a much lower cost than building a battery. Now, at the end of
the day, the academic exercise of the IRP is kind of a moot point because what will
happen in reality is, the IRP identifies resource needs, we will issue an RFP to meet
those capacity needs and all resources will have an opportunity to bid in. And if solar
plus a battery, or just a standalone battery, or a natural gas turbine is the lowest cost
given the resource needs, then we'll be able to figure out what is truly the lowest cost.
Unfortunately, IRPs don't factor in real resources. That's why I keep bringing up how
it's kind of an academic exercise, but we'll see what the market brings. I would
anticipate we'll have an RFP out in probably Q1 of 2025 in order to be able to act on
these resource needs by the end of the decade. Hopefully that answers Rachel's
question.
Rachel Wilson: Awesome. Thank you.
James Gall: Alright. Any other questions before we go the next decade, which is the
little bit more interesting? OK, nothing yet. Alright, let's get to the last decade, where I
would say a lot of things happen at least on the Washington side of the service territory.
We'll start with Idaho because it's a little simpler, but what we're seeing is natural gas
turbines remain to be the lowest cost option to serve peak loads for the Idaho side of
the service territory. Small load growth and offsetting generation that is retired.
Basically you're retiring a natural gas resource and replacing it with another natural
gas resource is really what the model is showing and in reality that may happen, I
guess we'll wait and see, but at least the gas prices and the cost of technology that

Appendix A
seems to be the lowest cost strategy, there is a little bit of demand response selected
for Idaho up to about 10 megawatts in that period of time along with a little bit of energy
efficiency around 30 average megawatts.
James Gall: And then in the last year, 2045, that portion of a biomass plan is actually
upgrading our Kettle Falls unit. At some point, that plant will need to have a major
overhaul and that might be a good opportunity to upgrade that facility at that time. On
the Washington side, which is definitely more interesting, as far as the quantity and
needs of resources, you have a few things going on in Washington on that. You start
to see rapid load growth from electrification. You have replacing of natural gas
resources that are going to have to be retired or removed from the portfolio by 2045.
So, you have a massive amount of resource need and then it's just a question of what
technologies can meet that need. We do forecast solar, small solar for the Community
Fund like we talked about earlier, but in 2043 through 2045, we would likely see larger
amounts of projects being online. We do see wind replacements of our current PPAs
that it will be expiring at the end of the decade. That's what the wind resources in 2041
and 2043 represent. And then additional wind beyond that period.
James Gall: We start seeing storage show up at the end of the decade. Those include
likely long duration energy storage, which is what will be needed in that period of time.
Also, related to storage, we have power-to-gas section starting in 2040. Power-to-gas
is really two categories of resources. One is cofiring hydrogen at our Coyote Springs
2 facility, and that is there in 2045, and then a new facility that would use a clean
hydrogen that's converted to ammonia as a storage mechanism and burn in a CT that
is around 300 megawatts between 2040 and 2042. We do see nuclear continue to
stay in the plan in 2045 as a base load renewable resource or I should say clean
resource. Also, geothermal and a second unit of Kettle Falls was selected in 2045.
Those totals at the end of the planning horizon should be enough to keep our system
reliable and meet the 2045 targets. Cost will be a concern and we're going to have a
discussion on that in a little bit of what we've figured out on cost. But it's kind of an
interesting resource strategy just because of how our loads are growing and the CETA
needs. I would say the model is basically back ending a lot of resources because of
how our portfolio is designed, where resources are not likely to retire that are using
natural gas until late in the study. So, when you're replacing capacity, we're able to
chip away at it with other resources besides large new technology projects like power-
to-gas or nuclear. Time will tell on load growth whether or not that changes. You have
a question, Molly? Molly, go ahead.
Molly Morgan (UTC): Yeah. What resource or combination of resources ends up
replacing peaker plants?

Appendix A
James Gall: I'd say that power-to-gas is really a peaker plant. Those are modeled
after a natural gas CT, but instead of using natural gas, they're using ammonia.
Molly Morgan (UTC): OK.
James Gall: So that's around 400 megawatts of those resources or 300 megawatts
of that peak of resource.
Molly Morgan (UTC): OK.
James Gall: Another 94 MW is the cofiring of hydrogen in Coyote, which will probably
in that period of time look more like a peaker than a base load facility.
Molly Morgan (UTC): OK. Thank you. Thank goodness. Yeah.
James Gall: Yep. Alright. Any other questions? Not yet. I'd miss demand response
and energy efficiency in the outer years. We do see around 52 megawatts of demand
response by the end of that decade. And like I said, we'll go through some of those
programs a little bit, but also energy efficiency continues to increase over this period
of time. OK.
James Gall: Really quick on the North Plains Connector Project, this is a reference of
the discussion I had earlier where we're assuming the 300 MW portion of this line. I
believe it's around 3,000 megawatts total, so Avista would have about a 10% share of
it. It's a line that goes from Colstrip to North Dakota, connecting into MISO and SPP.
When we get into scenario analysis, unless we're doing a scenario that's without this
line, we are assuming this line is in all scenarios as a fixed resource. We're not letting
the model pick this resource. It's going to be either in or out depending upon the
scenario. The reason for that is it's we just don't have all of the information yet as far
as the arbitrage value to include in the analysis along with the avoided capacity cost.
But when we started looking at arbitrage of values, it didn't take a lot of arbitrage value
to be added to the capacity value that it could bring to our system to be cost effective
for both states. So, it seemed like a resource that would be a good fit to lock in. As we
study what the impacts are for the other resources. Going back to when and actually
when is probably I'd say the biggest risk item in the next 10 years besides load growth.
And this is because the model is selecting a tremendous amount between 2029 and
2033.

Appendix A
James Gall: I've talked to some other utilities that are seeing some similar results
where we do a price forecast of the wholesale market. That has definitely risen in the
last couple of years, and we see at least theoretical low PPA pricing due to the IRA
tax credits. And when you look at a high market price and a low PPA, it models this is
a big winner. We should go out and build as much of this stuff as possible and then
reality will have to hit at some point where one the biggest risks I'm seeing in that 850
megawatts of wind is, can it all be built on the transmission system that we have in this
IRP? Assume we could build around 500 megawatts of wind in our service territory
without new transmission, and then another 200 MW, I believe in Montana. And then
I believe it was 200 MW off our system. But as all utilities in the Northwest needing
renewables to meet requirements in Washington and Oregon, some of those projects
will likely not be available to Avista. If any projects within our service territory get
exported off of our system, that will likely reduce the amount of wind that would be
selected in the 2029 to 2033 period.
James Gall: We're going to look at a scenario where we do limit the amount of wind
to see what that does in the portfolio. My expectation is that it will likely defer that
resource to later in the study when it's needed. So, we have this interesting
phenomenon where you have a low-cost resource you can acquire early versus when
you need it from a physical point of view. And for those of you who have been following
our IRPs for some time, we are definitely in a renewable resource length position
compared to CCA targets versus some of our peers. Wind is not necessarily a
resource need for meeting those targets. It is helpful but the result of the modeling
shows if you don't need something and it's not cost effective, you'll want to delay that
purchase as long as possible. But given the model is seeing it as cost effective, it
wants to acquire as much as possible, but if you run out of that supply, it's going to
defer that as long as possible because we would need to likely build new transmission
to import, to be able to bring that wind to the service territory. And that will have an
increased cost to our system and our customers. The third area that is a concern for
wind and this modeling exercise and it's really not necessarily I don't think could impact
the amount of wind, but it could impact the other resources we would need and
possibly lead to some different resource decision making.
James Gall: That is the way Montana wind QCC, especially in the winter. The
modeling that we are doing this time around utilizes some of the wrap QCC values for
Montana wind which are I would say relatively high compared to the northwest and
what that does in the modeling grand scheme of things is that adds capacity to our
system that we would be relying on and what we saw in the January cold weather
event is that Montana wind was not available due to 2022 extremely cold weather and
I guess it's a question of whether or not the QCC values we're assuming from Montana

Appendix A
when is it appropriate or not and if it's deemed to be too high over the next couple of
years you would likely see additional need for capacity. In that case, you might see
energy storage start to pop up as an economic alternative. That's something we're
going to need to continue to monitor whether or not we can actually rely on Montana
wind for capacity, especially in the winter time. We definitely would still see it likely
economic from an energy perspective, similar to the northwest wind, but the capacity
benefits are at a little bit of a risk.
James Gall: The last bullet is something we touched on a little bit in the last TAC
meeting and that has to do with why not more wind. For Idaho, when it's economic and
the cost in the marketplace and that has to really do with constraints of the system and
trying to prioritize meeting the constraint of CETA. Let's say you have one state that
has a CETA target. The other state doesn't. The benefit is equal to both, but one state
has a requirement, the other state doesn't. What the model wants to do is allocate the
few resources that it can to one state to make sure it meets that goal. Again, who
knows, or at least right now all costs are shared between the two states on a PT ratio.
But if you have a limited supply of a resource, the model is trying to optimize every
dollar it can. It's saying that we should allocate to Washington because it has a CETA
requirement versus Idaho does not. That's a reason why we're not seeing more wind
in Idaho. OK. Any questions or thoughts that I may have brought up that you want to
chat about. Questions and chat right now. OK.
James Gall: Now there are some other losses, accounted for losses, so I'm assuming
you're speaking of losses from the Montana side of things. We do a reduction in energy
delivery for losses the model optimizes for meeting the energy targets and capacity
targets, so we account for those as basically a deduction in generation, but you still
have to pay for the energy. If you pay for the energy, but it's not all delivered when
you're trying to match up generation against load. OK. Nothing else. Anything else?
James Gall: OK, let's keep going. I was talking about demand response. Like I
mentioned, we have a quite a bit of a demand response program selected in the
Preferred Resource Strategy and some of them begin immediately, but they don't
necessarily result in a large amount of megawatts immediately. And some programs
show up a little bit later than I think a lot of people were hoping to see last TAC meeting,
but there are reasons for that. It has to do with what our load forecast looks like. The
first one that was selected was really three programs in the first year, electric vehicle
time of use rates, which is a commercial pilot really that's kind of already underway,
but the. Our total load expectation or savings from around 9 megawatts is what our
study showed from our consultant that looked at our the total available. Cool.

Appendix A
James Gall: Demand response savings at peak hours. They did a potential study that
looks at a variety of different programs and tries to allocate how much could we depend
on over the 20 years of the IRP for that load savings where you have some programs,
or I should say end uses, that could be really placed into multiple different categories.
And so, they're trying their best efforts to trying to figure out what that savings would
look like depending on which program you select. The values you see here are
showing the highest value of either summer or winter over the 20-year period where
these programs really start at a lower amount then grow over time.
James Gall: The second one is battery energy storage. This program is really an
aggregation of customer batteries, similar to the Connected Community idea that Kit
talked about earlier, but we would be starting now. Our program here, where we would
as customers add batteries to their homes, we would try to initiate an agreement with
them to dispatch them during grid events. There are definitely not 10 megawatts of
batteries on our system right now, but there could be over the life of the IRP based
upon our distribution, energy resource locational study that we had done earlier this
year.
James Gall: The third program is variable peak pricing. It seemed to be a very cost-
effective program, easy to implement, that saved around 5 megawatts. So those first
three programs are cost effective, at least in the first three years. Those programs
were also cost effective in Idaho. There's a little bit of a delay on two of them really
having to do with needing AMI metering in Idaho to do some of these programs and
AMI was not expected, at least assumed in the model until 2029. You start to see
those programs show up as cost effective, peak time rebate shows up in 2035. That
is a pilot project we're working on this year. That program pilot will, I think, continue for
a couple years and maybe based upon the (earnings of that pilot, we may see that.
And if we have more load growth, we could see that program being selected earlier to
continue on, we'll have to wait and see how that pilot proceeds.
James Gall: We have behavioral programs and time of use rates in 2038. Time of use
rates is another one of those programs that we are piloting, and this one was a little
bit interesting because in our last IRP, this one showed up with a much larger savings
and showed up earlier. What we're finding is the cost to develop that program is
definitely higher in this last potential study and the savings potential was much lower
and that's why it's being pushed out, but still cost effective in that later period of time
when you have significant loads to meet. Third party contracts, that's an aggregator
concept and that shows up in 2039. I'm hopeful that when we go out for bid for capacity
resources, we would have some aggregators bid in for this potential and maybe have,
hopefully show higher potential, maybe even lower cost. This one is probably

Appendix A
something that's going to need to be bid into an RFP process. If not, we'll have to look
at building a program when it appears to be cost effective. We do see CTA water
heaters start to show up in the end of the cycle and along with controllable air
conditioning units. And what's interesting with the CTA water heaters, there's been a
lot of talk with those because it's maybe an easier to implement program. Because of
the similar technologies already on the water heater, but there's still a significant cost
to the utility to be able to connect those water heaters. Also depending upon if it's a
heat pump water heater or a non-heat pump water heater, the savings definitely is
much lower on the heat pump water heater. It's potentially a lot of cost for very little
savings at least on the heat pump water heater, much why it wasn't selected. But the
traditional water heater style was selected, but the amount of those available on the
system, I guess the wait and see based on energy codes if that quantity can really be
available. So that total, up to around 61 megawatts for Washington, 12 MW in Idaho
between the two were a little over 70 megawatts. Our peak load is around, let's say
1,850 today, around 4% of our peak load that was cost effective from a demand
response program point of view. But for Washington, 61 MW out of maybe 1,200 MW,
it's a definitely a much bigger share maybe around over 5% of peak load. That's on
top of the 25 to 30 megawatts we already have on our system today. Any questions
on demand response? OK, let's keep going.
James Gall: Moving on to energy efficiency, this is a similar slide we show last time
on how much was selected. Actually, I just saw a chat. Yeah, they said this thread DR
programs looks good, but the start dates are perplexing, especially the CTA water
heater. Thank you, Fred, and again it it's really just driven by low needs. If we had a
high load scenario where we had a capacity need immediately, you would start to see
these move up. I doubt you would see CTA move up just because of the cost to
implement it for very little savings. You got to have the water heaters, and the customer
base to justify the expense of that one. But you will see, like I said, in high load cases
a lot of these programs move up faster. We can just say that I have the load to justify
it, that could happen. I mean we do an IRP every two years. Last IRP we had one
program selected. This IRP, we have how many of them here? Eight of them. We
continue to revise as we go along, and we see whether or not loads prove out to be
there or not.
Fred Heutte: Yeah, I do have a question because I just had a comment before and
the question is on the CTA, the plug connected water heater program. Is that cost
basically driven by material cost or by customer incentives.
James Gall: I don't know. Yeah, check to see if Leona is on the call.

Appendix A
Leona Haley: Yeah, James.
James Gall: Go ahead.
Leona Haley: Yeah. Thanks James and Fred. Leona Haley. I work in the energy
efficiency demand response group under Meghan Pinch, and we are looking at CTA
2045 grid enabled water heaters. Right now, we are part of NEEA's end use load
flexibility project and currently the cost that have been modeled in the IRP are a result
from that Bonneville - Portland General study and others from 2018. As we move into
this pilot project with NEEA, those costs can be revised with NEEA's market
transformation prowess I guess is the right word, expertise. Those costs may be driven
down and we may see some efficiencies there, which will in turn influence the value
here in this IRP modeling process.
Fred Heutte: 59:09 Yeah. Thanks for that. I'm very familiar with that. No, 2018, 1 guess
you know field test whatever going to call it actually worked pretty closely with NEEA,
Bonneville, PGE, you know that were the kind of the main drivers of that that test really
showed the very wide-ranging capabilities of this. Approach with the water heaters
and you know now both Oregon and Washington have requirements for all the new
electric water heaters to have the CTA plug. So you know it's out there and we felt for
quite a long time because basically, you know the program can be run in such a way
that customers really don't feel any impact. You know they can always override as
you've mentioned for other programs. So just. Yeah, I'm. I'm going to be following up
with NEEA about that. We see a lot of potential for this and also for it to be a more of
a regional approach, not just utility by utility. Appreciate that it's at least in the list, but
I'm hopeful that it will move up in the activation dates.
James Gall: Yeah. Fred. I'm going to kind of reach a little bit on September,
suggestions here on the ones that are picked. But you know, I think the region
definitely has capacity needs and I guess it's maybe a societal question is should our
customers do DR early at our expense for the benefit of the region? It really is where
I'd say the argument is going is because the region needs capacity benefits. We have
customers that may or may not be able to fluctuate their load for that, but should we
be doing programs early for the benefit of the region versus our customer need? That's
another answerable question by me, but I guess if we did programs earlier, that would
be the situation we'd be in.
Fred Heutte: Yeah. I would agree with that and also point out that there are lots of
opportunities in the new organized markets to monetize that because if we're really

Appendix A
hot over here in Portland and you've got some flexibility in your area, can we find a
way to make that happen? And just to mention a couple things, the PG&E has been
talking, I don't know the details in this, has been talking to the California ISO about
some fine tuning to the EIM so that their demand response program in effect can bid
into the EIM. And then, of course, the day ahead markets. Whichever one, or both,
emerge in the Northwest will offer another opportunity for that. The issue here is the
markets give us an ability to tap into the load and resource diversity. Well, that includes
load flexibility across the region across the big footprint. Our hope is that the
economics of demand response kind of peak oriented activity could benefit a lot from
that and don't have an exact analysis of that yet, but hope that everybody keeps that
in mind is that the market availability of an organized market whether it's real time or
day ahead gives a lot more opportunity than to you to get more value out of the
demand response.
James Gall: Yeah, I think we're going to need, in addition to that, some type of
capacity payment to really drive early acquisition for the grid. It's regional support that
would be I think the key thing missing from that, but you have a comment from Jason.
Fred Heutte: Alright, thanks.
James Gall: So alright, what Jason? He said he's interested in what the value streams
are being used to inform the benefits of DR programs. Yeah, sure. Actually, this is
something we've actually, I'd say improved on last IRP. There are several benefits.
The first benefit is obviously just the capacity reduction to avoid building another
resource. So that's the capacity benefit I was mentioning to Fred where we did this as
a region. We're not saving anything for our customers or saving it for other utilities and
we're not getting compensated. So, in the effort of what's selected here, there's a
benefit to our customers of avoiding generation. The second value stream is also
related to what Fred mentioned, which is the energy value that you save from the
energy market. When prices are typically high during a demand response event, you
are saving spending that money for either buying a resource or able to sell something
else, so you're getting an economic energy value. Another benefit we included here is
savings on the T&D system. That is, if we implement these programs overall, the
concept is that we would have less T&D construction on our system and similar to a
T&D benefit, peanut butter across the system for energy efficiency. The other new
benefit we included on the suggestion of Idaho Commission staff was that we include
this as a load reduction rather than just a resource option. So, what that does is you
get a benefit of reducing your planning reserve margin. Instead of just saying, OK, 60
megawatts of savings from a societal point of view, we're actually saving planning
margin on top of that. That's another benefit we included here. The values do get

Appendix A
multiplied by what's called a QCC value, which is what it's capable of producing over
a long period of time. And that is still I'd say, an open-ended question of how much
you can rely on demand response in a prolonged winter event when these programs
are typically shedding load for three to four hours. And similar to a battery, in fact at
least a lithium-ion battery, this something that should have a reduction in QCC value
over time or is it fairly stable? We made a very conservative assumption, I guess,
depending on your point of view of keeping the QCC value relatively high over the
period of the 20 years. So, I'd say DR has a little bit of an edge over other resources
in this IRP versus other options. Time will tell whether or not that proves out to be a
good assumption or not, but we're trying to definitely encourage the model to pick DR
in an economic going to be where we have information.
Tom Pardee: Joshua from the UTC says has Avista done studies to see the benefits
of implementation of DER earlier in terms of customers getting used to DER
participation? Like in my mind if the customers get used to participation earlier that
opens up to many emerging opportunities that may seem more invasive, Avista
controlled EV charging for load shifting, for example, in the future.
James Gall: Yeah, maybe two thoughts on that. One, I'm going to lean on Leona,
maybe to answer, but we do have an electric vehicle time use rate for commercial
vehicles. And if Rendall is on he could probably speak to that, it's been very successful
on encouraging those commercial customers to charge at different times. But I was
hoping Leona, maybe could talk about the pilot project we did in Pullman on whether
or not customers like or do not like these programs. But I see Joshua has the hand
up, but if you want to add Joshua before we go to Leona.
Joshua Dennis (UTC): I wanted to say that the example, just like off the top of my
head, but more importantly I think my question is more of a behavioral one.
think that if and like I said, in my mind, if we could, if Avista could get people to
participate in DRs sooner and have more experience with it, there might be
opportunities in the future for Avista to expand. They're DR program selection with like
emerging technologies that might be more invasive, and people might be hesitant to
participate in those.
James Gall: Yep. So, what I guess I'm hearing is the more you make it available now,
the less resistance you'll see in the future. Is that where you were going there?
Joshua Dennis (UTC): Yeah.

Appendix A
Leona Haley: Yeah. The only thing I'd like to add to Joshua's point and the smart grid
demonstration project, it was one of several pilots we've had over the years.
But in that particular one, we did have more of an automated demand response, if you
will, where the customer was not notified of events, they were more automatic, they
could override them at any time simply by getting onto their thermostat app or right out
the thermostat itself inside the home or business. And we noticed that there weren't
many event opt outs and the attrition was normal attrition that you'd see in these types
of programs. To your point, that's all I had. Thanks.
James Gall: Yep. Alright, Rendall any thoughts on EVs and Joshua's comments?
Rendall Farley: Have a few. To your comment on the commercial electric vehicle time
of use rate, we implemented that in 2021 and it has been very successful, but it's been
limited just because the market for medium and heavy-duty electric transportation has
been light so far. But we expect that to increase in the future as well as light duty fleets
and larger workplace charging hubs and so forth. We think that time of use rate will be
very effective from early results we've seen so far. One other thing I did want to
mention too was something we've been working on or looking to launch once we have
funding secured for it, is a smart charging program for residential customers. Our early
pilot results show that we've shifted only about 5% of total load with the customers that
are participating is on peak. That's a substantial shift from uninfluenced charging
loads. Most people uninfluenced without a time use rate will tend to come home from
their errands or work and just plug in the car in the late afternoon or early evening.
And that tends to be on peak year-round. So that looks like it's got good potential to
scale. It's not listed here in this table because it's a little too early to hang our hat on
it, but it's pretty promising. So I did want to mention that too.
James Gall: Thanks, Rendall.
Rendall Farley: Yeah.
James Gall: Alright, back to energy efficiency. These are a list of the top programs
selected. I actually have a new chart that's probably going to be coming out in the next
draft of the IRP that summarizes a little bit better, but this will get you an idea of what
savings are picked by state. As you see in the top couple items, lighting is still the top
energy savings measure. In Washington, we do see a higher percentage of total
savings compared to Idaho. I believe around 71 ish percent of our total savings is
Washington, when it's around 65% of the load. So, we do see a little bit higher energy
efficiency there. That's due to higher avoided cost, due to requirements of how we
evaluate energy efficiency by including that social cost of carbon, the Power Act adder

Appendix A
of 10%, and some cost related to the CCA. So, we do see a little bit higher uptake in
Washington. Also, I should mention the non-energy impacts as well push up saving.
For example, windows that show up in Washington that are a little bit different than
maybe Idaho is likely due to non-energy impacts. But there for your reference like I
mentioned earlier, there is the Energy Efficiency Advisory Group where they're going
to be probably covering this type of information a little bit more detail beyond what the
Power Planner I can any questions on energy efficiency. But again, we'll have some
more summarized information to document that goes out in a month.
James Gall: I wanted to talk about transmission again briefly because we did mention
the 300 MW DC line to North Dakota, but we are evaluating transmission projects
within our system as well in the IRP process because as you add generation, it may
or may not trigger additional transmission builds. A lot of the resources the model is
picking are resources that can easily interconnect with our system, but when you have
certain resources, depending on the location could have significantly higher cost to
connect and the model did select two different transmission projects that we should
be evaluating and one of them is the Rathdrum area. We are going to need new
transmission between Rathdrum and the Spokane area if we're going to put any type
of generation out in that area, whether it's a natural gas CT or a storage project,
enforcement is likely needed out there to meet new generation needs. And the second
one also is off system imports. What we're finding is if we're going to need the amount
of renewables expected, that may not come from something that's within our system.
If we basically run out of opportunities for when in our area, we're going to have to go
off system, and that means we're going to need transmission to reach out to other
areas. So, this one is depending upon where resources end up in the future. Can we
get enough locally, or do we have to go elsewhere?And so, we would need to increase
capacity to those other locations. The challenge is where you increase and I don't think
that's a known quantity yet, but it's something we need to evaluate because this is a
10 plus year exercise to build larger scale transmission like we talked about with the
case to North Dakota. Now this would be on top of that. Our project and then the last
one is something I mentioned earlier. If we start to see renewables exported off of our
system and we don't have enough renewables, that's easily connectable in our service
territory, we could or we would need to build additional transmission. So, depending
on what happens with our loads and resources within our system, where they go, we
need to build additional transmission and those again are our 10-year project. In the
best-case world, you don't need it, but in the worst case, you would. Likely I don't have
to make that decision on do we start these projects or not? But it's something that is
showing up as an opportunity, or at least a concern if we start to see projects exported
off our system, we're going to need additional transmission.

Appendix A
James Gall: Alright. We're going to shift to some of the results of this strategy.
What that does to our portfolio, whether it's cost or share of clean energy and this
example, this shows right now we're around 80% clean energy as compared to how
much we generate over the course of the year versus what our load is. This is not
saying at all that every hour is served 80% clean energy. This is just basically over the
course of how much we produce versus what our load is allocated by state. And what
you see is in, at least for Washington, you can see that first wind addition in 2029 and
2030, you can see Washington start to move up to almost 100% clean energy that's
77% that 98% allocated to Washington. There is obviously a target to be 100% by
2030 and we do have resources that are allocated when in reality to both states, so
there would be a shift in generation to comply with Washington CETA there to hit the
100% target. But as we go over time, you can see we're adding both renewable to
Washington and Idaho. But as you get to 2045, we are going to have more renewable
energy than load in this scenario, largely driven by the requirement, really two
requirements in the modeling effort. One, at least for Washington, all load all the time
has to be by renewable or non-emitting resource. What happens is you have months
that are higher load months that you're going to need to build renewable generation to
help support that, which means you're going to be long on renewable energy. And
other months, what we're seeing is that phenomenon and the solution to that
phenomenon is more storage, but then the question of how do you optimize between
overbuilding or renewables and storage. If renewables are very expensive, then you
must start to look at or storage. But if renewables are cheap, you look at less storage
and more renewables. Last IRP showed more storage, less renewables. This IRP is
showing more renewables, less storage, which is an interesting phenomenon, but that
is what is driving the 2045 excess over 100%. But I see a hand up. Go ahead, Sofya.
Sofya Atitsogbe (UTC): Hi James. I have two questions about the development from
2030 to 2044 in Washington is that the decline in the existing resources? Is that mainly
retirement or is that all some kind of low water years incorporated here as well?
James Gall: It's actually PPA expirations might be a better term than retirements, but
we have contracts that are renewable energy that will go away. So, you got to replace
those and some of those replacements that you see in blue are basically the same
resource. For example, our Rattlesnake Wind Project, a 20-year PPA, it's likely, at
least hopefully likely, we can renew that PPA and continue that resource. That's what
you're seeing there in those reductions.
Sofya Atitsogbe (UTC): Got it.
James Gall: And then the far out years, you do start to see a little bit of reduction in

Appendix A
Kettle Falls generation, which probably is not really seeable on here, but you start
getting oversupply events that could reduce the amount of renewables depending on
what season you're generating in.
Sofya Atitsogbe (UTC): Thank you. And I do understand that for Idaho, the
percentage of clean energy is declining with time.
James Gall: Correct. That again, goes back to that PT split so anything that's existing
today in the model is allocated based on that PT ratio. So, Idaho is getting the same
reductions.
Sofya Atitsogbe (UTC): Yeah.
James Gall: Over time, really it's washing. It's just a matter of how we allocate
resources as well. It gets a little bit odd because the states have different levels of
PURPA resources as well.
Sofya Atitsogbe (UTC): And my last question would be, you mentioned the new
opportunity to connect to the transmission line. Does that forecast take into account
that opportunity or is this one without it?
James Gall: Yeah. It's with it, but we don't assume any renewable energy is delivered
on it. Think of it as there's going to be market purchases. We're not counting market
purchases in this. It's just the renewables that we would be controlling so that energy,
whether it's sold or purchased, is not included in here. That's a good question.
Sofya Atitsogbe (UTC): OK. Thank you.
James Gall: Yep. Actually, that issue shows up in another short later as well.
Hopefully, I will remember to talk about that. OK. This is our rate forecast and this is
not a, don't take this home this is what our rates are going to be. That's the first caveat,
but it's a very interactional rate forecast, it's the concept. We're trying to calculate what
is the average cost per kWh of our load by state and IRPs don't model the world we
could. It would take a lot longer, which I mean by that is we're not modeling every
transmission line upgrade, every distribution line upgrade, all of our A&G costs, we
make some assumptions that those costs are going to grow over time and we're just
seeing what is the impact of power supply costs on that total revenue requirement and
then dividing by how much sales there are. Both states look very similar actually in
growth patterns between Idaho and Washington until you get to the end of the strategy,
you start to see a little bit of a separation in 2042, but it gets to be a large separation

Appendix A
in 2045. 1 think the last IRP we started to see a little bit more separation earlier but not
this time. But the reason why this is an important chart, it's really just a, come back to
what is likely to happen in the 2045 period. Maybe it's just it's so far out there we
probably should be really concentrating on it too much, but there's a cost cap in
Washington of 2% per year and there's a lot of math behind the scenes asked to
happen to the calculate that. But, the resource strategy that we presented here today,
if it came to fruition, how it's modeled, which it obviously won't, but there would be
definitely some cost cap constraints in that 2045 period and we've looked at should
we be modeling the cost cap or not. In our Preferred Resource Strategy, we've decided
not to. We're going to try to run a scenario on what that cost cap would do to our
Preferred Resource Strategy that's going to come in the next TAC meeting, but
definitely 2045 has got some substantial cost considerations because you are losing,
think about it, as all of our gas generation has to be replaced. It's just a quantity, you're
taking low-cost generation and replacing it with higher cost generation that we just saw
on the previous slides. You start to see real cost impacts at that point in time. I guess
over all the next six IRP's, this will start to kind of shape its way out on what this will
look like. But it is definitely on our minds, at least 20 years out, there could be some
cost impact questions for Avista. Know how the utilities may have cost cap
considerations earlier, but at least for events it looks like it's going to be in that end of
the 20-year cycle.
James Gall: Alright, so this is something we didn't get to last IRP TAC meeting, but
we have some Customer Benefit Indicators [CBIs] we can go through. In our CEIP
process, the Clean Energy Implementation Planning process, there is something
called a Customer Benefit Indicator. And there is, I can't tell you how many, let's say
there's thirty of them and what we're trying to do is with those indicators is measure
how well we are assisting customers in the energy transition process. We've picked
out different CBIs that can be relatable to the Integrated Resource Plan and so I'm
going to go over some of those today. I would definitely say these are not the official
numbers we file necessarily as the amount because the IRP is a little bit of an
academic exercise, but these are very good indicators of where, directionally
measurements are going. First one has to do with energy burden, or really impact the
customers rates, and you can see 2045 customers that have excess energy burden.
Excess energy burden is that their utility bill, total between gas and electric, exceeds
6% of their income. And right now, it's around 40,000 customers, but we model and in
Washington State we have that situation and that appears to remain relatively flat until
2045. And if we actually saw that rate increase, you would see in on that conditional
20,000 customers have an excess energy burden now. One way is we can deal with
energy burden today is through transfer payments or energy assistance and that helps
bring that energy burden down. But, in 2045, when you start having to replace

Appendix A
significant capacity resources, we're going to see that number go up, which could be
more assistance or what other options do we have to reduce that energy burden?
That's where we're trying to account for energy efficiency improvements made.
James Gall: Community Solar is one option that's been discussed as a way to reduce
energy burden, and that's something we're going to show in the maximum customer
benefit scenario. The chart on the right gets into the percentage of customers. While
the number of customers is staying relatively flat, the percentage of customers is
slightly declining until you get to that last year 2045, but a little under 20%. And then
by the time you get out to 2044, you're at 15% before a large rate increase and then,
how much is that energy burden, that average energy burden, it's around $1,000 today
or in a couple of years. That would increase to $2,000. Obviously, these are nominal
dollars. They have inflation in them, so that's why that's definitely increasing.
James Gall: We're at 2 minutes left. That's telling me that we're probably going to
have another TAC meeting to finish up. I think that is probably where we need to end,
but I'm going to go back to, before we call it a day, if there's any preferences for the
September meeting. If I can find that slide from the introduction. Because I could talk
all day. We don't want to do that and we don't see that yet on our screen. Oops, wrong
one, sorry. Working off a very small screen. There we go. OK.
James Gall: We are going to have the finish these slides at the next meeting on I
believe August 13t" and we'll continue the discussion. As far as the September meeting
to finish up scenarios, we have three options: September 10t", 9:00 to 11:30 or the
17t" from 9.00 to 11.30 or 1.00 to 3:30. 1 just want to know if there's any, maybe the
best question to ask is are there any that are a nope for anybody? Otherwise, we'll
probably pick. If somebody has a no, let us know. Let John know or put it in the text,
and we'll pick out a date. Just email us. We'll wait for the next couple days to see what
response we get. If it's up to me, I would prefer the 17t" to give us a little bit more time
to wrap all the work up, but so we'll see if that doesn't work for somebody, we'll
definitely go with the 10t". Appreciate the time today. Great discussion. Hopefully we
don't change the strategy again, but we got to lock it down at some point. Thank you
and have a great day.
Charlee Thompson: Thank you.
James Gall stopped transcription.

A endix A
I ,1
IF
2025 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 12 Agenda
Tuesday, August 13, 2024
Virtual Meeting — 8:30 am to 10:00 am PTZ
Topic Staff
Introductions John Lyons
Preferred Resource Strategy Results (continued) Planning Team
Avoided Costs James Gall
Microsoft Teams meeting
Join on your computer, mobile app or room device
Click here to join the meeting
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���r r/ISTA
2025 IRP TAC 12 Introductions
John Lyons, Ph.D.
Technical Advisory Committee Meeting No. 12
August 13, 2024

Appendix A
Today's Agenda
Introductions, John Lyons
Preferred Resource Strategy Results, Planning Team
Avoided Costs, James Gall
2

Appendix A
Remaining 2025 Electric IRP TAC Schedule
• TAC 12: August 13, 2024: 8:30 to 10:00 (PTZ) — Scheduled
o Preferred Resource Strategy Results (continued)
o Avoided Costs
• NEW TAC 13: September 17, 2024: 9:00 am to 11 :30 am (PTZ)
o Scenario Analysis
o IRP Next Steps
• September 2, 2024- Draft IRP Released to TAC with the following chapters:
o Economic and Load Forecast
o Long Term Position
o Distributed Energy Resource Options
o Supply Side Resource Options
o Transmission Planning and Distribution
o Preferred Resource Strategy
o Washington Clean Energy Action Plan
3

Appendix A
Remaining 2025 Electric IRP TAC Schedule
• Virtual Public Meeting- Natural Gas & Electric IRP (November 2024)
o Recorded presentation
o Daytime comment and question session (7:30 am to 8:30 am, PTZ)
o Evening comment and question session (6:00 pm to 7:00 pm, PTZ)
• October 1 , 2024- Remainder of Draft IRP Released to TAC with the following chapters:
o Executive Summary
o Introduction, Interested Party Involvement, and Process Changes
o Existing Supply Resources
o Market Analysis
o Portfolio Scenarios
o Action Plan
4

���r r/ISTA
2025 Electric Integrated Resource Plan
Draft Preferred Resource Strategy
James Gall
Technical Advisory Committee Meeting No. 12
August 13, 2024

DRAFT
Appendix A
Preferred Resource Strategy (7/16/2024)
jjjjjjhw -^a6 2027 2028 2036 2037
Shared System Resource
Mrkt/Trans 40 4 10 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Natural Gas 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Solar 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Wind 0 0 0 0 0 100 100 200 0 0 0 0 0 0 0 0 0 0 0 0
Storage 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
PtoG 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Nuclear 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Geothermal 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Biomass 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 10 0
RNG 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
DR 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Washington
Mrkt/Trans 0 0 0 0 0 0 0 0 0 0 0 50 0 0 50 50 50 50 0 50
Natural Gas 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Solar 0 1 1 1 1 1 101 1 1 1 1 1 1 1 1 1 1 1 200 5
Wind 0 0 0 200 200 100 0 0 0 0 0 0 0 0 0 140 0 120 0 200
Storage 0 0 0 0 0 0 50 0 0 0 0 0 0 0 0 0 0 0 104 62
PtoG 0 0 0 0 0 0 0 0 0 0 0 0 90 0 0 0 196 0 94 0
Nuclear 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 150
Geothermal 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 20
Biomass 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
RNG 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Idaho
Mrkt/Trans 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Natural Gas 0 0 0 0 99 0 0 0 0 0 0 90 0 0 0 0 124 0 0 0
Solar 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Wind 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Storage 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 35 0
PtoG 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Nuclear 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Geothermal 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Biomass 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
2 RNG 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Appendix A
Revised Preferred Resource Strategy (2026=35)
20261 2027F 2028 2029 2030 2031 F 20321 20331 20341 2035 Total
Market 25.8 2.5 6.4 - - - - - - - 34.6
Regional Transmission - - - - - - - 198.4 - - 198.4
Natural Gas - - - - - - - - - - -
Solar - 0.5 0.6 0.6 0.7 0.8 0.8 1.0 0.5 0.5 5.9
Wind - - - 200.0 200.0 165.9 66.0 104.0 - - 736.0
Storage - - - - - - - - - - -
Power to Gas - - - - - - - - - - -
Nuclear - - - - - - - - - - -
Geothermal - - - - - - - - - - -
Biomass - - - - - - - - - - -
Total 25.8 3.0 6.9 200.6 200.7 166.7 66.8 303.4 0.5 0.5 974.9
Cumulative Demand-Side Management I
~7$,000 MWh
Demand Response MW 0.5 1.4 3.0 4.9 7.2 8.7 9.4 10.2 11.1 12.4
Energy Efficiency aMW 3.4 7.1 11.2 15.8 19.7 24.0 29.2 34.5 39.8 44.5 Biannual EE Target
Market 13.6 1.3 3.3 - - - - - - - tlRe ional Transmission - - - - - - - 101.6 - -Natural Gas - - - - 90.2 - - - - -
Solar - - - - - - - I - - - -
Wind - - - - - 34.1 34.0 53.3 - - 121.4
Storage - - - - - - - - - - -
Power to Gas - - - - - - - - - - -
Nuclear - - - - - - - - - - -
Geothermal - - - - - - - - - - -
Biomass - - - - - - - - - - -
Total 13.6 1.3 3.3 - 90.2 34.1 34.0 155.0 - - 331.5
Cumulative Demand-Side Management
Demand Response MW - - - 0.1 0.3 0.7 1.0 1.2 1.3 1.3
Energy Efficiency aMW 1.2 2.6 4.1 5.9 7.2 8.6 10.5 12.6 14.5 16.3
3

Appendix A
Revised Preferred Resource Strategy (2036=45
2036 2037 2038 2039 20401 20411 20431 2044, 20451 Total
Market - - - - - - - - - --Regional Transmission - - - - - - - - - - -
Natural Gas - - - - - - - - - - -
Solar 0.5 0.5 0.5 0.5 0.5 0.5 0.5 180.5 120.5 0.6 305.1
Wind - - - - - 140.0 - 120.0 108.4 200.0 568.4
Storage - - - - - - - 90.0 86.1 85.3 261.4
Power to Gas - - - - 90.2 - 209.8 - - 94.3 394.3
Nuclear - - - - - - - - - 100.0 100.0
Geothermal - - - - - - - - - 20.0 20.0
Biomass - - - - - - - - - 64.4 64.4
Total 0.5 0.5 0.5 0.5 90.7 140.5 210.3 390.5 314.9 564.6 1,713.E
Cumulative Demand-Side Management
Demand Response MW 13.6 15.1 18.8 26.5 31.9 36.6 40.6 44.6 48.4 51.6
Energy Efficiency aMW 49.1 53.5 57.E 61.1 64.4 67.E 70.0 72.7 75.2 77.3
Idaho (MW- Nameplate)
Market - - - - - - - - - --Regional Transmission - - - - - - - - - - -
Natural Gas - - - - 90.2 - 94.9 - - - 185.1
Solar - - - - - - - - - - -
Wind - - - - - - - - - --Storage - - - - - - - - - - -
Power to Gas - - - - - - - - - - -
Nuclear - - - - - - - - - - -
Geothermal - - - - - - - - - - -
Biomass - - - - - - - - - 3.2 3.2
Total - - - - 90.2 - 94.9 - - 3.2
Cumulative Demand-Side Management
Demand Response MW 1.4 1.4 1.7 2.1 2.5 2.9 3.7 5.8 8.7 10.6
Energy Efficiency aMW 18.21 20.0 21.7 23.2 1 24.61 25.9 27.0 28.21 29.3 30.4
4

Appendix A
North Plains Connector
Oliver
1 1 County
i;eerll r... 1 1 1 LLAUt
1 `
1 rA_EN: TM
Dickr su i I n,an
I �Blsrnarck
• I - 1 1 1- /y
Jd1 — 1 I _
-————ti � bbiEs ciry •-' t c[ Nrnwxe I I � �
� 1 CJ61FA ti tu.Ny I � I UJMi —,V r
1 1 • �
I 1
I
1
1
I 1
345 W AC Segment : _ _ _ : Project's route is under active development
5W W oc Segment and is subject to change.
At the 7/16/2024 TAC Meeting: 300 MW of this resource was selected between 2037-45. It was
discussed this resource cannot be acquired in increments and not all benefits were modeled at this
time
5

Appendix A
Wind Selection Observations
• 850 MW of wind is selected between 2029-2033, this is a financially
beneficial early action taking advantage of IRA benefits and low PPA prices.
— If tax credits change or low priced PPA terms do not materialize, this selection will
change.
— Avista has limited transmission to integrate new wind in the service territory, if wind
projects are exported off system, the PRS selection will reduce.
• Concerned with Montana Wind winter QCC could underestimate need for
winter capability.
• Additional wind could be economic for Idaho customers, but the model
allocates to Washington due to limited options to meet long-term CETA goals.
7

DRAFT
Appendix A
Demand Response
Customer Segment Washington Idaho
Start Year Start Year
Electric Vehicle TOU Commercial 2026 8.8 2029 0.7
Battery Energy Storage All 2026 10.4 2035 1 .5
Variable Peak Pricing Large Commercial 2026 5.4 2029 1 .7
Peak Time Rebate Residential/Sm. Com. 2035 5.5 2040 4.0
Behavioral Residential/Sm. Com. 2038 1 .9 2043 1 .0
Time of Use Rates Residential/Sm. Com. 2038 2.5 n/a
Third Party Contracts Large Commercial 2039 18.0 2044 3.1
CTA ERWH Residential/Sm. Com. 2041 3.4 n/a
Central A/C Residential/Sm. Com. 2043 5.2 n/a
Total MW by 2045 (Highest of Summer/Winter) 61 .2 12.0
Assumptions:
• Current industrial contract remains
• Idaho AMI by 2029
• Total savings assumes projects do not overlap into other programs
8 • Totals include ramped savings to 2045, based on the time period the program was selected

Appendix A
EnergyEfficiencyTop Measure Types
Row Measure State 2035 Row Measure State 2035
1 Linear Lighting WA 81.34 1 Linear Lighting ID 43.34
2 Windows - High Efficiency (ENERGY STAR 7.0) WA 27.98 2 High-Bay Lighting ID 12.70
3 High-Bay Lighting WA 25.00 3 Water Heater- Pipe Insulation ID 7.90
4 Water Heater- Pipe Insulation WA 18.13 4 Ducting - Repair and Sealing ID 6.75
5 Ducting - Repair and Sealing WA 17.70 5 Insulation -Ceiling Installation ID 5.96
6 Ductless Mini Split Heat Pump WA 17.11 6 Air-Source Heat Pump ID 4.91
7 Air-Source Heat Pump WA 16.05 7 Lodging - Guest Room Controls ID 4.69
8 Water Heater(<= 55 Gal) WA 13.69 8 Windows - Low-e Storm Addition ID 4.34
9 Home Energy Reports WA 10.43 9 Ventilation -Variable Speed Control ID 4.27
10 Insulation - Ceiling Installation WA 9.26 10 Home Energy Reports ID 4.24
11 Ventilation -Variable Speed Control WA 8.60 11 Grocery - Display Case - LED Lighting ID 3.89
12 Advanced Industrial Motors WA 7.81 12 Clothes Washer- CEE Tier 2 ID 3.60
13 Insulation -Wall Sheathing WA 7.46 13 Fan System - Equipment Upgrade ID 3.40
14 Windows - Low-e Storm Addition WA 6.63 14 Refrigeration - High Efficiency Compressor ID 3.24
15 Building Shell -Air Sealing (Infiltration Control) WA 6.03 15 Kitchen Ventilation -Advanced Controls ID 2.75
16 Kitchen Ventilation -Advanced Controls WA 5.89 16 HVAC - Energy Recovery Ventilator ID 2.66
17 Clothes Washer-CEE Tier 2 WA 5.70 17 Water Heater(<= 55 Gal) ID 2.59
18 Strategic Energy Management WA 5.38 18 General Service Lighting ID 2.17
19 Insulation - Ceiling Upgrade WA 5.16 19 Ventilation - Demand Controlled ID 2.07
20 General Service Lighting WA 4.90 20 Insulation - Ceiling Upgrade ID 1.69
21 Pumping System - System Optimization WA 4.89 21 Area Lighting ID 1.68
22 HVAC - Energy Recovery Ventilator WA 4.77 22 Water Heater- Faucet Aerators ID 1.48
23 Fan System - Equipment Upgrade WA 4.54 23 Furnace - Conversion to Air-Source Heat Pump ID 1.32
24 Connected Thermostat - ENERGY STAR (1.0) WA 4.49 24 Pumping System -System Optimization ID _ 1.27
25 Refrigeration - High Efficiency Compressor WA 3.98 25 Refrigeration - High Efficiency Evaporator Fan Motors ID 1.26
9

DRAFT
Appendix A
Avista Transmission Considerations
• Rathdrum Area: New natural gas CTs begin in 2030, these are likely located
in North Idaho, new transmission will be required , if projects continue to be
sited in the area additional reinforcement is needed .
• Off-System Imports : Need to increase connections to markets/areas to
reach additional wind to import by 2045.
• If within system renewables are exported off system , additional transmission
within Avista BA will be needed .
10

Appendix A
Clean Energy Forecast
140%
120% ■Existing New
100%
21% 13% 12% °
38% 28% 35
G
g0% 11% /o
J u%
4— 60%
O
V40% 1% 77% 79% 80% 77% 78% 75% 2% 73% 71% 66% 68%
i 60% 54/o° 6°
IL 20%
0% L"d
O c E O c E O c E O c E O C E
CO
U CO U U U)
m Cu Cu m m
3: 3: 3: 3: 3:
2026 2030 2035 2040 2045
11

Appendix A
Average Energy Rate Forecast
$0.30
—Electric Washington
$0.25 — —Electric Idaho
$0.20
00
am
$0.15CD
Q � —
$0.10
$0.05
$0.00
CD 1­ 00 M U') C9 r— 00 O O N M Nt LO
N N N N CY C''� C'"i Cr) %� CO CO M M M 't :T I: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
12 Assumes non-modelled cost increase by 3.8% per year

DRAFT
Appendix A
Washington Energy Burden CBI
#2a: WA Customers with Excess Energy Burden #2b: Percent of WA Customers with Excess Energy Burden
(Before Energy Assistance) (Before Energy Assistance)
70,000 25.0%
60,000
20.0%
50,000
15.0%
40,000
30,000 10.0%
20,000
10,000 5.0%
0 0.0% IIIHIIIIIIH-1111111
CO r CO O) O N M V N to h CO O O N M 1 0 CO 00 O O N M 'IT 0 O 1� CO C) O N M 1 M)
N N N N M M M M M M M M M M It It I* It 11 It N N N N M M M Cl M M M M M M I* lzr 11 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
#2c: Average Excess Energy Burden
(Before Energy Assistance)
$2,500
$2,000
$1,500
$1,000
$500
$0
CO 1- 00 M O N CO) LO CO 1%- 00 M O N CO) LO
N N N N Cl) M M M M M Cl) M M M
13 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

DRAFT
Appendix A
DER Additions CBI
#5a: Total MWh of DER <5MW in
Named Communities
140,000
120,000
100,000 ,
80,000
60,000
40,000 I
20,000
0
t0 h 00 O O N co) --t to to h 00 C1 O N M 'cr to
N N N N M M M M M M M M M M le le Itt
O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N
#5b: Total MWh Capability of DER Storage <5MW in Named
Communities
3.0
2.5
2.0
1.5
1.0
0.5
0.0
to 1- 00 M O N M le 41 w 1- O O O N M le 0
N N N N M M M M M M CM M M M le qI qe le le qe
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
14

DRAFT
Appendix A
WA Low Income/Named Community Investments CBI
#6: Approximate Low Income/Named Community Investment and
Benefits
$70
Annual Utility Benefits
$60
Annual NEI Benefits
$50 —Annual Investment
c $40
O
$30
$20
$10
CO ti 00 M O N M Iq Ln W ti 00 M O r N M Iq LA
N N N N M M M M M M M M M M I* I* 1* 14 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
15

DRAFT
Appendix A
Reserve Margin CBI
#7: Energy Availability- Reserve Margin
35%
■Winter Summer
ca
d 30%
d
G 25%
Q
20% 'd
i J
a 15%
as
L 10%
5%
0% -
�C ti O O O T N M 14 U) CO ti O O O r N M It 0
N N N N M M M M M M M M M M IV 11 NT It 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
Notes:
• Regional Transmission not included in Reserve Margin
16 0
Demand Response reduced from peak load

DRAFT
Appendix A
Generation Location CBI
#8: Generation in WA and/or Connected Transmission System
(as a Percent of Generation)
100%
80% 80% 80% 81% 83% 81% 79% o o a o 0 0 0 0 0 0
(� 80% 77/0 76/0 76/0 76/0 76/0 76/0 76/0 77/0 77/0 75% 76/0 75% 74%
J
p 60%
V 40%
L
20%
0%
(0 f- 00 O N M 'Cr LO w 1- 00 0) O N M ICT V)
N N N N M M M M M M M M M M 1 1* 11 11 V
O O O O O O O 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 N N N N N N N N
17

DRAFT
Appendix A
Washington Air Emissions CBI
#9a: S02 #9b: NOx
5 500
4 400
N N
H3 H 300
2 t�
'L 'L
2 200
1 100
0 = = M = — — — — — — — —
IIIIIIIIIIIIIIHIIII
t0 f` CO O O N M � N t0 f` 00 Cn O N M � LO 0 _
N N N N Cl M M M M 01 M M M M V � V 't It It t0 r- O O O N Cl It U) w r 00 O O N M � 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 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
#9c: Mercury
#9d: VOC
0.05
30
0.04 25
to 20
c
0 0.03
2
C v 15
0.02
10
0.01
■ 5
0.00 -
t0 r- 00 O O N PM le to tO h 00 M O N M le to W h 00 M O r N M t to CO t• 00 O O c- N CO V to
N N N N M M M M M M M M Cl) M I 'Cr 7 le le N N N N M M M M M M M M M M It 'q le IT 'e
O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O
18

DRAFT
Appendix A
WA Greenhouse Gas Emissions CBI
#10a: Greenhouse Gas Emissions
1.2
■Direct Emissions ■Net Emissions
w 1.0
c
0
0.8
N
C
H 0.6
.L
M 0.4
0.2
CO
f-- CO 0 O � N M It O O n M O O � N M � U')
N N N N M M M M M M M M M M 't It It
CD CD O O O O O O O O CD O CD 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
#10b: Regional Greenhouse Gas Emissions
12.0
10.0 10.3 10.2 10.2 10.3 10.1
9.8 9.8 9.7 9.7 9.7 9.7 9.7 9.7 9.7 9.6 9.6 9.5 9.4 9.3 8.8
� 8.0
H
0 6.0
L
4.0
C
0
2.0
t0 r� OD OA O N M V LL7 CO r� OD C1 O N M -4 Ln
N N N N M M M M M M M Cl) Cl) M V -q V 11 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
■Waste Management ■Agriculture ■Transportation '
19 ■Residential&Commerical Fuels ■Electric Power Serving Washington ■Electric Power Serving Idaho
■Large Sources Total

DRAFT
Appendix A
Job Creation ( Direct and Induced)
Jobs Created From Resource Selection
900
798
800
700 575 616
600 531
500 392 412
400 263 283 299 314 332
300 160 188 216 241
200 96 128
00 19 39 62
CO ti CO 0) O r N M I LO CD Il- CO M O r N M 1* LO
N N N N M M M M M M M M M M q qqT 44 IT 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
Job estimates based on spending to job relationship today using IMPLAN
20

DRAFT
Appendix A
Resource Diversity ( Resource Resiliency Metrics)
Facility Diversity Fuel Diversity
3,500 3,500
■Winter ■Summer ■Winter ■Summer
3,000 3,000
2,500 — 2,500
C 2,000 C 2,000
in <A
= 1,500 = 1,500
1,000 1,000
500 500
(fl � 00 O O N M V LO (0 N O O N CO V Ln (0 rl- 0D O O N CO V Ln (0 1- W O O N M V Ln
N N N N cM M M (`') CO 0M (`') (`') cM (`') V V -V N N N N (`) 0M (`) M (`) CO m (- M 7 V V It
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
Transmission Diversity
3,500
■Winter ■Summer
- Metric Meaning 3,000
<1,500 Competitive Marketplace 2,500
c 2,000
1,500-2,500 Moderately Concentrated
= 1,500
>2,500 Highly Concentrated 1,000
500
21 CO P- CO O O N CO V (0 n CO M O N M V
0 o a o 0 0 0 0 0 o a o 0 0 0 a 0 0 0 0
N N N N N N N N N N N N N N N N N N N N

Appendix A
Avoided Costs (Idaho)
Flat • Off-Peal Energy Capacity
(Energy Energy Energ Premium Premium
( iA
2026 $41.61 $42.50 $40.42 $0.00 $0.00
2027 $37.88 $37.26 $38.70 $0.00 $0.00
2028 $35.13 $33.57 $37.19 $0.00 $0.00
2029 $34.57 $33.01 $36.64 $0.00 $0.00
2030 $38.56 $36.84 $40.85 $4.46 $100.30
2031 $43.00 $40.96 $45.74 $4.55 $102.30
2032 $42.74 $40.36 $45.92 $4.64 $104.30
2033 $43.82 $41.29 $47.20 $4.73 $106.40
2034 $43.92 $41.19 $47.54 $4.82 $108.50
2035 $44.93 $42.18 $48.59 $4.92 $110.70
2036 $44.50 $41.72 $48.21 $5.02 $112.90
2037 $45.69 $42.61 $49.82 $5.12 $115.20
2038 $45.66 $42.64 $49.68 $5.22 $117.50
2039 $46.29 $43.19 $50.42 $5.33 $119.80
2040 $47.28 $43.96 $51.69 $5.43 $122.20
2041 $47.66 $44.19 $52.29 $5.54 $124.70
2042 $49.92 $46.35 $54.68 $5.65 $127.20
2043 $50.52 $46.88 $55.38 $5.77 $129.70
2044 $51.24 $47.58 $56.12 $5.88 $132.30
2045 $52.39 $48.71 $57.26 $6.00 $134.90
Levelized $42.77 $40.64 $45.60 $3.48 $78.20
22

Appendix A
Avoided Costs (Washington)
Flat • - Off-Peak Energy Capacity
Energ Energy Energy Premium Premium
L ($/MWhj ($/MVVI31IM($/MWh) ($/kW-Yq
2026 $41.98 $43.12 $40.46 $0.00 $0.00
2027 $38.14 $37.82 $38.58 $0.00 $0.00
2028 $35.40 $34.18 $37.03 $0.00 $0.00
2029 $35.04 $33.84 $36.64 $3.31 $0.00
2030 $39.18 $37.89 $40.90 $3.37 $132.30
2031 $44.10 $42.38 $46.40 $3.44 $135.00
2032 $44.33 $42.27 $47.09 $3.51 $137.70
2033 $45.40 $43.23 $48.29 $3.58 $140.40
2034 $45.55 $43.17 $48.72 $3.65 $143.20
2035 $46.71 $44.27 $49.96 $3.73 $146.10
2036 $46.40 $43.90 $49.74 $3.80 $149.00
2037 $47.66 $44.82 $51.45 $3.88 $152.00
2038 $47.77 $44.98 $51.51 $3.95 $155.00
2039 $48.48 $45.58 $52.35 $4.03 $158.10
2040 $49.59 $46.43 $53.79 $4.11 $161.30
2041 $50.01 $46.68 $54.44 $4.20 $164.50
2042 $52.31 $48.88 $56.90 $4.28 $167.80
2043 $52.97 $49.45 $57.66 $4.37 $171.20
2044 $53.84 $50.27 $58.61 $4.45 $174.60
2045 $55.07 $51.48 $59.83 $4.54 $178.10
Levelized $44.13 $42.27 $46.60 $2.87 $103.50
23

Appendix A
Portfolio Scenarios (includes changes)
g )
Methodology Load Scenarios Resource Availability
Alternative Lowest Reasonable Cost Low Growth Clean Resource Portfolio by 2045 17% PRM (replaces lower WRAP
[only used for 2026-2029] PRM scenario)
Baseline Least Cost Portfolio High Growth 500 MW Nuclear in 2030 30% PRM (replaces 0% LOLP
[excludes CETA] scenario)
Minimal Viable CETA Target RCP 8.5 Weather Power to Gas Unavailable Maximum Washington Customer
-AL Benefit
Maximum Viable CETA Target 80% Washington Building Nu p­;;F Gast Sens+t+v+ty PRS w/ CCA repealed
Electrification by 2045
PRS Constrained to the 2% Cost 80% Washington Building ug, nGG on De nand Response
Cap (replaces unconstrained cost Electrification by 2045 & High
cap) Transportation Electrification
Scenario M6
80% Washington Building Regional Transmission not Available
Electrification by 2045 & High
Transportation Electrification
Scenario with RCP 8.5 Weather
Extreme Building/Transportation Northeast Early Retirement/Late
Electrification for Washington & Idaho
w/o new Natural Gas CTs
Data Center in 2030 On-System Wind Limited to 200 MW
No IRA Tax Incentives
24 "Proposed Portfolio Changes in Red .

Appendix A
2025 Electric IRP
TAC 12 Meeting Notes
August 13, 2024
Attendees:
Andres Alvarez, Creative Renewable Solutions; Shawn Bonfield, Avista; Michael
Brutocao, Avista; Logan Callen, City of Spokane; Josie Cummings, Avista; Kelly
Dengel, Avista; Joshua Dennis, UTC; Mike Dillon, Avista; Chris Drake, Avista; Michael
Eldred, IPUC; Ryan Ericksen, Avista; Ryan Finesilver, Avista; Damon Fisher, Avista;
Grant Forsyth, Avista; James Gall, Avista; Bill Garry; Amanda Ghering, Avista; John
Gross, Avista; Leona Haley, Avista; Lori Hermanson, Avista; Mile Hermanson, Avista;
Fred Heutte, NW Energy Coalition; Kevin Holland, Avista; Annu John, Fortis BC; Steve
Johnson; Clint Kalich, Avista; Paul Kimmell, Avista; Corey Kupersmith, Sun2o
Partners; Erik Lee, Avista; Seungjae Lee; IPUC; Kimberly Loskot, IPUC; Patrick
Maher, Avista; Jaime Majure, Avista; Heather Moline, UTC; Austin Oglesby, Avista;
Kaitlyn Olson, PSE; Michael Ott, IPUC; Tom Pardee, Avista; John Robbins, Mitsubishi;
Jared Schmautz, Avista; John Calvin Slagboom, WSU; Darrell Soyars, Avista; Collins
Sprague, Avista; Dean Spratt, Avista; Lisa Stites, Grant PUD; Jason Talford, IPUC;
Charlee Thompson, NW Energy Coalition; Taylor Vallas, Invenergy; Bill Will,
WASEIA; Rachel Wilson, Form Energy; Yao Yin, IPUC;
Introduction, John Lyons
John Lyons: We'll get started here in just a minute or two. Alright. Well, we crossed
30 people on the meeting, so I think we're good to get started. We've been pushing
around 50 for the meeting. Today we'll finish up the slide deck from last time with the
Preferred Resource Strategy results and then go into the avoided cost. Any other
questions though that have come up, things you want to ask us about, now would be
a good time to bring those up. We already went over the second page of this. James,
if you just want to pop to the third page, remaining schedule of the TACs. After today
we did add that lucky 13'" TAC meeting on September 17'". It's going to be a slightly
longer meeting from 9:00 to 11:30. We'll cover the scenario analysis and next steps of
the IRP. By that time, we'll have the first part of the draft out, that'll be September 2na
We'll have those first chapters out, so economic and load forecast chapter, long term
position where we're at with the resources and our needs, the distributed energy
resource options and everything that goes along with DERs, supply side resource
options. All the new resources and what we modeled and what their characteristics
are, the transmission planning and distribution sections chapter will be done. The big
one, the Preferred Resource Strategy, what we plan on doing over the next 20 years

Appendix A
and we'll have the Clean Energy Action Plan in there. Those will all be out by
September 2nd, released to the TAC.
John Lyons: Then on the next slide, in October, October 1 st when we release the rest
of the IRP draft. It'll be the executive summary, the introduction chapter that has all
the background if you want to look where something is in the IRP and why we did it
for regulatory requirements that's in there. Existing supply resources, our current mix
of what we have, and we'll have discussions on that. The market analysis for the
regional studies, the portfolio scenarios and then the action plan of review of what we
were asked to do in the last IRP, the 2023, and where we're at with all of those. And
then it'll have what the projects are for the next IRP.
John Lyons: Then we are having the virtual public meeting that is being moved to
November. There will be a morning session and an evening session on that. We're not
doing a lunch time this time, and there will be a prerecorded presentation that people
can watch whenever they want, and that way it'll have a little more time for a discussion
and interaction. James, do you have anything else you want to add?
James Gall: No, it said it on the virtual public meeting. That's still being developed, so
just there could be changes, but we will let the TAC know about those schedule
changes when we have a date and times and how we're going to structure those. You'll
all be invited plus we'll send out an invite to all of our customers as well. There's also,
through the CEIP process, a quarterly public meeting, and I believe this IRP
presentation will be part of that quarterly meeting as well. So more to come out about
that. Alright. Any questions on the last TAC meeting before we try to finish up the last
TAC meeting? I'll just give a pause there for people to think about that as I try to
transition to the other slide deck, OK.
John Lyons: We did have one question hanging out from last time and I believe that
was on the Connected Communities. You should have seen the answer for that when
sent out the slide deck, we got that from that area basically. And if I remember right,
it was regarding if we had some of the class information on that and how is that being
able to replicate that? Basically, it's a pilot program where we're getting that data and
then seeing how we can apply that to other areas of the distribution system.
Preferred Resource Strategy Results, James Gall
James Gall: Alright, I think we left off on this slide last time. If somebody remembers
differently, let us know. We did check the notes and then reporting, and we got here,
jumped around a little bit, and then we had to call it a morning. I think I did cover this
slide on what our energy forecast for average rate was and we were starting to get

Appendix A
into this session of kind of what happens in 2045 when CETA goes to 100%, which
causes the blip in 2045.
James Gall: I'm going to go to the next slide and then we're going to cover the energy
burden CBI and the rest of the CBIs. Then we'll get into divided cost section and then
have another scenario, or a slide on scenarios, for what we're going to see next time.
On the Washington Energy Burden CBI, there are really three calculations that we
were required to do and all of these CBIs, we're only in the IRP. We're looking at ones
that affect resource selection or resource selection I should say affects the CBI. There
are a lot of CBIs that are not necessarily related to resource planning, and we're going
to cover those in the document you're going to see go out in a couple of weeks about
which ones are applicable to the IRP and which ones are not. But the ones that we're
going to go through today are the ones we see as applicable and they're the same
CBIs from the last IRP. But we've also added a couple measurements that could be
CBIs if the CEIP process says this is something we should probably add, we'll get into
that in a little bit.
James Gall: As far as customer energy burden, on the top left, this represents the
number of customers with excess energy burden. What that means is that we're
looking at trying to calculate how much energy burden each customer has. We look at
their income, their usage of natural gas and electric, and try to estimate how many
customers have an energy burden over 6% of their incomes. I'd say this is an estimate.
We don't necessarily have incomes for every customer and we're basically using
average incomes from census tracts and then looking at average usages for those
census tracts and creating a distribution around those census tracts to come up with
an estimate. It's around 40,000 customers we think would be in this criteria in 2026
and that number really stays fairly flat as we expect our rates to increase but also
salaries to increase. We also have reducing energy use from energy efficiency that's
included. But by the time you get the 2045, you start to see where a radical change
happens. When you have that rate increase that we showed in the previous slide for
going to 100% [clean], which brought up in the last TAC meeting some discussion of
that probably being at a risk of hitting the cost cap in 2045 where that rate increase
probably would not be as high if everything happened as the IRP forecasts, which I'm
not going to say is going to happen, but who knows. But that's what it's starting to look
like.
James Gall: The second chart to the right of that takes the same data on the left but
divides that by total number of residential customers. Basically, what this shows is as
a percentage of the total population the customers having energy burden are declining
until you get to 2045. The last chart on here represents how much is that energy

Appendix A
burden or excess energy burden. If you take 6% of their income, and the amount of
dollars that's not being covered by the 6%, how much extra dollars is that? A little
under$1,000 is what we calculated for 2026, but that increases over time with inflation.
So from an inflationary adjusted value, it's probably fairly flat, but I see a hand up from
Heather. Go ahead.
Heather Moline (UTC): Yeah, James, sorry. Can you just repeat that? Oh, this is
Heather from the UTC. Can you repeat that point about the 2045 jump and something
about how that would be different, or how that would be expected, given what the IRP
shows, or given the 2% cost cap. I didn't really follow that.
James Gall: Yeah. Sure.
Heather Moline (UTC): Thank you.
James Gall: Got it. You have no problem. I kind of skipped over that to some extent
because I'm not sure what I covered last time versus this time. But in 2045, we are by
law, I guess the goal is to be 100% clean energy, but when you look at the resources
that we have to remove and then add to the system to get to that, that jump is obviously
more than 2% from 2044 to 2045. But that necessarily isn't how the cost cap
calculation is going to occur in that time. Actually, we have very little direction from the
statute or law on how that's going to work in 2045 because the 2% cost cap really is
through 2044. So, if the 2045 period, if it's 2045 or a 4-year period, whatever you want
to call that, if that has a similar cost CAP calculation methodology compared to what
we're required to do between now and 2044, we would likely exceed that cost cap.
The resources that are called for to get to 100% in that period, since we would exceed
that cost CAP, we're not going to see those resources. So, you're going to have a
lesser rate increase in reality, if we followed the cost cap methodology in that period.
We're going to have a scenario to share at the next meeting of what that would likely
look like, but again, you don't know what the cost cap is going to look like in 2045, but
that's where I was going with the 2045 cost cap. I don't know if that helps or not,
Heather.
Heather Moline (UTC): Yeah, I think I'm hearing it depends on what the cost cap
methodology is. Yeah, I'm tracking. Thank you.
James Gall: Yeah. Because if you look at the first, the four years now, it's 2% of
revenue requirement. The first of the 4-year period times four, 3 * 2% for the third
period and so on. The cost cap from a period is actually extremely high. It's not 2%
period to period, it's much higher. But in 2045, 1 don't know what it's going to be. The

Appendix A
other challenge is when you get to 2045, your cost cap is going to be based on
everything that you've done from the time the law passed the 2044 as well. You don't
even know what our baseline would be in 2044 to calculate the cost cap. So, we're
going to guess what it could look like, but I'm not sure. And I see Charlee has her hand
up. Go ahead.
Charlee Thompson: Yeah. Good morning everyone. My question, still on the energy
burden CBIs, just clarifying the projection through 2045. It's based on projected rate
increases and census tract level income data. Is that right? But not base.
James Gall: Is that correct?
Charlee Thompson: Sorry, go ahead.
James Gall: No, you finish your thought here. I thought you were done. Go ahead.
Charlee Thompson: Wait a second there, your part to the question, it is not based on
other factors like Avista's internal goals for its energy assistance programs, right, like
it's new bill assistance programs or EE programs?
James Gall: Yeah. It's before energy assistance, so any energy assistance program
that's not included what it does include though is if we did community solar. We had
some community solar forecasted in the IRP that's included. So, it is this census tract
based of income, and it's based on how Mike's going to.
Mike Hermanson: There's actually three sources of income data. We have people
that are participating in some sort of assistance program, and they provided their
income data to Avista. We've used that. We had a third-party data source that we used
and then the remaining ones are from the census tracts. There are three sources of
data with different levels of accuracy. No, I've forgotten all the question points. Did we
get them all?
Charlee Thompson: Yeah, I think so. Is that based off of rate increase and then the
income data and good to know that there's three different sources and then the second
was it doesn't include energy assistance projections.
Mike Hermanson: Yep.
Charlee Thompson: That was helpful. Thank you.

Appendix A
James Gall: And the rate increase it's based on this slide here. We take the existing
rate structure that we have today and escalate it at the rate of growth of this forecast.
Now this forecast is power supply only. But what we do for the non-power supply cost
that we model, we increase those that 3.8% per year. Obviously, that fluctuates every
year or every rate case, but we try to keep everything that we don't model constant or
constant growth and then just show the effects of power supply costs. Alright.
Charlee Thompson: Thank you.
James Gall: You're welcome. Any other questions? Alright, so let's go to the DER
CBIs. this slide is actually slightly updated from what we sent out. That's on the first
chart on top. I was awaiting to get some results, for those of you that may have been
following along, we had a consultant help us do a DER forecast, which is basically a
solar, battery, small wind forecast for our company along with an EV forecast and they
did a differential between where solar is going to be in a Named Community
designated area or non-designated area. The previous slide had the forecast for all
areas, and I was able to get a breakdown of the Named Communities only and that's
what this reflects. So, we have solar owned by customers in this chart that are in
Named Communities, it also includes any small PURPA projects that would be in any
community, plus any solar that we've proposed in the IRP. Small, community solar
based is in here. We do see a radical increase from 2026 to we'll say 2030, early
2030s and slower growth thereafter. The reason for that trajectory is in the solar
forecast the consultant has done, it's based upon how tax credits are working. In 2033,
that's when the IRA expires and that's why it slows its growth, then grows with more
of a constant rate.
James Gall: That's our forecast for energy, mostly solar in Named Communities and
the second chart below is the storage assumed in Named Communities.
I've not updated this one yet for any of the storage that's included in that DER forecast,
we do need to make that update, but it's very small. It probably won't look much
different than this one, because those are mostly kWh amounts, but so I do owe an
update on that one. We did not select any DER energy storage on the distribution
system in the IRP. That does not mean there won't be any coming in our next
distribution plan. And what I mean by that is, and if you are following the DPAG process
as well, you might hear somebody in the future with some of the plans are there. But
the advantage with an IRP is we can create what's called an avoided cost, which we're
going to talk about later. That avoided cost could help the Distribution Planning team
when they're looking at solving constraints or growth on the distribution system. They
have options and they can use some of our information in the IRP to identify whether

Appendix A
or not an energy storage project would be cost effective on the distribution system. If
it is cost effective, we would then pick up that information in the next IRP. So that's
going to be an iterative process for distribution energy storage, so nothing yet.
Question, go ahead Joshua.
Dennis, Joshua (UTC): Joshua Dennis, UTC, I had a question about your 5A. With
that, total megawatts of DR in Named Communities. You mentioned small PURPA
projects included in there. And I was wondering, did any of them have liquid fuel
generation in those included? Yeah.
James Gall: Liquid fuel. It'd be water that's liquid, but no, they're all mostly small water
or hydroelectric facilities.
Dennis, Joshua (UTC): Thank you.
James Gall: Yeah, we the only other besides hydroelectric we have is that's not
hydroelectric. Sorry, we have a waste to energy facility and that's large in Spokane
and we have a large biomass generator in Lewiston, ID. We had another lumber mill
that has since closed. We have another one that we just signed, but it's a net PURPA
that's kind of a different thing, but it is biomass.
Dennis, Joshua (UTC): Thank you.
James Gall: You're welcome. And actually, now that you brought that up, I'm just
going to give you, the IRP, when we release that, the existing supply chapter covers
all the PURPA resources, what they are, where they're located, their sizes and what
they're contract term is. So, look for that in the IRP. You can also check the last one,
but we'll have some updates this time around. OK, let's move on. This chart is, I'd say,
a very complex one, but I'll try to walk you through it. Let's say it's one of those, there
were good intentions. I'm not sure if it paid off or not, and the good intentions for the
CBI when we were developing these three years ago, but the goal was to look at
investment and that's the black line of investment in Named Communities or low
income in our case. One of the challenges with investment is in an IRP we don't we
know, if it's a generator we know what the capital cost is, but when you're looking at
an energy efficiency program, for example. From an IRP perspective, we just get a
Ievelized cost. So, we have to translate that somehow into an upfront investment.
This is a very calculated estimate of what the investment is, but the black line
represents how much in a given year is invested in the Named Community or a low-
income community.

Appendix A
James Gall: In the case of energy efficiency, that raises every year until about 2033.
And then as energy efficiency starts to slow down and the forecast of the additional or
incremental investment slowly declines. This is a not a cumulative investment or an
investment. This is just an annual investment there in the black Line and actually in
2030 you can see it kind of stays constant for a year which is kind of an anomaly out
of the energy efficiency forecast. The bars represent the benefit, and the orange
represents the utility benefit. Or what do I call that is really the avoided cost of the
energy or capacity?And then the blue bar portion represents the NEI value. For energy
efficiency, we've worked with the consultant to help us identify any NEls or non-energy
impacts for energy efficiency and for some supply side resources as well. But we're
taking those two benefits and adding them together and then this is a cumulative
version of the benefit. It's showing you by the end of the study you have about 60
million in cumulative benefits. And then when we have the annual investment going
forth, this is what was asked of us to create, and like I said, it's very informative. It's
not like an NPV analysis, but it's kind of an interesting view of about how you could
look at, I guess costs and benefits. Any questions?
Tom Pardee: Steve has a question. Are the numbers for solar and storage broken
down between behind the meter versus on the distribution side of the meter?
James Gall: I guess maybe that relates back to this one. Here, this is the line that
says solar. That's in total 5.9 megawatts that is in front of the meter and also the small
solar that's in this and the, let's just say that's 10 megawatts in front of the meter for
small distributed solar and then the majority of what you could say, what would be the
remaining amount would be behind the meter solar. So, all of the customer solar. I
don't have a breakdown of each, but I think between that 10 megawatts plus what we
have today, which is another, let's say half a megawatt is from the meter, yeah. OK.
James Gall: Any other questions, Tom? OK, let's keep going. Reserve margin. This
is actually an interesting result I got from the resource strategy, and it's really due to a
transmission line, but we'll cover that in a moment. Our resource planning model, we
had a constraint for planning reserve margin. We've covered this in multiple TAC
meetings that we plan to have planning margin to ensure we have reliability, but this
is also a CBI. The CBI is a little bit different, but its goal was to look at how well your
reserve margin is. We're trying to calculate a reserve margin and if you look backward
in time, the reserve margin jumps around because we're looking at actual load and
we're looking at actual generation. But, looking forward, we should always expect the
reserve margin to be what our modeling constraint is, 24% 1 believe winter and 17%
or 18% in the summer, but we're not seeing that and there's a reason why. That is
because our transmission line, the 300 MW line we've talked about in the previous

Appendix A
couple meetings from Colstrip to Montana, is basically increasing market reliance. And
we're not including that in our calculation. So, from a reserve margin of resources, we
would control in the future, you can see our reserve margins slowly start declining after
2033 when that line is proposed, and the IRP stays around 15-20%. But it was just
interesting when you take out that line because you're assuming that's a market
purchase that you're relying on for reserve margins.
James Gall: Doesn't make us less reliable because now we have additional market
access. But it was just kind of an interesting result of that change also on demand
response, we deducted that from our load as well. That would still get your reserve
margin above the required ratio, but that's another note as well that we're reducing
peak demand by DR. But again, this is kind of interesting though. It's just showing our
future though is more market reliant with that transmission addition. We are running
and we have shown the TAC, the reliability results from the PRS that still show in 2030
and 2045 if resources are built as forecast, we do have a reliable system with that
market reliance addition. Nothing to worry about here, it is just kind of an interesting
result of data.
James Gall: Alright, so the next one is where our resources are located. This one
we've calculated the total amount of generation that is in our forecast and divide that
by the total amount of generation. I actually missed one thing in the first statement
there, the amount of generation that's in Washington State or connected to our
transmission system. The idea behind this CBI was to try to look at resiliency of our
system and the theory, the background behind this, is that if resources are in the State
of Washington or connected to our transmission system directly, we would be more
resilient because resources are closer to the load of the State of Washington. We did
the calculation over about 80% and that stays fairly constant, slightly declines a little
bit over time. And the reason for that slight decline really has to do with some Montana
wind that's forecasted, but in reality, we don't know where a lot of our future generation
is going to be located. We're going to do RFPs in the future. They may or may not be
located in Washington, so this may be better to look at retrospective over time. If it's
still important when we go through the CEIP process, but it's hard to forecast
necessarily where things are going to show up in the future, but that one does not look
like it's going to significantly decline. Could slightly depending on where resources are
eventually cited.
James Gall: OK, air conditions. This one, there's going to be actually two sets of these
charts you're going to see in the IRP document. You'll see this set, which is related to
the CBI, and we have we have another set that is for our total system. But in the case
of the CBI for Washington, it's only plants in Washington State which is Kettle Falls,

Appendix A
Boulder Park, Northeast and Kettle Falls CT. This is a forecast of those resources plus
anything that's added that might be in Washington in the future. Top left is SO2 which
is from a natural gas facility, our Kettle Falls facility is very low and basically goes to
zero out in the future. NOx is another story, and you're going to see increases,
especially in 2045 for the other ones as well. But NOx at Kettle Falls, there's some
amount of NOx at our peckers. But you see a reduction over time. That increase at
the end really has to do with the forecast assumes we're going to need more biomass
generators out in the future. A Kettle Falls Unit 2 and a Kettle Falls upgrade is
contemplated. Out of that future, to get to the 100% goal, there would be NOx related
to those plants. Also, we have hydrogen-based ammonia plants forecast in the late
2030s. There would be NOx related to those facilities as well. I saw a question pop up.
Tom Pardee: Yeah, it's from Steve Johnson. I assume the IRP will discuss the reserve
margin in the context of low hydro years and financial adequacy versus physical
resource adequacy. Yes, I'll put that way.
James Gall: I'll come back to that, Steve, and after I get this slide. You make some
good points there I want to cover. Alright, so back on NOx. We have new facilities that
are contributing to NOx and whether it's biomass or ammonia. But we do see
reductions from the natural gas side of things and that's the same case with mercury
and VOCs as well. But as far as the ammonia facilities, it's really affecting only the
NOx calculation. The biomass is what's driving the, just say NOx is a combination of
the ammonia and the biomass. But the VOC and mercury is mostly driven by the
biomass units. When the model is looking at resources, we do include a societal cost
for each of these emissions. It's just one of the challenges when you're trying to get to
100%. You're trying to get to 100% all the time and you need some baseload
generation. So, the model is looking at OK do I build basically in this period of time,
have biomass, I can probably build around, we'll say 60 megawatts or 70 megawatts
of biomass which is plausible versus nuclear. And that's really your only two options
for more of a base load style resource out in this period in time. We have some peaker
options via the ammonia and hydrogen type resources for peaking. Those do get
selected as well and the same with the energy storage which gets selected as well.
But the model definitely it's wanting more baseload resources at this time because I
think our loads are quite a bit higher. That's why we're starting to see nuclear and
these generators we did not see in the previous IRPs. Comment from Charlee. Sorry,
I missed this. VOC is primarily from which resources? Kettle Falls and future biomass
facilities.
Charlee Thompson: Thank you.

Appendix A
James Gall: Yep, alright. I'm going to go back to Steve's question on resource
adequacy. What we definitely see when we run our resource planning model is when
you have a low water year and a high load period in the winter like we saw in this
January, that's when you're going to see risk of not serving 100% load. Reliability
models are trying to do, take 1,000 simulations of varying conditions, but the idea
behind it is you can serve all of your load in 95% of those conditions. But the conditions
you can't serve load in are usually those cases where you have high loads, lower
water, or a resource outage. Those are still at risk in the future and the way to solve
that risk is really two options. One, you create more diversity in the region and have a
regional approach which is what's going on through the WRAP process. Now, whether
or not that planning margin the WRAP comes up with is high enough to cover that
condition remains to be seen. But the second solution is you just have to start planning
for a low water year or a combination of events, which means effectively you're
planning for a lower LOLP standard. Instead of planning for 5%, maybe you plan for
1% and that would be a solution to that. And actually, we have some scenarios on that
in the next TAC meeting. Hopefully, that addresses Steve comment. There's I say
definitely risk. The other option I guess is you have more market reliance that's kind of
what we saw in January where the region exceeded what its local resources could
provide. It had to go to the market and was able to get it from another region. But
think I saw a hand come up. Steve just said thank you. Alright, appreciate the
questions and comments. Steve does have his hand up. Steve, you still have a
question?
Steve Johnson (Guest): Well, I do and it really relates. I mean your explanation,
James was perfect. And then what I wanted the audience to realize is that during that
period of tough to meet load, whether or not you lose load or not, prices get really high
both for energy and for capacity. And that's why I introduced that concept of financial
resource adequacy. You might want to say yes or no to the question when these
events happen and this is more of a financial question than a resource, physical
reliability question. Will the Company keep the lights on, but show up more or less
bankrupt, like 24 years ago? I mean, that's what's kind of these are, statistical
averages for the physicality of resource adequacy.
James Gall: Yeah.
Steve Johnson (Guest): But we have to start really putting back on the plate that
concern about how do we survive financially and what do we look like at that moment
financially, I want to read about that now in the IRP, I don't want to take up time in this
meeting. I just wanted to lay that question down. I'll be looking at the IRP to see what

Appendix A
that looks like because this is pretty tough times out in the market. I mean I do not
envy. I do not want to be a trader meeting load right now, so good luck.
James Gall: Alright. Well, appreciate that. You make a good point on the financial
side of it because that is the risk you have when you're in the market. I remember,
even 10 years back, trying to do analysis on a financial resource adequacy where
you're weighing the cost to go to a greater financial, or sorry, you're way in the cost of
higher market prices to be less reliable or should you build more resources to avoid
that cost and whether it's a societal cost or true market cost. That was always kind of
a goal to try to model that. And I don't think we were able to achieve that, we left it to
planning margins, but it maybe it could be appropriate again.
Steve Johnson (Guest): Yeah.
James Gall: But I think what you're seeing though with $3,000 prices that we saw in
January is maybe buying, capacity can be cost effective when you're comparing it to
those substantial price spikes or even getting more market access. Having more
transmission to other markets is another avenue as well, but very good comments.
Appreciate it, Steve.
Steve Johnson (Guest): OK. Thanks.
James Gall: You're welcome. Alright, I think we're on this slide next, greenhouse gas
emissions. I'll say one of these slides which is tables and charts is very useful. The
other one is a little bit of a challenge and we're going to cover that in a second. But on
the top one, again, this is Washington share of emissions. We take our total emissions
and then take the Washington share of those and then that's what you're seeing in this
top chart, and they are declining overtime as resources are, or I should say our natural
gas resources, there's two things happening. One is some of our peers are retiring
over time, which drives the reduction slightly for the Washington share. And then the
second one is we expect our natural gas generators to run less in the future, which
that is due to if all of the renewables show up, that is expected in our price forecast,
there's going to be less hours that our gas facilities will be dispatched. No, I'll say this
is like what Steve mentioned earlier, right now prices are extremely high, the market
is very tight, so we're seeing gas plants dispatch a lot and actually they've probably, I
think it's some of the all-time highs for a capacity factor point of view. But if resources
are built out in the future like we're expecting, they should slowly decline. Also, we
have in the models and about 2031 we expect, if the CCA continues past the
November election, at some point will the commit or will the ecology change the rules
as allowed in 2031 for how resource or how allowances are given to utilities. We

Appendix A
assume the worst-case scenario where we're including the price of the CCA in
dispatch of all resources in 2031. That creates a reduction in dispatch for some of our
facilities as well. That's the dark blue line, or I'm sorry, the light blue line. The dark blue
line represents how much net emissions are, which means when we sell power, we're
including some of the emissions of our total system in that sale. And that's why it's
lower. In the outer years, you can see that dark blue line is actually a little bit higher,
and that's because our system becomes a net buyer. About 2042, we go from a net
seller to a net buyer in the marketplace.
James Gall: The second chart to the bottom was another one of those CBIs that has
good intentions. Unfortunately, we can't get the data to do it for the most part, but the
idea was to look at regional emissions from not just Avista, but from other industries
and calculate an emissions forecast. The challenge with that is, we're just a small
amount of emissions in the region and transportation is a large amount of it. And that
big light blue line you can see it's not really declining. We tried to make our best shot
at that, but with the CCA and CETA, you would expect emissions to decline further
from that transportation sector. But I don't know if they will or not. I don't have a good
way to forecast that. The only thing we can really forecast is emissions related to
Avista's natural gas system. We're going to propose to remove this CBI. I included it
here and in the document that we're going to send out a couple weeks, I'm not going
to include it there because we just can't get data for the rest of the region and forecast
it. But again, it's good intention of a CBI, but it's just something we're probably going
to have to let go of because of lack of data. Alright.
James Gall: OK, so that's all the CBIs. Now we're going to get a couple different
metrics that were brought up through the TAC process that we want to share some
results of from the Preferred Resource Strategy. The first one is jobs. We got a tool
called IMPLAN and IMPLAN is an economic model that helps figure out the economic
impact of investment. If you ever read in the newspaper, something that's built is going
to create X amount of jobs and is going to add millions of dollars to the local economy.
They're using a tool like IMPLAN to do that calculation. So IMPLAN, with an "m" it's an
"m" so we'll fix that, what we did is we looked at all of the investment types that are in
the Preferred Resource Strategy, energy efficiency or generating resources. When it's
wind or solar, we got a value of the number of jobs per $1 million investment, if I recall
right. Yes. OK, so we got a job per million-dollar investment. We went through our
strategy and try to come up with how many jobs were created and this is what we
came up with. It starts out with around 19 jobs in 2026 goes up to around 800 by 2045.
This includes direct jobs. Tell me, John. Go ahead and allow to you to go through.

Appendix A
John Lyons: Basically, these are the jobs that would be done beyond the initial
injection into the economy. There's the money that's spent by hired people to go in
and to erect the wind facilities, put up solar panels, things like that, and then it's those
indirect jobs that are developed because of that. As they're in town, they're buying
lunch. They're going to movie theaters. They're buying houses. All that stuff that helps
grow the local economy and the numbers that were coming up, they are small, but that
is what we come up with. There's been a really good study that just has come out
recently from the national labs where they were able to use the really hyper detailed
Census data where they had to basically sign all these secrecy agreements to look at
it. But they've looked at it, and you're right around nationally about 0.55 jobs per
$1,000,000 of investment most now we're just looking at this as the whole statewide.
A lot of those jobs are usually local, that study from the national labs actually looked
at 6 miles out from the facility and that's where the bulk of them are. But those do tend
to be longer term jobs, so they looked out six or seven years and the jobs were still
there.
James Gall: All right. I thought I'd put on this one. This is new jobs. It doesn't include
lost jobs, so we do have power plants that are retired. It doesn't net those out as well.
It's a one-sided look at this. But anyway, it's interesting results. I there was some
interest in job data from our public participation process I think. The Equity Advisory
Group was very interested in that and seeing if we can do some local spending, if will
that help develop some of these lower income areas. Going forward, the one challenge
with this is IMPLAN is not free. It costs money and we're using it. We actually got it for
the gas IRP to help with some values of the gas system. I'm not sure we're going to
continue to have this model available, so I don't know if it's going to be a good one to
include ongoing, but we have it today, so we want to utilize it and see what its
capabilities are. This is what we got from it.
James Gall: Alright, I think this is my last metric slide and this is on resource diversity.
Early on in the TAC process, about a year and a half ago, we had a short discussion
on how do we measure resiliency in an IRP from a generator point of view where a lot
of times resiliency was where it gets really categorized. OK, what's the resiliency of
really the delivery system? How well are you going to be able to deliver the electrons
on the distribution system when there's a storm or an outage of some kind when we're
trying to look at generation diversity? We thought, OK, that might be a way to look at
resiliency because if you had a major event, if all of your resources are located in that
specific area, maybe that's more at risk. And therefore, if you have more diverse
resources, you're going to be more resilient. It's a stretch. I'll put that way. So, we went
along with this ride for a little bit to see if this made any sense. We looked at how can
we measure diversity of the resources of our system? We came up with a methodology

Appendix A
called the Herfindahl index and that's used for measuring whether or not there's
monopolistic powers in certain markets. And I got an economist next to me. He
probably wants to say something, if he wants to, he can.
John Lyons: It's Herfindahl-Hirschman. Can't forget Hirschman.
James Gall: I know. Sorry. OK. Thank you. They came up with the methodology of
calculating a score of how diversified the marketplace is. The bottom left of this chart
represents what they came up with, what is diversified versus not so diversified.
If you had a score above 2,500, you're highly concentrated, and that means that there's
not a lot of diversity. Think about it. It's more of a, I won't call it monopolistic, but closer
to that realm. If you look at a monopoly to perfect competition, economic modeling,
when you got a conversation should explain that. But well, and this is it, basically this
is the same study that would be done say if you've got two businesses want to merge.
So, when AT&T and T-Mobile wanted to merge, the Federal Trade Commission would
have actually run those numbers and see what is the HHI go to and see how much
further it goes up. It gets too concentrated. Then they have to decide and say is that
too much of an issue with competition and we need to just totally block it? Or can we
have them divest some asset? Same thing, grocery stores are going to merge, trucking
companies, whatever it's going to be, because if you have too much concentration,
you have too much market power and you can essentially control the market.
Traditionally, you'd think like 80 plus percent would be generally considered a really
strong monopoly. But think of things like OPEC, which controls about 40% of oil
production in the world, and they can swing prices with that 40% quite a bit.
James Gall: This is just a mathematical way of us looking at that dispersion of
resources, kind of like how we use Black Scholes model for some of the finance issues
we were looking at that in the past, so trying to use some new tools to apply them.
Alright, so we came up with three metrics. I'll go through each of these: facility, fuel
and transmission. Facility was obviously the lowest, most diverse methodology we
look at. That is looking at every unit that we have and counting it, counting every unit
on its own. So how this really works is you take the unit capacity, and you square it,
and then you add them all up and they came out. But when you look at it as a unit
basis, we have a lot of diversity across our units because it's really a function of
quantity in this calculation, which ended up being, I would say, not a good metric. While
we have a lot of units which creates this score to go down, the problem is that one of
our units is a very large, actually two of our units, Coyote Springs 2 and you have like
we call a shaft risk. Even though we have a very low score here, one unit on its own
is a high percentage of the total. But from a scoring of HHI, it didn't show up. So, we
don't like this metric because of that. What I mean by shaft risk is, for example, Coyote

Appendix A
Springs 2, which is in the wintertime around 300 and we'll call it 20 megawatts. As a
percentage of our peak load, that's a high percentage if you lost that resource,
replacing it is a harder challenge. This resource diversity, you'd expect that that would
show up, but it didn't. And so, while we have low or quite a bit of diversity and
resources, but you still have a large shaft risk issue. And when you look at a shaft risk
percentage of Avista versus any other utility in the West Coast, I think we're still the
highest shaft risk utility in the West when you look at the largest unit as a percentage
of your peak load. While this one looks good from this point of view, but when you dig
into the shaft risk issue, we have some challenges, which is why in our planning margin
requirements we have a minimum planning margin of our largest single contingency
for summer. And that's for that reason. So that one didn't quite work out so good.
James Gall: Looks good on paper, but there's some challenges there, so the next one
we looked at was fuel diversity and this one actually kind of interesting because it's
fairly stable, then all of a sudden it just radically declines where we were at that edge
of highly concentrated and then a reduction. And what we're doing here is looking at
what is really the fuel source of our generation. Think about hydro. We have four hydro
sources. We have the Mid-C, the Columbia River, it's a hydro source. We have the
Clark Fork River. We have the Spokane River and now we have some irrigation hydro.
Really, those are our four sources.
James Gall: And then we look at natural gas, we really have one source and that's
the GTN pipeline. Then you look at wind, we have two sources now, we have a wind
regime in the Eastern Washington area and now we have a wind regime in Montana,
so we have very few sources of where our energy comes, so that's why it's fairly highly
concentrated. But when you get past 2041, we start to see a decline there and that's
because we start seeing new resources show up in the resource strategy from other
locations. And that is when you start getting into ammonia turbines or getting other
energy storage. You're getting nuclear in the out years, you started to see that fuel
diversity. This one I thought was the most interesting of the three because it actually
showed that benefit of having a more diverse set of resources and it didn't necessarily
have an underlying challenge behind it like the facility diversity.
James Gall: Now the third one was transmission, and this one was really kind of
thought of being based on a wildfire risk. Let's say you had a very large wildfire. It took
out a geographic area. How diverse are your resources from a geographic point of
view? Let's say we had six areas of our system and you lost one. Could you recover
from that loss of one of the six. That was kind of the background thought of this one,
but we split up our resources and areas of our system. I call either transmission, or
geography might be a better term, but this one was in that mildly concentrated area. It

Appendix A
stayed flat the whole time, but there was one problem with this one, it actually probably
could decline drastically, we just don't know where resources are physically going to
end up. While this one it is a good metric, but in going look in the future if you don't
know where your resources are going to be, it's a hard one to forecast. So, that one
probably do not see as useful because of that purpose or that reason. But anyway, it
was a good intellectual exercise. We'll probably continue to look at this to some level
in the future, but it is definitely a hard thing to model from a generation perspective
and considering an IRP. But we definitely learn a few things in this process.
James Gall: OK, this is the last slide before I go to avoided costs. Are there any
questions? OK, we have 30 minutes left. I think we might get done early. We'll see.
OK, so avoided costs. I've kept these slides fairly simple. What the results are and
how avoided costs work is we're trying to estimate if we had to acquire new resources
based upon the IRP, what is the cost of those resources on generic terms? So, we
look at what resources were picked in the Preferred Resource Strategy for both Idaho
and Washington and try to back into what those costs are. And you can use that
information to help you or help us decide between IRPs if energy efficiency or a small
resource is cost effective. Now it's a big resource, we'd likely go out to bid in an RFP,
but for something small it's very helpful to help us come up with what a resource is
really worth. It can be also useful in setting PURPA rates as well, because PURPA it's
required to be paid based on avoided cost.
James Gall: For the most part, avoided costs are based on a market price forecast.
You see on both of these charts there's an on peak and off peak and a flat price, and
that is our Mid-C price forecast from our Aurora model. You'll see there is a difference
in price, slight difference between the Washington and Idaho. Washington is slightly
higher and that has to do with the CCA and what happens is, we're using a delivered
into Washington price for Washington; and for Idaho, we're using a not delivered price
into Washington. It's kind of a call like a borderline price. The prices are not much
different, and actually that's something we were seeing in the marketplace as well
today that there's a premium to delivery in Washington, but the premium is not
substantially higher than one that's not delivered in Washington. We're seeing that in
our world modeling as well. That is what on peak off-peak flat is. That's a Mid-C price
forecast, on peak would be delivered in the middle of the day between, don't want to
get this wrong, 7:00 AM and 10:00 PM except for Sundays. That's off peak, so off peak
is really nighttime pricing. You can see the nighttime pricing or off-peak pricing is
actually, I want to make sure you got these. I think these are backwards actually these
get switched on me. We're going to revise this chart, I apologize, but I think this one
on the Washington side is correct. I think I might have switched to label on the Idaho
side on the on off peak, but the off-peak prices in the long run are higher than the on

Appendix A
peak and that has to do with solar. So over forecasting on the future is in the middle
of the day, prices will decline drastically and that drives the on peak price lower,
although during the on peak period it has the highest prices in the late evening. But
overall, for the 16-hour period, the prices are lower compared to off peak. So, when
we look at resources from an hourly point of view, we can look at it and say, OK, solar,
you produce a lot of on peak power, but most of your power is in the middle of the day
when the prices are the lowest. So, that would get less value than, say, a resource
that produces power at night or in the evenings. Looks like you have a question come
up and come up. Note from Heather. OK, no problem. If there's any questions you feel
free to jump in, happy to kind of go through them. Go ahead. Yao.
Yao Yin: Thank you. I have a couple questions about prices. Did you say
Washington's prices are higher?
James Gall: I did say that. Washington prices, subject to check on the previous slide,
should have higher energy prices from the Mid-C calculation, so the energy portion
that is based on market prices will have a higher price.
Yao Yin: Do we assume the market for market purchases and market sales, we use
the same Mid-C prices?
James Gall: From an IRP perspective, we typically do, but in reality there is a spread
between buying and selling. That could be from a reality perspective, that's something
to consider and then this is from other cases we've been involved with. When you're
long, can you really get that price? These are just showing what the market price
forecast is, not looking at a position of a utility, but just this is what the market price
forecast is.
Yao Yin: And we don't distinguish purchase or sale for the IRP purpose?
James Gall: Correct. This is just the raw price of the market for the forecast.
Yao Yin: Last question, so the Washington prices are higher due to CCA.
James Gall: Yep.
Yao Yin: Did you say that?
James Gall: Correct.

Appendix A
Yao Yin: But my understanding of the CCA is for off system sales, it doesn't distinguish
the two states. I mean only the dispatch cost. For example, for Boulder Park, I think
the company proposes in multiple prior cases that Idaho would pay the Idaho portion,
but for off system sales based on our last understanding. In the last case, it doesn't
distinguish both Washington and Idaho.
James Gall: Depends on where your delivery point is, so if you're delivery point is in
Washington, then you're assessed a carbon price. And if you're delivery point is not in
Washington, you're not assessed a carbon price. The challenge though in the
marketplace is there's not a major difference in the price that you get between a
delivered in Washington product versus a delivered in non-Washington. The carbon
price is really reflective of where the product is delivered to after the fact. How do we
model that in an IRP? This goes back several TAC meetings, but we have a market
that's just Washington and then we have a couple different zones in our model that
are not in Washington and the price that we're showing for the Idaho is the price of a
non-Washington product that's in the northwest. So, if we were going to try to if we
had a market or. Make sure I get this right. We have an Avista zone, and we have BPA
zone, and we have an Oregon zone, and we have a Washington zone. The
Washington zone is going to have the highest price because of the carbon cost in that
state. But the three other zones around it are going to have similar pricing because
they're going to have to either one to serve Washington. They're going to have to
dispatch and pay that price that drives those prices up higher and that price that's
outside of that state is what we're using for the Idaho calculation. Does that make
sense or not?
Yao Yin: I think I understand what you're saying. When you say delivery point, you
mean for the transaction that happens and to me, you have to specify where the
energy goes to and if it's outside of Washington, then the Mid-C transaction prices
could be lower.
James Gall: Yeah, if it's outside of Washington, you may. Let's say you're selling. You
may sell for the same price you're just not paying the cost of the carbon. Let's say you
had a transaction that's just say Mid-C and you don't know who the counterparty is,
and so you sell it for, let's say $100. And after the fact you found out it was delivered
to Puget, you're going to have to pay a carbon penalty. If it was delivered to Portland
General, you wouldn't have to pay the penalty. That's what the structure of the
marketplace is now. My understanding is you and that's why there's not, and this one
it's some of the challenges we were having in the Northwest is you don't know if you
have a liability or not. So, you're going to start seeing more and more, you're going to

Appendix A
have pricing outside of the State of Washington that is lower, but we're seeing today
is that pricing outside the State of Washington is not much lower.
Yao Yin: OK. That is why we see the difference between Idaho avoided costs and
Washington what it costs.
James Gall: Correct for that. For the market price portion, now when I get into the
energy premium and the capacity premium, there will be different reasons for that.
Yao Yin: OK.
James Gall: And I'll cover those in a minute.
Yao Yin: OK. Thank you.
James Gall: Yep.
Tom Pardee: First question from Steve is shouldn't the IRP start modeling 4.00 to
8:00 PM Summer?
James Gall: We've done that in the past and I think where Steve is going, here is a
chart showing a different instead of on off peak we show a 1/3 segment of time where
different segments in time we could do that. It's not a bad idea. The model doesn't kick
that out right now. We'd have to do it manually, so maybe that's a good one for the
next IRP, but good idea. OK. And then second question from Jason, what is the
revolution in the Mid-C energy price forecast can go to? It is an hourly forecast and we
run 300 simulations of future hydro, load, wind, forced outages. We have 300 hourly
forecasts. And when we look at resources, we take that hourly forecast and look at
how is that resource going to dispatch and then we can match up those dispatch hours
with the hourly forecast.
James Gall: Alright, OK. I think we've covered the energy side of this, or at least the
flat on peak, off peak. Again, the Idaho, apologize, the labels should be flat on off and
it's showing on off flat, so I apologize for that. We'll fix that. I'm going to leave it. Leave
this on the Washington one for this next discussion to avoid the mix up on the previous
slide. But for the energy and capacity portion, this is actually a result of how the
Preferred Resource Strategy compares to other scenarios. So, what we're trying to
look at is the breakdown of how much additional cost our resources are and divide
them in between is it really the energy we need or is it the capacity we need. And what
you're seeing here, in both Idaho and the Washington, is a majority of the benefit you

Appendix A
need is capacity related. We're trying to serve those highest load hours of the year.
We do show a small energy premium as well because we do need energy in our
forecast, but a majority of it is capacity and it's mostly driven by wintertime. We have
a winter peak and a summer peak. You need both. Winter has higher need than
summer, but not much higher. But if you had a resource that only provided you
summer, you would not solve your winter problem and vice versa. When we look at
capacity values for resources, we have to look at when is it providing energy, when it's
needed and what is the driving force of it. That's the advantage in the PRiSM models.
It's trying to find resources that solve both of our winter needs and summer needs, but
this is a breakdown of what it's costing us to serve that capacity. And then we have
broken that out. Think of it is as if you only served your load with market, you would
be paying the pricing that's on the left of the charts. That flat energy price and on off
peak. And if you're going to serve only your energy needs, like, for example, CETA is
an energy need to some extent you pay the energy premium to solve your energy
requirements you have by month. But if you're going to serve your peak needs, you
got to pay that extra cost on the capacity premium.
James Gall: And I thought I saw a comment pop up, but just now observation from
Steve. OK about the differentials in market being driven together. Yeah, I think where
the Mid-C is going, that the price is on off peak is collapsing and solar storage is the
reason for that, and that's been our forecast for a while obviously. It's been a hard pill
to swallow as a forecaster as this future, when the present is much different. But what
mean by that is, we've been forecasting collapsing spreads for a couple IRPs, now
because of storage and solar and until recently we haven't really seen that. We think
there's about 6,000 megawatts of storage in California now. We're starting to see some
pricing effects of that. And then also just amount of solar down there as well. We're
starting to see this future show up. It's been a little slower than we thought, but it's
starting to show up.
James Gall: OK. Any other questions on avoided costs? This is I'd say from last IRP
versus this IRP mostly similar. The big issue is when on the capacity premium,
when we're short, 2030 is what we're showing here for when that capacity period would
start and we've talked about a couple IRPs ago, we have some small deficits, 2026
and 2027, they go away. but our long-term capacity need starts really in 2030 unless
we get a new large load, or we lose a resource. So, that's subject to revision based on
that. But we're doing all the other calculations based on the long-term resource need
is 2030 and the energy premium is zero until 2029. That is, when the first large scale
renewable resource, or I should say an energy resource was selected which is 2029
for Washington, we shifted that to 2030 for Idaho because the resource that was
selected in the IRP in 2029 was a Washington driven resource, so that's shifted to

Appendix A
2030 for the Idaho version. We do similar calculations as this for energy efficiency.
They are different. They're actually a little bit higher because we're looking at a future
without energy efficiency to calculate what it cost for those. Those are going to be in
the document itself. You can read about it in a couple weeks, but again those are a
little, they're a similar methodology, little bit higher pricing, but these are the ones you
see here are more for resource based what it cost. OK, we have about 15 minutes left.
think we're going to be done early, which is the first time in, I think, a very long time
for an IRP TAC meeting for at least the electric side.
James Gall: This is my last slide. This is a kind of a preview of the next TAC meeting.
We're going to go through the scenarios which you see. There are a lot of them, which
is why we are suggesting more time. I think I added them all up yesterday, it was 25
scenarios we're now going to be running. Some of these will have reliability results
and then some will just be resource only, no analysis and then we'll try to get into the
costs and benefits of these. But I've broken the scenarios into 4 categories. The first
one is a methodology category where we're testing different methodologies. An
example of that is alternative lowest reasonable cost. That's a requirement for CETA's
cost cap calculation, which is used for the first four years of the plan. That's kind of a
methodology scenario. We also have a baseline portfolio, which excludes CETA
entirely, it is a methodology portfolio to show where we would otherwise be. We have
different CETA targets and then we have the cost cap scenario. Those are
methodology scenarios. One of the bigger categories we have is load scenarios where
we're testing different load growth, whether it's lower growth or higher growth, different
weather, electrification of buildings and transportation, also data centers. So those will
be all the load growth scenarios. The next category has resource availability, and you
see two of them that are crossed out here and those two were ones that we proposed
in the earlier TAC meetings that we are going to remove because one is on the nuclear
cost sensitivity, we were not expecting nuclear to be selected, so we wanted to see
what price nuclear would be selected. Since it's picked in the strategy, I didn't see any
value including that. The other one I crossed out was the high QCC on demand
response and that was really a test of whether or not we'd see more demand response
if we had higher QCC values. Given the Preferred Resource Strategy has fairly high
QCC values for demand response and it's we'll call it base case, it didn't seem
necessary to run that case.
James Gall: I could cross those two out, but we did add in red some other scenarios
that I thought would be helpful when we go through the resource strategy. One is on
regional transmission. What I mean by that one is the Colstrip to MISO, SPP line we
talked about. We've included that in our Preferred Resource Strategy. I'd like to test
what our PRS would look like without that line, so that's what that one's about.

Appendix A
Northeast, it's been a resource we forecasted to retire in 2030. We wanted to test if
that plant has longer life or shorter life, how does that change the resource strategy
because right now, in 2030 you have we have five years to come up with a solution.
But what if you have less time to come up with a solution? Where you have more time
to come up with a solution? What does that do to our portfolio? Actually, that one to
me is probably of all of these portfolio scenarios on the list, that's to me is the most
important too because that's the one that's a near term decision. A couple more of that
that showed up when we're starting to go through our resource analysis, or the
preferred strategy is limiting. If we had to limit to our amount of wind on system in our
modeling. What I mean by that is we modeled 500 megawatts of wind in our system
that could be interconnected at very low cost. But if another utility, a third-party, or one
of these developers that are developing maybe 500 megawatts of wind. If they sell
that project to another utility, that's less that we can interconnect at a low price. So, if
we don't have access to cheap wind, how does that change our portfolio? That's what
that one's about.
James Gall: Another one we wanted to test is, and this is really a result of the amount
of wind picked in the Preferred Resource Strategy, that it was all picked very early.
The model saying it's cost effective to go into wind early to take advantage of the tax
credits. But I want the test whether or not that resource decision is driven by the tax
credits. Is it driven by need? Is it driven by high market prices? What's causing that?
That early selection of wind, or the amount of wind in this scenario I think will help
show that. That's why we're going to run a case with no sensitives. So, that's the
resource availability. Obviously, the top three that we had in black, there are ones we
proposed before and then other changes we have other portfolios we were going to
run a case that had a lower resource strategy or PRM for can't talk, sorry, planning
reserve margin to represent more of a WRAP scenario. We decided just to make that
a 17% scenario to replicate maybe what the WRAP will go to, because we don't know
exactly where the WRAP's going to end up long term and then we want to run another
scenario that has a 30% PRM to replicate, we're trying to achieve a 0% loss of load
probability or something as close as possible to 0. So those are, that's really to simplify
the modeling. And so those are two that we're working on and then we have the
maximum customer benefit scenario and we're going to be doing a scenario with what
happens if the CCA is repealed. If there are any changes to the strategy if that
happens? We're working on these right now. The goal is to show those at the next
TAC meeting in September, and then we'll also have these written up and described
in the IRP that will come out, I believe October 1st
James Gall: That is all I have today. Any questions, comments, concerns? OK. Well,
let's wrap it up. OK, go ahead. Yes, I think we're done for the day. Go ahead, Steve.

Appendix A
Steve Johnson: I had just one annoying question. Not quite related to the slides
exactly, but I assume that the IRP is not going to discuss the merits of selling off
Avista's distribution system. And I asked this question because there's a neighboring
utility struggling with solvency with regard to their system. And so, is it Avista's view
that they're distribution system has a net positive financial value to them considering
fire risk and short liability?
James Gall: Well, that is definitely a challenging question. I don't know, is Kevin
around or if there's someone above our pay grade that would like to? Yeah.
Steve Johnson: Well, that's OK. I'll just look for it now, IRP or somewhere else. We
don't have to go into that topic here today.
James Gall: Well, you're not going to find that discussion in the IRP probably.
Steve Johnson: Yeah. Well, maybe the ratepayer, the shareholders and the board
will think about that. But there is a question here. I just wanted to bring it up on a
recorded line. Just having fun, thank you very much.
James Gall: Yeah. You're welcome, Steve, maybe we can talk about that offline
someday and opine on a different theoretical possibility.
Steve Johnson: Well, I don't laugh because there is serious risk to people's life and
safety. It's not, you know, but also there's these broad financial results which may or
may not cure the actual problem, which is the risk to the community.
James Gall: Yep.
Steve Johnson: So, we're going to, we're in a sort of dysfunctional relationship. And
I have some concerns about it, but it's not exactly an IRP question, but that does need
to be a question in the public realm somewhere for the utilities with public engagement.
So, we'll find a place. Thanks.
James Gall: Appreciate it. It's definitely a concerning topic, that is, I know on our
board's mind and our executive's minds, but you know, there's a crossroads,
customers obviously need power, but there's these risks. And if the utility has to bear
all of those risks, we may not be able to afford to be a utility or the rates may not be
affordable and we can't get insurance or limited insurance for fire risks. These are
definitely major challenges.

Appendix A
Steve Johnson: Well, and the decision making, the metrics for decision making,
shouldn't be shareholders managing the risks. It should be the public interest and so
we may have a whole set of wrong metrics driving decision making at this point.
It's a little tenuous, but it's a big subject. I didn't mean to rob the meeting, hijack the
meeting, so we'll move on. Thanks.
James Gall: Yep. All right. Well, I don't know if there's any other questions or
comments, so I don't know if you robbed it, but at least you extended it a couple
minutes.
John Lyons: We are starting to see some of the commissions grapple with how do
you take that issue up because we have specific work filed, some made some filings
in the states that are basically raising that question. And usually it was, no, we can't
do it that way. But then I think the commissions are saying, but this is something we
need to take up, look at, and I haven't heard anything like it. I'm sure they're discussing
it, but how do you handle it? State by state? Do you hand it nationally?
James Gall: It is definitely a regional issue for wildfires. But there's going to be
implications across the country for that.
Steve Johnson: Well, I just don't know what it didn't apply some years down the road.
If we have a lot of distributed energy resources on a vulnerable distribution system, I
don't know, it just gets more and more complicated. We'll cross those bridges,
unfortunately, when we get to them, I bet. Thank you so much for your time.
James Gall: You're welcome. Alright. Any other questions or comments? I think we'll
call it a day. We'll see you in September. And I look forward to everybody's feedback
on the draft IRP as it comes out over the next couple of weeks. Thanks again. Have a
great day.

'AdVISTA
2025 IRP TAC 13 Introductions
John Lyons, Ph.D.
Technical Advisory Committee Meeting No. 13
September 17, 2024

Appendix A
Today's Agenda
Introductions, John Lyons
PRS Update and Scenario Analysis, Planning Team
RP Next Steps, James Gall
2 imb

Appendix A
Remaining 2025 Electric IRP TAC Schedule
• Virtual Public Meeting - Electric IRP (November 13, 2024)
o Recorded presentation
o Daytime comment and question session (7:30 am to 8:30 am, PTZ)
https://us02web.zoom.us/i/82646796064?pwd=PeQBOudUk4HQCOai l b516GwK9DawJX. 1
Meeting Topic: Avista Energy Resource Planning
Meeting ID: 826 4679 6064
Passcode: 530027
o Evening comment and question session ( 12:00 pm to 1 :00 pm, PTZ)
htt s://usu2wel).zoom.us/ /69000361941 "�/ wd=oXL9E vvvt u s uuua n pHpeWD 3nV. 1
Meeting Topic: Avista Energy Resource Planning
Meeting ID: 890 0036 1941
Passcode: 302233
3 OEI

Appendix A
Remaining 2025 Electric IRP TAC Document Schedule
. . - Availability
Executive Summary October 1 , 2024
Introduction, Involvement, and Process Changes October 1 , 2024
Preferred Resource Strategy Available
Economic and Load Forecast Available
Existing Supply Resources Available
Resource Needs Assessment Available
• Distributed Energy Resources Options Available
Supply-Side Resource Options Available
Transmission Planning & Distribution Available
Market Analysis October 1 , 2024
Portfolio Scenarios October 1 , 2024
Action Plan Available
4 im

Appendix A
Remaining 2025 Electric IRP TAC Document Schedule
EMM E j Availability
TAC Presentations I RP website
Work Plan I RP website
Draft AEG EE/DR Potential Assessment Available
10-year Transmission/Distribution Plan Available
Transmission Generation Integration Study Available
DER Study Available
Public Input and Results Data October 1 , 2024
Confidential Inputs and Models January 2, 2025
Historical Generation Operation Data (Confidential) January 2, 2025
New Resource Transmission Table January 2, 2025
Washington State Schedule 62 January 2, 2025
Public Comments January 2, 2025
* Original Appendix K — Resource Portfolio Summary moved into Appendix G
5

'AdVISTA
2025 Electric Integrated Resource Plan
PRS Update and Scenario Analysis
James Gall
Technical Advisory Committee Meeting No. 13
September 17, 2024

Appendix A
'AC Meeting
• Line losses were double counted in the energy efficiency analysis .
• Does not affect generation resource portfolio .
• Economic potential in 2045 is 7 . 7% lower.
Energy Efficiency Comparison
1,000
900
800
U) 700
2 600
500
c�a 400
C� 300
200 PRS
100 —TAC Draft
CO fl- CO O O N M It LO CO � 00 O O NCO
N N N N CO M MMMMMMMM �
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 Nib
2

Appendix
Portfolio Risks
Nuclear Availability ortheast CT Availability
Economic Growth
Data Center lean Energy Preferences
Power to Gas Availability
Future Weather
Regional Transmission Building Electrification
CETA Rul
n I
Transportation Electrificatio
Reliability Objectives Cmate 111111111171 111
Commitment Act
Tax Incentives
Distributed Energy Resources
r ✓ISTA'

Appendix A
Scenario Analysis Insights
• Demand response and energy storage are best resources to quickly add
capacity.
• Due to limits on power-to-gas (P2G) resources, nuclear is go to resource for
higher loads in Washington .
— May create cost concerns as nuclear energy is estimated at $144/MWh in 2030 and
$206/MWh in 2045.
• Wind is relied upon for winter capacity contribution .
• Additional wind beyond the PRS is difficult due to transmission limitations,
pushing solar/nuclear to meet clean energy targets if loads increase.
• Natural gas CTs remain the lowest cost resource for Idaho customers; but will
require long lead times and infrastructure development.
4

Appendix A
Portfolio Scenarios
Methodology Load Scenarios Resource Availability
2- Alternative Lowest 5- Low Growth 4- Clean Resource Portfolio by 10- Maximum Washington
Reasonable Cost 2045 Customer Benefit
3- Baseline Least Cost Portfolio 6- High Growth 11- 500 MW Nuclear in 2040 12- 17% PRM
15- Minimal Viable CETA Target 7- 80% Washington Building 14- Power to Gas Unavailable 13- 30% PRM
Electrification by 2045
16- Maximum Viable CETA 8- 80% Washington Building 21- Regional Transmission not 26- PRS w/ CCA repealed
Target Electrification by 2045 & High Available
Transportation Electrification
17- PRS Constrained to the 2% 9- 80% System Building 22- 2026 Northeast CTs
Cost Cap Electrification by 2045 & High Retirement
Transportation Electrification,
No New NG CTs
18- 200 MW Data Center in 23- On-System Wind Limited to
2030 200 MW
19- RCP 8.5 Weather 24- No IRA Tax Incentives
20- 80% System Building 25- 2035 Northeast CTs
Electrification by 2045 & High Retirement
Transportation Electrification
Scenario No New NG CTs with
RCP 8.5 Weather ��Ib
5

Preferred Resource Strategy Appendix A
Nameplate MW 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 Total
Shared System Resource
Mrkt/Trans 39 4 10 0 0 0 0 300 0 0 0 0 0 0 0 0 0 0 0 0 353
Natural Gas 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 -
Solar 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 -
Wind 0 0 0 0 0 100 100 157 0 0 0 0 0 0 0 0 0 0 0 0 357
Storage 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 -
PtoG 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Nuclear 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Geothermal 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Biomass 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 10 10
RNG 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
DR 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Washington
Mrkt/Trans 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Natural Gas 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Solar 0 1 1 1 1 1 1 1 1 1 1 1 1 1 1 181 120 1 311
Wind 0 0 0 200 200 100 0 0 0 0 0 0 0 0 0 140 0 120 108 200 1,068
Storage 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 90 86 85 261
PtoG 0 0 0 0 0 0 0 0 0 0 0 0 0 0 90 0 210 0 0 94 394
Nuclear 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 100 100
Geothermal 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 20 20
Biomass 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 58 58
RNG 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 -
DR 25 0 0 0 0 0 0 0 0 6 0 0 4 20 0 6 0 10 0 0 70
Idaho
Mrkt/Trans 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 -
Natural Gas 0 0 0 0 90 0 0 0 0 0 0 0 0 0 90 0 95 0 0 0 275
Solar 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 -
Wind 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Storage 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
PtoG 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Nuclear 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Geothermal 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Biomass 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
RNG 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
DR 0 0 0 3 0 0 0 0 0 3 0 0 0 0 4 0 0 1 7 0 .A
Year LOLP LOLE LOLH LOLEV EUE EUE without reserves
Reliability Metrics: 2030 0.032 0.072 0.73 0.176 114 107
6 2045 0.033 0.093 1.05 0.304 172 116

►�IVIsra
Methodology Scenarios

Appendix A
2= Alternative Lowest Reasonable Cost
• Purpose: Understand impact of CETA for the 2% cost cap calculation. Used for CEIP analysis
for the first 4 years.
• Assumption Changes: Removes CETA clean energy targets and Named Community
spending assumptions and allows natural gas CTs.
• Results Summary:
— Resource portfolio shows fewer renewable resources acquired, 466 MW less wind, 211 MW less
solar, and 136 MW less energy storage.
— Energy efficiency is slightly lower. Some natural gas is added to Washington and more resources
are selected as system resources.
• Cost/Rate Impacts: Long-term Washington energy rate is 16% lower, although Idaho's is 6%
higher, in the CEIP period PVRR for Washington is $4 million less.
• Resource Adequacy Assessment: Both 2030 and 2045 show lower LOLP results then the
PRS whereas 2045 is 1 .4%; indicating the potential to reduce the PRM and have lower cost.

Appendix A
3= Baseline
• Purpose: Understand cost impact of CETA going forward, assists in determining avoided
costs.
• Assumption Changes: Removes CETA targets, NCIF spending minimum, SCGHG, NEI ,
allows natural gas in Washington in 2045. Energy efficiency is not changed.
• Results Summary:
— Renewable generation greatly reduced, but 700 MW of early wind acquisition for both states remains.
— All capacity resource needs are moved to Natural Gas CTs (+700 MW), Energy Efficiency changes were not
modeled. Only portfolio with higher emissions in 2045 than 2026.
• Cost/Rate Impacts: Long-term Washington energy rate is 17% lower, although Idaho's is
2% higher (PVRR is lower for Idaho than PRS).
• Resource Adequacy Assessment: Pending, but expectations are system will be less than
5% LOLP and may allow for lower PRM.
9

Appendix A
15= Minimal Viable CETA Targets
• Purpose: Supports CEIP Condition 33 "Avista agrees to model a scenario in the 2025
Electric IRP meeting the minimum level of primary compliance requirements beginning in
2030 that will create the glide path to 2045. If the results of this modeling differ from the
Company's PRS and Clean Energy Action Plan, it must explain why."
• Assumption Changes: Uses CETA Targets:
2026 2027 2028 2029 2030-2033 2034-2037 2038-2041 2042-2044 2045
#15 Primary 62.5% 62.5% 62.5% 62.5% 80.0% 82.0% 88.0% 92.0% 100.0%
#15 Alternative 20.0% 18.0% 12.0%1 8.0% 0.0%
PRS I Primary 1 66.0%1 69.5%1 73.0%1 76.5%1 80.0%1 85.0%1 90.0%1 95.0%1 100.0%
PRS JAIternative 1 20.0%1 15.0%1 10.0%1 5.0%1 0.0%
• Results Summary:
— No material change due to same goals in 2030 and 2045, results will be more impactful in the CEIP
analysis for greater REC sales.
— Further, without natural gas CTs as a long-term option, resource selection is limited to clean energy.
• Cost/Rate Impacts: No impact.
• Resource Adequacy Assessment: not studied due to same result as PRS.
10 iEh

Appendix A
16= Maximum Viable CET *X Targets
• Purpose: Supports CEIP process to estimate resource portfolio changes to support CEIP.
• Assumption Changes: Uses CETA Targets:
2026 2027 2028 2029 2030-2033 2034-2037 2038-2041 2042-2044 2045
#16 Primary 70.0% 73.0% 75.0%1 78.0% 81.8% 86.8% 92.2% 97.1% 100.0%
#16 Alternative 1 18.2% 13.2% 7.8% 2.9% 0.0%
PRS I P ri m a ry 1 66.0%1 69.5%1 73.0%1 76.5%1 80.0%1 85.0%1 90.0%1 95.0% 100.0%
PRS JAIternative I I I 1 1 20.0%1 15.0%1 10.0%1 5.0% 0.0%
• Results Summary:
— No material change due to same goals in 2030 and 2045, results will be more impactful in the CEIP
analysis for lower REC sales.
• Cost/Rate Impacts: No impact
• Resource Adequacy Assessment: Not studied due to same result as PRS.
11

Appendix A
17= PRS Constrained to the 2% Cost r - -
• Purpose: Due to uncertainty of cost cap calculation for 2045 and the 2045 PRS rate
increase projection, this scenario offers up a lower 2045 rate impact replicating a potential
cost cap.
• Assumption Change: PRS between 2026-2043 is unchanged, but the model solves for
revenue requirement cap in 2045 (Alternative Lowest Reasonable Cost). The cap is limited
to 8% (2045 Revenue Requirement of scenario without retiring Coyote Springs 2 x 2% x 4)
• Results Summary:
— Coyote Springs 2 remains on the system as a shared resource (with 30% hydrogen). Requires
Idaho to offset generation remaining for Washington.
— Washington resources in 2044/45 shift to use less wind, nuclear, biomass, and energy storage, but
more solar and P2G.
• Cost/Rate Impacts: Washington 2045 rates are 9% less, Idaho's rates increase 3.5%.
• Resource Adequacy Assessment: not studied, but resource selection does not indicate a
risk.
12 P&

Appendix A
►irV§sra
Load Scenarios

Appendix A
.ow Load Growth
• Purpose: Understand resource selection impact if loads take lower trajectory.
• Assumption Change: Uses lower load growth forecast (0.34% per year vs. 0.85%)
• Results Summary:
— No resource changes as compared to PRS until 2033.
— Long term less wind (93 MW), 162 MW less solar, 100 MW less nuclear, and 10 MW less demand
response.
• Cost/Rate Impacts: 2030 rates are slightly higher due to less load to spread fixed costs, but
long-term rates are slightly lower then the PRS.
• Resource Adequacy Assessment: Not studied.
14

Appendix A
a h Load Growth
• Purpose: Understand resource selection impact if loads take higher trajectory
• Assumption Change: Uses higher load growth forecast (1 .75% per year vs. 0.85%)
• Results Summary:
— Short-term- increase demand response and acquire wind earlier.
— Long-term for Washington, acquire additional demand response, solar, and nuclear to meet load
growth.
— Long-term for Idaho acquire more natural gas CTs.
• Cost/Rate Impacts: 2030 rates are slightly lower due to less load to spread fixed costs, but
long-term rates are higher than the PRS (WA +6%) and (ID: -7%).
• Resource Adequacy Assessment: Not studied.
15

Appendix A
7= 80% Washington Building Electrification by 2045
• Purpose: Understand resource selection and cost impact if 80% of 2026 natural gas demand
moves to electric service.
• Assumption Change: Natural gas LDC load converts to electric demand and assumes 75%
former natural gas load becomes Avista electric load. Results in an additional 356 MW of peak
load by 2045 and 107 aMW of energy.
• Results Summary:
— Biggest impact is a reduction to system resources and these resources (357 MW wind) are allocated to
Washington.
— Idaho requires 20 MW more natural gas in the 2040s.
— Washington needs 240 MW more solar, 276 MW of energy storage, and 141 MW more nuclear.
• Cost/Rate Impacts: Idaho's 2045 rate impact is 2% higher, but Washington's 2045 rate is 12%
higher. When taking into account reduction in the natural gas costs of the LDC, customers
overall pay 25% more between 2043-2045 when conversion cost are considered.
• Resource Adequacy Assessment: Not studied.
16 imb

Appendix A
8= 80% Washington Building Electrification by 2045 &
High Transportation Electrification
• Purpose: Understand resource selection and cost impact if 80% of 2026 natural gas
demand is moved to electric service and higher electric transportation trajectory occurs.
• Assumption Change: Uses same electrification forecast as scenario 7, plus the high
transportation load scenario (+127 MW winter peak, 76 aMW energy).
• Results Summary:
— Biggest impact is a reduction to system resources and these resources (357 MW wind) are
allocated to Washington.
— Idaho then requires 14 MW more natural gas in the 2040s plus a share of a Kettle Falls upgrade. In
addition to the wind/biomass allocation.
— Washington will need 240 MW more solar and 375 MW of energy storage and 222 MW more
nuclear.
• Cost/Rate Impacts: Idaho's 2045 rate impact is 2.5% higher, but Washington's 2045 rate is
11 % higher. When taking into account reduction in the natural gas costs of the LDC,
customers overall pay 33% more between 2043-2045 when conversion cost are considered.
• Resource Adequacy Assessment: Not studied.
17

9= 80% System Building Electrification by 2045 & Hi —A,e"dix A
Transportation Electrification , No New NG CTs
• Purpose: Simulates highest load possible. Similar to scenario #8, but Idaho building and transportation
loads are electrified.
• Assumption Changes: Disables new natural gas generation, uses scenario #8 loads for Washington.
For Idaho assumes 90% reduction in 2045 natural gas load. Idaho Building Electrification adds 394
MW winter peak load (115 aMW) by 2045. The high transportation scenario adds 126 MW winter peak
(104 aMW) by 2045.
• Results Summary:
— Resource allocation is better aligned between states as each state has similar objectives, including +96 MW of
winter peak reducing energy efficiency.
— New natural gas is removed (-275 MW) and 200 MW less wind.
— Adds +800 MW of solar, +877 MW of energy storage, +726 MW nuclear to the PRS.
• Cost/Rate Impacts: Idaho's 2045 rate impact is 36% higher, but Washington's 2045 rate is 25%
higher. When taking into account reduction in the natural gas costs of the LDC, customers overall pay
63% more between 2043-2045 when conversion cost are considered.
• Resource Adequacy Assessment: 2045 is well below 5% threshold, potential for lower PRM study
Reliability Metrics: Year LOLP LOLE LOLH LOLEV EUE EUE without reserves
2045 0.011 0.035 0.348 0.122 56 1
18 "ft

Appendix A
Electrification Cost Summary
� $5,000
0
$4,500
$4,000
�
$3,500
N $3,000 _
$2,500
$2,000
o $1 ,500
U $1 ,000
Q $500
$0 8-WA Building 9- Building 20- Building
erred 7-WA
cation & High
Resource Strategy Electrificationg Electrification & High Trans.Electrification
s Electrification Trans.
ElectrificationTrans. Electrification w/o NG w/o NG w/RCP 8.5
Other Utility Cost Impacts $0 $37 $34 $46 $46
NG Site Conversion Cost $0 $118 $118 $233 $233
Natural Gas Idaho $172 $175 $174 $118 $118
■Natural Gas Washington $369 $332 $331 $333 $333
■Electric Idaho $626 $639 $639 $1,283 $1,183
■Electric Washington $1,636 $2,012 $2,184 $2,558 $2,588
Total $2,803 $3,313 $3,480 $4,570 $4,501
2041-45 Electric/Natural Gas GHG (WA/ID) 1.94 mmt 1.78 mmt 1.77 mmt 1.16 mmt 1.04 mmt
9 2026-30 Electric/Natural Gas GHG (WA/ID) 2.93 mmt

Appendix A
Greenhouse Gas Emission Savings
3.5
• Includes both Electric
3.0 and Natural Gas LDC
2.5 • Washington and Idaho
y
0
Only
'
• Does not include
E 2.0
y transportation
0
0 1.5 emissions
v
• Incremental Cost for #7
1.0 -1- Preferred Resource Strategy is $828/metric ton
-7- WA Building Electrification levelized
0.5
-9- Building Electrification & High Trans. Electrification w/o NG
C4 I1- 00 O O r N CO LO O r- 00 O O N CO "t
N N N N co co M co M co M M co co It It IT It
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

Appendix A
CP 8 , 5 Weather
• Purpose: Understand impact of warmer winters to the resource strategy.
• Assumption Change: Uses RCP 8.5 future temperatures instead of RCP 4.5 for winter
seasons for energy and peak weather normalization.
• Results Summary:
— Reduces need for winter peaking generation.
— Resources no longer needed by 2045 include: natural gas CT (-46 MW) and biomass (-58 MW),
but more energy storage (+64 MW) is selected, there is also a shift in system allocated generation
for P2G projects and wind and small nuclear increases.
• Cost/Rate Impacts: Minimal change to rates and slightly less PVRR (-0.2%).
• Resource Adequacy Assessment: A future with no cold winters indicate the PRM could be
reduced
Reliability Metrics: Year LOLP LOLE LOLH LOLEV EUE EUE without reserves
2045 0.006 0.007 0.030 0.009 2 0
21 imb

20- 80% System Building Electrification by 2045 & Hig1h
Transportation Electrification , No New NG CTs, w/ RCP
8 , 5 Weather
• Purpose: Evaluates highest load obligation with warmer winter weather forecast.
• Assumption Change: Combines scenarios 9 and 18.
• Results Summary:
— Comparing to scenario #9: +3 MW solar, +46 MW wind, -49 MW energy storage, -46 MW nuclear,
and +7 MW demand response.
• Cost/Rate Impacts: Idaho's 2045 rate impact is 26% higher, but Washington's 2045 rate is
28% higher then PRS. When taking into account reduction in the natural gas costs of the
LDC, customers overall pay 60% more between 2043-2045 when conversion cost are
considered.
• Resource Adequacy Assessment: Not studied.
22 imb

Appendix A
18- 200 MW Data Center in 2030
• Purpose: Understand implications of large data center in Washington.
• Assumption Change: Adds 200 MW of load to Washington in 2030, assumes PT ratio
allocates more existing resources to Washington.
• Results Summary:
— With PT ratio impact, 90 MW of additional natural gas is required due to lost capacity for Idaho.
— For Washington, short-term impacts include faster acquisition of wind, demand response, and P2G
projects. In the long-run +321 MW Solar, +67 MW P2G, and +97 MW nuclear.
• Cost/Rate Impacts: Idaho 2045 rate: +3.7%, Washington 2045 rate: -4.2%.
• Resource Adequacy Assessment: 2030 study pending.
23 i lb

►�IVIsra
Resource Availability Scenarios

Appendix A
4= Clean Resource Portfolio by 2045
• Purpose: Determine resource selection and cost impacts of not adding natural gas
resources and removing all gas generation by 2045.
• Assumption Change: No natural gas as an option and retires Coyote Springs 2 in 2044.
• Results Summary:
— Significant portfolio changes. Resources are selected closer to a system basis.
— Short-run: more wind, energy efficiency, demand response, and energy storage for Idaho and less
natural gas.
— Long-run: nuclear (+384 MW) replaces natural gas, but more wind (+130 MW), solar (+62 MW),
demand response (+58 MW), energy efficiency (+14 MW), and energy storage (+93 MW) is
needed. Only reduction in resources is P2G (-94 MW).
• Cost/Rate Impacts: Both states show higher cost, Washington 2045 rates are 17% higher
and Idaho 55% higher.
• Resource Adequacy Assessment: 2030 study requires higher planning margin to be
resource adequate with 24%, planning margin LOLP is 6%, but 2045 resources are
adequate with the PRS's PRM at 1 .7% LOLP.
Reliability Metrics: Year LOLP LOLE LOLH LOLEV EUE EUE without reserves
2030 0.06 0.194 2.117 0.435 359 339
25 2045 0.017 0.025 0.144 0.051 18 16 #as

Appendix A
11 - 500 MW Nuclear by 2040
• Purpose: Understand resource impact of large nuclear facility in 2040.
• Assumption Change: 500 MW nuclear forced into model in 2040 as a system resource,
does not retire any resources (such as Coyote Springs 2).
• Results Summary:
— Removes 185 MW of new natural gas for Idaho and increases system wind and P2G resources.
— Significant reductions in system resources (mostly Washington): wind (-606 MW), solar (-300 MW),
energy storage (-200 MW), biomass (-58 MW), and demand response (-15 MW).
• Cost/Rate Impacts: Idaho 2045 rate: +30%, Washington 2045 rate: +9%.
• Resource Adequacy Assessment: Near 0% LOLP due to resource length.
Reliability Metrics: Year LOLP LOLE LOLH LOLEV EUE EUE without reserves
2045 0.006 0.007 0.03 0.009 2.1 0
26

Appendix A
14- Power to Gas Unavailable
• Purpose: Understand impacts if hydrogen and ammonia are not available as a fuel.
• Assumption Change: Disable ammonia and hydrogen resource options.
• Results Summary:
— Reduces shared wind resources and increases Idaho's need for natural gas by 72 MW.
— Washington's resource needs change by losing 394 MW of P2G and replaces it with 288 MW of
energy storage, 122 MW of nuclear and small changes to wind, solar, and demand response.
• Cost/Rate Impacts: Idaho 2045 rate: +4%, Washington 2045 rate: +11 %.
• Resource Adequacy Assessment: LOLP near target level
Reliability Metrics: Year LOLP LOLE LOLH LOLEV EUE EUE without reserves
2045 0.04 0.137 1 .641 0.375 324 323
27 imb

Appendix A
21 = Regional Transmission not Available
• Purpose: Removes the 300 MW regional transmission. The scenario helps understand
resource portfolio impacts rather than cost impacts due to arbitrage benefits not include in
the PRS.
• Assumption Change: Removes the 300 MW transmission and associated market
availability.
• Results Summary:
— 113 MW of additional system wind- taken from Washington.
— Idaho requires more natural gas (+25 MW) and energy storage (+25 MW).
— Washington requires 141 MW of energy storage, nuclear (+10 MW), solar (+9 MW), demand
response (-15 MW).
• Cost/Rate Impacts: N/A.
• Resource Adequacy Assessment: Not studied.
own
28

Appendix A
24= No IRA Tax Incentives
• Purpose: Useful in determining if IRA is responsible for the early wind acquisition in the PRS
and determines portfolio/cost impacts if the IRA is repealed.
• Assumption Change: Changes resource costs to reflect IRA expiration in 2026.
• Results Summary:
— No system wind resource (-357 MW), results in 13 MW more natural gas for Idaho in 2030.
— Washington acquires 262 MW more wind and 36 MW more energy storage and Kettle Falls Unit 2
is removed, small increases to solar and demand response.
• Cost/Rate Impacts: Idaho rates are 0.5% higher and Washington rates are 2.7% higher.
• Resource Adequacy Assessment: Not studied.
29 imb

Appendix A
23= On -System Wind Limited to 200 MW
• Purpose: Understand resource portfolio changes if wind connected to Avista's transmission
system is wheeled off system rather than to serve Avista customer load.
• Assumption Change: Limits on-system wind to 200 MW without building large transmission
infrastructure.
• Results Summary:
— System wind is 357 MW lower, results in 13 MW more natural gas for Idaho in 2030.
— Washington's wind is 261 MW lower, energy storage is 53 MW lower and nuclear is 54 MW higher
• Cost/Rate Impacts: Idaho rates are 0.5% higher and Washington rates are 3.3% higher.
• Resource Adequacy Assessment: Not studied.
30 imb

Appendix A
22= Northeast CT- Retire in 2026
• Purpose: Determine resource portfolio change without Northeast CTs available.
• Assumption Change: Disable Northeast CTs.
• Results Summary:
— Immediate need for 79 MW energy storage as a system resource and 100 MW system wind earlier.
— Idaho portfolio needs 32 MW less natural gas, +31 MW more energy storage as (2030 NG CT is
gone), also more system allocated wind.
— Washington's allocated wind falls by 208 MW and needs 40 MW less energy storage, but 22 MW
more nuclear.
• Cost/Rate Impacts: 1 % rate impact for Idaho in 2030, no rate impact for Washington. 2045
rate impacts are 0.4% for Idaho and 0.8% for Washington. System PVRR is 0.6% higher
• Resource Adequacy Assessment: Not studied.
31

Appendix A
25= Northeast CT- Retire in 2035
• Purpose: Determine resource portfolio change with Northeast CTs extended 5 years.
• Assumption Change: Disable Northeast CTs in 2035.
• Results Summary:
— Defers need to build Idaho's new natural gas CT, in its place is 36 MW of energy storage between
2030 and 2032 and total natural gas CT need is 21 MW less.
— System wind is moved earlier in time.
• Cost/Rate Impacts: No early year rate impact, but Idaho's 2045 rates are 0.7% higher, but
system PVRR is slightly lower then PRS.
• Resource Adequacy Assessment: Not studied.
32 imb

►����sra
"Other" Scenarios

Appendix A
10= Maximum Washington Customer Benefits
• Purpose: Washington IRP rules require a scenario intended to maximize customer benefit indicators.
• Assumption Change:
— DERs: Solar (164 MW) and 38 MW of energy storage.
— No new air emitting resources are allowed in Washington (i.e., no P2G CT or biomass).
— No out of system resource can serve Washington loads (except up to 200 MW of shared Montana wind).
— Increase energy efficiency credit from 10% to 20%.
— Includes more solar and EV load from DER potential study with higher penetrations in Named Communities
— Regional transmission line remains.
• Results Summary:
— Washington selection increases: solar (+284 MW), energy storage (+337 MW), nuclear (+189 MW),
demand response (+50 MW), and energy efficiency (+5 MW)
— Washington selection decreases: wind (-145 MW), biomass (-64 MW), geothermal (-20 MW), power to gas
(-394 MW)
• Cost/Rate Impacts: 12.7% higher rates in 2045.
• Resource Adequacy Assessment: Not studied.
34 imb

Appendix A
Customer Benefit Indicator Comparison (2045)
Customer Benefit Indicator Measurement PRS Max Change
Customer
Benefits-
#2a: WA Customers with Excess Energy Burden Customers 59,696 59,143 (553)
#2b: Percent of WA Customers with Excess Energy Burden % Customers 21.2% 21.0% -0.2%
#2c: Average Excess Energy Burden $ 1,998.3 1,801.6 (196.7)
#5a: Total MWh of DER <5MW in Named Communities MWh 185,973 574,875 388,902
#5b: Total MWh Capability of DER Storage <5MW in Named Communities MW 2.4 306.4 304.0
#6: Approximate Low Income/Named Community Investment and Benefits Annual Investment ($mill) 6.5 68.8 62.2
#6: Approximate Low Income/Named Community Investment and Benefits Annual Utility Benefits ($mill) 21.6 37.0 15.4
#6: Approximate Low Income/Named Community Investment and Benefits Annual NEI Benefits ($mill) 38.4 35.5 (3.0)
#7: Energy Availability- Reserve Margin Winter % 20.0% 19.9% -0.1%
#7: Energy Availability- Reserve Margin Summer % 25.1% 28.2% 3.1%
#8: Generation in WA and/or Connected Transmission System % of Generation 82.0% 83.7% 1.7%
#9a: SO2 Metric Tonnes - - -
#9b: NOx Metric Tonnes 0.0 0.0 (0.0)
#9c: Mercury Metric Tonnes 407.5 148.4 (259.1)
#9d: VOC Metric Tonnes 26.9 9.2 (17.6)
#10a: Greenhouse Gas Emissions Direct Emissions (metric tonnes) - - -
#10a: Greenhouse Gas Emissions Net Emissions (metric tonnes) (0.2) (0.2) (0.0)
#10b: Regional Greenhouse Gas Emissions Metric Tonnes 8.8 8.8 (0.0)
35

Appendix A
12= 17% PRM
• Purpose: Illustrates resource portfolio relying on increased market for resource adequacy.
Resembles potential future where the WRAP enables utilities to plan for fewer resources.
• Assumption Change: Adjusts winter PRM from 24% to 17%, summer remains at 16%.
• Results Summary:
— Near term changes: Exchanges Idaho's 90 MW 2030 CT for 105 MW solar and selects system
wind resources earlier (2030).
— Idaho: Natural gas (-62 MW) and solar (+105 MW).
— Washington: Solar (-101 MW), energy storage (-131 MW), and other resources such as wind,
nuclear, demand response have small changes.
• Cost/Rate Impacts: Washington has 1 .7% lower rates in 2045, Idaho's rates 0.2% lower.
Overall PVRR is $69 million less (0.4%).
• Resource Adequacy Assessment: Close to 0.05 LOLP Target, and over 0. 1 LOLE Target
Reliability Metrics: Year LOLP LOLE LOLH LOLEV) EUE with reserves EUE without reserves
2030 0.045 0.127 1.394 0.293 232 221
2045 0.047 0.103 0.855 0.26 149 145
36 tift

Appendix A
13= 30% PRM
• Purpose: Illustrates resource portfolio relying less on market resources for resource
adequacy. Resembles potential future where LOLP should be near zero.
• Assumption Change: Adjusts winter PRM from 30% to 17%, summer remains at 16%.
• Results Summary:
— Near term changes: Adds 100 MW of system wind in 2027 and 87 MW of Washington energy
storage in 2026.
— Idaho: Natural gas (+25 MW) and energy storage (+25 MW).
— Washington: Energy storage (+157 MW) and demand response (+3 MW).
• Cost/Rate Impacts: Washington has 1 .4% higher rates in 2030 and 1 .7% higher in 2045;
Idaho's rates increase by 0.2% in 2030 and 1 .5% in 2045. Overall PVRR is $183 million
higher (+1 .2%).
• Resource Adequacy Assessment:
Reliability Metrics: Year LOLP LOLE LOLH LOLEV) EUE with reserves EUE without reserves
2030 0.016 0.034 0.46 0.115 81 80
2045 0.008 0.017 0.148 0.035 18 17
37 i lb

Appendix A
26= PRS w/CCA Repealed
• Purpose: Understand impact to PRS if CCA is repealed in November 2024 election.
• Assumption Change: removes CCA from market price forecast, results in lower wholesale
price forecast.
• Results Summary:
— Near term changes: The first wind acquisition moves from 2029 to 2030, and Idaho's 2030 CT
reduces to 46 MW.
— Idaho: Total natural gas CTs unchanged as 2030 need is shifted to later load growth, and less
system wind is selected.
— Washington: Renewable need mostly unaffected due to CETA, but solar (+8 MW), energy storage
(+27 MW), nuclear (+34 MW), biomass (-58 MW), and demand response (+3 MW).
• Cost/Rate Impacts: Undetermined. Lower wholesale prices reduce market sales and
increase customer cost, but future allowance distribution methodology could impact the
customer cost.
• Resource Adequacy Assessment: Not studied.
38 01b

►�IVIsra
All Scenario Comparisons

Appendix A
Portfolio Cost Comparison
Scenario WA- PVRR ID-PVRR($ TOTAL WA 2030 WA 2045 ID 2030 ID 2045
($ Mill) Mill) PVRR ($ Rate Rate Rate Rate
Mill) ($/kWh) ($/kWh) ($/kWh) ($/kWh)
1- Preferred Resource Strategy 10,924 0 4,758 — 15,682 0.130 0 0.248 0.112 0.180
2-Alternative Lowest Reasonable Cost Portfolio 0 10,796= 4,766 m 15,562 0 0.130 w 0.208— 0.112 a 0.189
3- Baseline Portfolio 10,851 = 4,655= 15,506 m 0.131 w 0.205— 0.111 0.185
4- Clean Resource Portfolio 11,135= 4,873 = 16,007= 0.131 AL. 0.289— 0.112.1 0.280
5- Low Economic Growth Loads 10,641 = 4,711 = 15,352= 0.131 0 0.242 , 0.112 0.189
6- High Economic Growth Loads 11,494 4,964 AL 16,458= 0.128,& 0.262 0 0.109,w 0.167
7-WA Building Electrification AL 11,825 4,793 AL 16,617= 0.131 a. 0.278 0.112 0.184
8-WA Building Electrification & High Trans. Electrification AL 12,374 4,791 AL 17,165= 0.130,& 0.276 0.112 0.185
9- Building Electrification & High Trans. Electrification w/o NG AL 13,295 a 6,195 AL 19,490= 0.131 & 0.310 0.111 a 0.245
10- Maximum WA Customer Benefits 11,188— 4,767 — 15,956 m 0.130& 0.279 0.112— 0.180
11- Least Cost + 500 MW Nuclear in 2040 11,697 a 5,124 .& 16,822= 0.131 & 0.270 0.111 & 0.234
12- 17% PRM 10,880= 4,734 = 15,614= 0.130= 0.244 0.112= 0.180
13- 30% PRM 11,083= 4,781 = 15,864= 0.132= 0.252 0.112= 0.183
14- Power to Gas Unavailable 11,020= 4,772 = 15,792= 0.130 0 0.275 0.112 0.188
15- Minimal Viable CETA Target 10,923= 4,758= 15,681 = 0.130 0.248 0.112 0.180
16- Maximum Viable CETA Target 10,923= 4,758= 15,681 = 0.130 0.248 0.112 0.180
17- PRS Constrained to 2% Cost Cap 10,867= 4,767 = 15,634= 0.130 0.225 0.112 AL 0.187
18- Data Center in 2030 AL 11,794= 4,871 & 16,666= 0.131 0.237 0.112 Ak 0.187
19- RCP 8.5 Weather 10,907= 4,752 — 15,659= 0.132 0 0.248 0.113 a 0.182
20- Building Electrification & High Trans. Electrification w/o NG w/ R o 13,342 5,941 AL 19,283= 0.132 0.317 0.112 AL 0.228
21- Regional Transmission not available 10,902 4,717 = 15,620= 0.130 0.250 0.112= 0.181
22- Northeast Retires Early 10,993 4,775= 15,768= 0.131 0.250— 0.113= 0.181
23- On-system wind limited to 200 MW 11,030 4,781 = 15,811 = 0.131 0.256= 0.112= 0.181
24- No IRA Tax Incentives AL 11,266= 4,754 = 16,019= 0.131 0 0.255 0 0.112= 0.181
40 25- Northeast Retires Late o 10,922= 4,758 0 15,680 0 0.1301 0.248 0.112= 0.182

Appendix A
Washington 2030 and 2045 Average Energy Rates
3-Baseline Portfolio 0.131 1 0.205
2-Alternative Lowest Reasonable Cost Portfolio 0.130 0.208
17-PRS Constrained to 2%Cost Cap 0.130 0.225
18-Data Center in 2030 0.131 0.237
5-Low Economic Growth Loads 0.131 0.242
12- 17% PRM 0.130 0.244
19-RCP 8.5 Weather 0.132 0.248
1-Preferred Resource Strategy 0.130 0.248
25- Northeast Retires Late 0.130 0.248
16-Maximum Viable CETA Target 0.130 0.248
15- Minimal Viable CETA Target 0.130 0.248
22-Northeast Retires Early 0.131 0.250
21- Regional Transmission not available 0.130 0.250
13-30% PRM 0.252
24- No IRA Tax Incentives 0.131 0.255
23-On-system wind limited to 200 MW 0.131 0.256
6-High Economic Growth Loads 0.1280.262
11-Least Cost+500 MW Nuclear in 2040 0.131 0.270
14-Power to Gas Unavailable 0.130 1 0.275
8-WA Building Electrification & High Trans. Electrification 0.130 0.276
7-WA Building Electrification 0.131 1 0.278
10- Maximum WA Customer Benefits 0.130 M 0.279
4-Clean Resource Portfolio 0.131 0.289
9- Building Electrification&High Trans. Electrification w/o NG 0.1310.310
20-Building Electrification & High Trans. Electrification w/o NG w/RCP 8.5 0,132 0.317
$0.00 $0.05 $0.10 $0.15 $0.20 $0.25 $0.30 $0.35 $0.40
■WA 2045 Rate ($/kWh) ■WA 2030 Rate($/kWh)
41

Appendix A
Idaho 2030 and 2045 Average Energy Rates
6- High Economic Growth Loads 0.167
12- 17% PRM 0.180
10-Maximum WA Customer Benefits 0.180
1- Preferred Resource Strategy 0.180
15-Minimal Viable CETA Target 0.180
16-Maximum Viable CETA Target 0.180
21-Regional Transmission not available 0.181
22-Northeast Retires Early 113 0.181
24-No IRA Tax Incentives 0.181
23-On-system wind limited to 200 MW 0.181
25-Northeast Retires Late 0.182
19- RCP 8.5 Weather 113 0.182
13-30% PRM 0.183
7-WA Building Electrification 0.184
3-Baseline Portfolio 0.185
8-WA Building Electrification&High Trans. Electrification 0.185
17- PRS Constrained to 2%Cost Cap 0.187
18-Data Center in 2030 0.187
14- Power to Gas Unavailable 0.188
5-Low Economic Growth Loads 0.189
2-Alternative Lowest Reasonable Cost Portfolio 0.189
20-Building Electrification &High Trans. Electrification w/o NG w/RCP 8.5 12 0.228
11-Least Cost+500 MW Nuclear in 2040 1.111 0.234
9-Building Electrification&High Trans. Electrification w/o NG 0.245
4-Clean Resource Portfolio 0.280
$0.00 $0.05 $0.10 $0.15 $0.20 $0.25 $0.30 $0.35 $0.40
■ID 2045 Rate($/kWh) ■ID 2030 Rate($/kWh)
42

Appendix A
Cost ( PVRR) vs . Risk (2045 Tail Var)
$180
3-Baseline Portfolio
$160
6-High Economic Growth Loe-WMA Building Electrification&High
14-Power to Gas Unavailable Trans.Electrification
$140
2-Alternative Lowest Reasonable Cost 7-WA Building Electrification
Portfolio
21-Regional Transmission not
$120 available 18-Data Center in 2030
12-17%PRM
$100 9-Building Electrification&High Trans.
> 24-No IRA Tax Incentives Electrification w/o NG
M 17-PRS Constrained to 2%Cost Cap
� 23-On-system wind limited to 200 MW
LO $80 10-Maximum WA Customer Benefits
p 13-30%PRM
N 15-Minimal Viable CETA Target
$60
5-Low Economic Growth Loads 20-Building Electrification&High
Trans.Electrification w/o NG w/RCP
8.5
$40 1-Preferred Resource 22-Northeast Retires Earl
Strategy
4-Clean Resource Portfolio 11-Least Cost+500 MW Nuclear in
$20 19-RCP 8.5 Weather 2040
16-Maximum Viable CETA Target 25-Northeast Retires Late
$0
$900 $1,000 $1,100 $1,200 $1,300 $1,400 $1,500 $1,600 $1,700 $1,800
Levelized Revenue Requirement Millions
43 PEN

Appendix A
Present Value of Revenue Requirement (2026=206....
5-Low Economic Growth Loads $10,641 f $4,711 $15,352
3-Baseline Portfolio $10,851 $4,655 1 $15,506
2-Alternative Lowest Reasonable Cost Portfolio $10,796 $4,766 $15,562
12- 17% PRM $10,880 $4,734 $15,614
21-Regional Transmission not available $10,902 $4,717 $15,620
17- PRS Constrained to 2% Cost Cap $10,867 $4,767 $15,634
19- RCP 8.5 Weather $10,907 $4,752 $15,659
25-Northeast Retires Late $10,922 $4,758 $15,680
16-Maximum Viable CETA Target $10,923 $4,758 $15,681
15-Minimal Viable CETA Target $10,923 $4,758 $15,681
1- Preferred Resource Strategy $10,924 $4,758 $15,682
22- Northeast Retires Early $10,993 $4,775 $15,768
14-Power to Gas Unavailable $11,020 $4,772 $15,792
23-On-system wind limited to 200 MW $11,030 $4,781 $15,811
13-30% PRM $11,083 $4,78� $15,864
10-Maximum WA Customer Benefits $11,188 $15,956
4-Clean Resource Portfolio $11,135 $4,873 $16,007
24-No IRA Tax Incentives $11,266 $4,754 $16,019
6- High Economic Growth Loads $11,494 $4,964 $16,458
7-WA Building Electrification $11,825 $4,793 $16,617
18-Data Center in 2030 $11,794 $4,87� $16,666
11- Least Cost+500 MW Nuclear in 2040 $11,697 $16,822
8-WA Building Electrification& High Trans. Electrification $12,374 $17,165
20- Building Electrification & High Trans. Electrification w/o NG w/RCP 8.5 $13,342 19, 83
9-Building Electrification& High Trans. Electrification w/o NG $13,295 $6,1 9, 90
0 0 0 0 0 0 0 0 0 0 0
69 o 0 0 0 0 0 0 0 0 0
0 0 0 0 0 0 0 0 0 0
(V (.O 00 O N (0 00 O
Efl d3 ER Efl EA Efl (A (A EA 613
WA- PVRR($ Mill) ■ID-PVRR($ Mill) TOTAL PVRR($ Mill)
44

Appendix A
Risk Adjusted PVRR
5- Low Economic Growth Loads 46$1,360
3- Baseline Portfolio 53$1,380
2-Alternative Lowest Reasonable Cost Portfolio 50$1,381
12- 17% PRM 46$1,382
21- Regional Transmission not available 47$1,383
17- PRS Constrained to 2% Cost Cap 148$1,386
19- RCP 8.5 Weather '148$1,387
25- Northeast Retires Late $47$1,388
1- Preferred Resource Strategy $48$1,389
16- Maximum Viable CETA Target $48$1,390
15- Minimal Viable CETA Target 48$1,390
22- Northeast Retires Early 43$1,392
14- Power to Gas Unavailable 48$1,400
13-30% PRM 46$1,403
23-On-system wind limited to 200 MW 52$1,405
4-Clean Resource Portfolio 38$1,407
10- Maximum WA Customer Benefits 47$1,412
24- No IRA Tax Incentives 60$1,431
6- High Economic Growth Loads 56$1,464
7-WA Building Electrification 51 $1,473
11- Least Cost+ 500 MW Nuclear in 2040 41$1,480
18- Data Center in 2030 58$1,484
8-WA Building Electrification & High Trans. Electrification 51 $1,520
20- Building Electrification & High Trans. Electrification w/o NG w/... 37$1,687
9- Building Electrification & High Trans. Electrification w/o NG 37$1,705
500 1,000 1,500 2,000
45 ■System Levelized PVRR ($ Mill) Levelized Tail Risk($ Mill) Total

Appendix A
Greenhouse Gas Emission 2045 vs . 2026 Change
3-Baseline Portfolio
2-Alternative Lowest Reasonable Cost Portfolio 1
17-PRS Constrained to 2%Cost Cap 1 '
1 :
6-High Economic Growth Loads
18-Data Center in 2030 1
1 •
1
21-Regional Transmission not available 11
13-30%PRM 1 1
24-No IRA Tax Incentives 1 '
1
1
8-WA Building Electrification&High Trans... 1
23-On-system wind limited to 200 MW 1 1
1
7-WA Building Electrification 1
11
15-Minimal Viable CETA Target
1
16-Maximum Viable CETA Target 1
1
1-Preferred Resource Strategy 1
1
14-Power to Gas Unavailable 1
1
25-Northeast Retires Late 1
1.
22-Northeast Retires Early 1
1
19-RCP 8.5 Weather 1 1;
12- 17%PRM 1 '
10-Maximum WA Customer Benefits 1
1
5-Low Economic Growth Loads 1
1
11-Least Cost+500 MW Nuclear in 2040
9-Building Electrification&High Trans...
20-Building Electrification&High Trans...
4-Clean Resource Portfolio '
-0.5 0.0 0.5 1.0 1.5 2.0 '
46 ■Net Emission Change(MMT)
■Generation Emissions Change(MMT)

Appendix A
Change in Emissions vs . PVRR Cost
5,000
4,000
0 \
0
3,000 g-Building Electrification&
High Trans. Electrification
p� w/o N G
� 8-WA Building Electrification
d &High Trans. Electrification
E 2,000 10-Maximum WA Customer
a) Benefits
v 11-Least Cost+500 MW
CI) Nuclear in 2040 7-WA Building Electrification
•� 6-High Economic Growth
1,000 4-Clean Resource Portfolio Loads
14-Power to Gas 13-30% PRM
cC Unavailable
I 16- Maximum Viable CETA
U i Target
0 2-Alternative Lowest �� �- 3-Baseline Portfolio
Reasonable Cost Portfolio 17-PRS Constrained to 2°
15-Minimal Viable CETA t5-Low Economic Growth Cost Cap
Target Loads
-1,000
-4 -3 -2 -1 0 1 2 3
Change in 20yr Total Greenhouse Gas Emissions (MMT)
47 O=

►�IVIsra
Natural Gas Price Sensitivity Analysis

Appendix
PVRR Impact of Change in Natural Gas Prices
Change in PURR vs Expected Case Market Pricing
m6mmm
Washington�� Idaho System �
High NG Low N High NG Low NG High Low NG
Prices Prices Prices Prices NG Prices
r�✓ISTA'
49

Appendix A
GHG Emissions Sensitivity to Natural Gas Prices
Total GHG
Emissions vs
Expected Prices_
High NG Low NG
tortfoliaLl
1- Preferred Resource Strategy -13.0% 7.7%
3- Baseline Portfolio -14.0% 8.8%
4- Clean Resource Portfolio -9.4% 5.7%
11- Least Cost + 500 MW Nuclear in 2040 -11.8% 6.8%
t
3- Baseline Portfolio -2.3% -0.1%
4- Clean Resource Portfolio -9.4% -14.6%
11- Least Cost + 500 MW Nuclear in 2040 -1.8% -4.0%
50 imb

Appendix A
2025 Electric IRP
TAC 13 Meeting Notes
September 17, 2024
Attendees:
John Barber, Magneglide; Shawn Bonfield, Avista; Kim Boynton, Avista; Annette
Brandon, Avista; Michael Brutocao, Avista; Logan Callen, City of Spokane; Katie
Chamberlain, Renewable NW; Kelly Dengel, Avista; Chris Drake, Avista; Michael
Eldred, IPUC; Rendall Falrey, Avista; Ryan Finesilver, Avista; Damon Fisher, Avista;
James Gall, Avista; William Garry; Konstantine Geranios, UTC; Amanda Ghering,
Avista; Leona Haley, Avista; Lori Hermanson, Avista; Mike Hermanson, Avista; Kevin
Holland, Avista; Fred Heutte, NW Energy Coalition; Annu John, Fortis BC; Alexandra
Karpoff, PSE; Paul Kimmell, Avista; John Lyons, Avista; Heather Moline, UTC; Molly
Morgan, UTC; Tomas Morrissey, NWPCC; Austin Oglesby, Avista; Kaitryn Olson,
PSE; Michael Ott, IPUC; John Calvin Slagboom, WSU; Nathan South; Darrell Soyars,
Avista; Dean Spratt, Avista; Lisa Stites, Grant County PUD; Charlee Thompson, NW
Energy Coalition; Bill Will, WASEIA
Introduction, John Lyons
John Lyons: Oh, good, James. You started the recording. Glad you remembered on
that. Going to flip to the next slide here.
James Gall: I will try. It's giving me issues here, so bear with me here. All right. I'm
going to have to stop sharing really quick. Sorry, John. I apologize.
John Lyons: No, not a problem. Basically, everyone, what we are going to be doing
today is mainly going over the results of the scenarios, so we have been busy running
all of those and getting the data for them. James is going to be spending the bulk of
today sharing the results of those. And then once we get the slide deck up here, you
already should have seen the draft of the IRP for the bulk of the chapters that came
up. And there we go. We've seen today's agenda. And if you want to just go right to
the PRS update because, James, I believe you had one or two little things that you
had to update on that. Is it for energy efficiency, I think.
James Gall: Yeah, it's correct. Yep.
John Lyons: And then scenario analysis, then the next steps, just going to wrap up
for the day and what the plans going to be for getting everything done for the January
1 St publication date. And next slide. We have set a date for the virtual public meeting.
It'll be for joint natural gas and electric IRP. There'll be a recorded presentation and
there's going to be a 7:30 to 8:30 in the morning meeting Pacific Time and then there
will be, looks like we have an evening one from 6 to 7 pm.

Appendix A
James Gall: John, actually, there are a couple corrections on this one.
John Lyons: Or is it noon, OK? So, it is noon that we're doing.
James Gall: Noon and then no natural gas. Sorry, I apologize.
John Lyons: Oh, OK, good.
James Gall: We'll update that slide.
John Lyons: OK. We will do that, but it is going to be November 13t". So, we have
that.
James Gall: I believe so.
John Lyons: OK. Those all be posted on the website too? And then the next slide.
We already have quite a few of the chapters that were sent out, the remaining ones:
the introduction, involvement process changes. Basically, where you can look to see
where things are going to be located in the IRP in the organization of. It will be adding
the market analysis chapters and portfolio scenarios and then we'll be able to write the
executive summary when those are completed. That'll be October 1 st. We'll send those
out and then you'll have the complete draft of the IRP. I think James, is that all, we do
have the appendices. And I believe we did have a slight change towards the end there
where we're combining two of them for the data.
James Gall: Yeah, that's Appendix K going to go away and be part of Appendix G.
John Lyons: We're trying to organize those so they're all little bit easier to go through.
Presentations are already on the website, Work Plan, those first batches of data for
the studies, and then we'll finish. We already have quite a bit of the public input and
results data. James, if you want to talk about what's out on the Teams site.
James Gall: Yeah, I really was going to keep that in the context of today. What the
presentation, there's, I'd say, a limited, we have 26 scenarios and that's a lot of
information to cover in 2 1/2 hours. But if somebody wants to dig into the results more,
I do have a file out there that summarizes all of the scenarios. And then once we get
past October 1 st, I'll be posting all of the PRiSM models out on the Teams site as well,
and eventually they'll be on the website. If you want to dig in, it's going to be available

Appendix A
for you to do that. We're going to keep it mostly high level today just to get through all
of the scenarios.
John Lyons: I think that takes care of it. If you want to start going on the results.
James Gall: OK, I'm going to see if I can get this to move over to the other
presentations. See here. We see the right thing.
John Lyons: Yes.
Scenarios, James Gall
James Gall: Yep, we do. OK, good. So, like I mentioned earlier, we have about 26
scenarios to go through. We've also done a couple of different, we'll call them market
sensitivities that I'll cover today, but before I get into the scenarios which actually are
really the most interesting part of the IRP, because it tells you how our resource
strategy could change as time goes on because we all know the Preferred Resource
strategy will change. I don't know if any of them have been correctly right in my 20
years of history here at Avista. It gives definitely a glimpse into what could happen in
the future. Before we go there, we do have one change dimension on the PRS. This
was actually, we were able to get it corrected in the IRP document that went out as a
draft, but it has to do with energy efficiency. We were meeting with AEG and right
before we're ready to publish the draft IRP, we realized that losses, line losses for
energy efficiency will be double counted. So, we had to rerun our model, come up with
the correct economic potential for energy efficiency. The slide here shows the
difference between what we presented in the TAC meeting, I believe in August, and
then the final result once we removed losses. Losses are around 5'/2%. That covers
most of the reduction. The other reduction, to get to 7.7%, has to do with some of the
economic choices when the resource provides less benefit than it thought it would.
The model actually selected slightly less energy efficiency, so this is like I said earlier,
it's been updated in the draft IRP, it did not change our Preferred Resource Strategy
on that generation or the supply side at all.
James Gall: We've been running our energy efficiency separate from the supply side
selection to lock it down. That choice actually helped us quite a bit here to ensure it
didn't have a ripple effect on the rest of the analysis, but just something to be aware
of. OK. Over the course of the TAC meetings, we've talked about portfolio risks, and
this is a scattered chart of all the different risks that we've covered over the year and
a half of going through this IRP. A lot of it has been around load. We've talked about
weather quite a bit. We talked about data centers. We talked about CETA and the
impacts it has on the portfolio with different interpretations of rules.

Appendix A
James Gall: Another big topic we've covered is what resources are going to be
available. Northeast is actually the biggest resource on our mind as that's the closest
one to a retirement date. Is nuclear going to be around? Is power-to-gas going to be
a real resource? We talked about the regional transmission line going into North
Dakota. But what we're trying to do is take all of these risks that were discussed in the
TAC meetings and come up with different scenarios on how it could impact the
resource strategy. And then also look at the reliability of the portfolio with some of
these changes and then the question is, do we do loop backs of whether or not our
portfolio is reliable? Do we change the scenario or results? Or if it's more than reliable
enough, do we go back and try to reduce the amount of resources that are needed.
We ended up doing 26 scenarios. And as you might think about, we have 26 scenarios
with the trial and error of a lot of these scenarios. We probably run our capacity
expansion model probably 150 to 200 times to make sure these 26 scenarios are
looking in the right light, as far as what the scenarios intent is. Some of the insights
found going through the scenarios is demand response and energy storage is really
the fastest resource we can add, if we need capacity if the load forecast comes out to
be too low next time we look at resource acquisitions. For example, in the upcoming
RFP, we're going to be looking at those two options, they are probably the best to
meet capacity needs. When to some extent they can help meet some capacity needs,
but it takes maybe an extra year or so to get one of those facilities online.
James Gall: Looking out more out in the future. There are really two technologies
being discussed, at least we found in the analysis to be help us meet winter peaks.
That's power-to-gas, and that's ammonia or hydrogen. Depending on how much of
that resource is able to contribute, when I mean by that is how much fuel we're able to
get. So, how much hydrogen or ammonia we're able to get out of the marketplace. If
that is a constrained resource. And CETA continues in its same form. Nuclear energy
appears to be the only real resource that can meet the goals of CETA out in the 2040s.
A lot of our scenarios show a significant nuclear acquisition in the out years and that
creates a cost on the system because the prices I have here ranges between $144 to
$206/MWh and that can create a cost cap concern from a CETA perspective. That's
something to look for as we go through time. Obviously, it's not something that's an
immediate issue today, but it's definitely something we've caught on in the analysis.
James Gall: Going back to wind in the PRS. There's a significant amount of wind
around 1 ,000 megawatts and at 1,000 megawatts, even at 5% or even 10% capacity
contribution that's 100 megawatts of capacity contribution. You're leaning on wind and
that creates a risk for the utility because we saw during the January cold weather
event, wind was not a significant capacity contribution. It creates a little bit of a risk to

Appendix A
rely on wind to even meet a small amount of capacity, but that is something we've
seen in the modeling. The other thing to think about is transmission limitations. The
PRS that we presented last TAC meeting. It's really trying to maximize the amount of
wind that's available given the transmission limitations we think the system has and
then what happens is if once you hit those transmission limitations, that's when nuclear
and solar also starts to show up. If we hit our transmission limitations earlier and still
need clean energy, that's where we're nuclear and solar will likely increase its need.
But if we have transmission expansion, it may lessen or defer that net need.
James Gall: And then lastly for Idaho analysis, we do see natural gas CTs repeatedly
showing up as a low-cost option. There are some challenges with natural gas CTs and
that's permitting. The time it takes to permit those resources and then the infrastructure
transmission pipeline, potentially energy or natural gas storage, even with all those
costs, natural gas for our Idaho customers seems to be the least cost. It just takes time
to get those resources online. But again, at the end of the day, all of our resource
selections will likely go through an RFP process with specific projects and we can then
see what's the most cost effective once we have specific information rather than
generic information in an IRP.
James Gall: OK, so like I mentioned earlier, we did run 26 scenarios. That includes
the Preferred Resource Strategy. I've lumped them into the four different buckets to
cover today. The first bucket will cover some different methodologies on different
portfolios and we'll get into some low growth scenarios, resource availability scenarios,
and others maybe get combined in the final report, but we're trying to group these into
a rational order. The numbers you see on each of the scenarios correspond to the
order we created these scenarios, and they were assigned a number. We just we left
those numbers as we created the scenarios in our modeling. You might see those
numbers attached to some charts in the future, either in the document or in the
presentation. This slide is really for reference as we go through the scenarios on what
was included in the Preferred Resource Strategy. I don't want to cover this too much
in detail, but we'll just mention a few things. That's more near term. And that is, we do
have a little bit of market in the early period and that's related to a contract that's going
away that 39 megawatts kind of buys back a contract that we have. And then the model
switches to DR and community solar and then eventually a wind acquisition by the
2030s. And I saw a hand up and I think it was Molly. Go ahead, Molly.
Molly Morgan (UTC): Yeah. Just a question, I don't see this in the draft IRP like this
actual table. Is that coming in October, then?
James Gall: Let me see here. We have, like I said, I think it's a simplified table in draft

Appendix A
we do have. This is in the appendix, so we'll have an appendix that has a table that's
very similar to this for every portfolio.
Molly Morgan (UTC): OK.
James Gall: So that will be a spreadsheet and on our team site you have access to
this. Right now there's a file. I think it's called. PRiSM scenario results out there and
then also the prism file that created this is on the team site as well. So you have the
full model for this specific scenario.
Molly Morgan (UTC): OK. You said this this isn't in an appendix. Currently, though in
what you filed.
James Gall: No, it is not.
Molly Morgan (UTC): Yeah. OK.
James Gall: Yeah.
Molly Morgan (UTC): Yeah, I think this would be. I just like seeing it like this. I think
it'd be good to have it in the filing itself, so maybe supplement that in October because
saw like in Chapter 2, the PRS chapter, it's broken up in different ways.
James Gall: Yeah, we can do that.
Molly Morgan (UTC): But yeah, it's nice to just see it all laid out. Thanks.
James Gall: OK, we'll do that. We'll put it in there and it'll be in the new chapter too.
Alright. Any other questions or thoughts before we get to the scenarios?
Heather Moline (UTC): Yep. This is Heather from UTC staff. James, did you say
solar or community solar by a certain year?
James Gall: Yeah. The solar you see in there under Washington, I don't know if my
mouse is the point, but that the ones that you see going across. That is community
solar that's picked in the model. And that represents some funding by the State of
Washington that's funneled through Washington State University to pay for a majority
of the cost, if not all the costs, for community solar projects. When we model that
basically free solar, we'll call it that. It does pick basically as much of the free solar you
can get. How that works, I believe it's a 200 or 199 kilowatt size project or less. You

Appendix A
can group some together. But that's something the Company is looking at. As we look
at how we can access that funding and my expectation is that's going to be probably
a topic of interest in the CEIP process. That actually ends up looking like.
Heather Moline (UTC): So, not utility scale. It looks like utility scale is not found within
the Preferred Resource Strategy at all. You're just talking about community solar.
James Gall: Yes and no. Community solar, early on. Utility scale solar shows up late
if you look at 2043/2044, it does show up, which actually is an improvement from the
last IRP. We had no solar show up besides community solar.
Heather Moline (UTC): So that it doesn't actually differentiate here, but you're saying
that 2043 within the solar row that jumped from 1 to 181? So, 180 megawatts of utility
scale.
James Gall: Correct.
Heather Moline (UTC): OK.
James Gall: And if you go to, and maybe that's something we'll break out, that next
chart we have all of these technology categories. We are modeling around 50 or 60
different resource options. We could even break that down further. You can see what's
DER solar, what's utility scale, and then on system wind in Montana on the AVA
system. We have further breakdowns. This is more of a summary shot of it. OK.
Any other questions? We have about two hours and it should be on time.
Let me know if we need to take a 5 minute break potentially at maybe, I don't know,
10:15 am. That might be appropriate.
James Gall: OK. My plan is to cover each scenario, do a high-level summary of the
results and what the assumptions are. And then I have some slides at the end that are
really a combination of all the scenarios. I'm not going to spend a lot of time on those
if we couldn't get that far through the presentation, but please interrupt me as we go.
Lori's watching the chat. Just feel free to interrupt me at any time. OK. The first
scenario, we call it the alternative lowest cost scenario, is part of CETA's requirements
to calculate a counterfactual portfolio to calculate the 2% cost gap, I almost thought
about not including this in the IRP. It's really a CEIP or Clean Energy implementation
plan scenario. It covers the first four years as that counterfactual portfolio, but
regardless, it is here. I don't want to spend a lot of time on it just because it's really
focused on the four years for the CEIP. And in that four years, the model is basically
coming up with a very similar result. Just because our resource position is a little bit

Appendix A
less energy efficiency in this scenario for the first four years, but largely the same. But
if you extended this out over time, it does acquire quite a bit less resources because
this scenario does not include the CETA targets. But it does include the social cost of
carbon adder, and that combination results in a little bit less wind, less solar and then
less energy storage. And then at the end of the day, it results in less cost for
Washington. Although it's going to be unique in this scenario and the next one, you're
going to see, Idaho actually sees slightly higher cost in how you shuffle resources
around between the states. Washington's always trying to in the model take low-cost
energy resource or clean energy resources to meet CETA, and sometimes that can
cause issues on the Idaho side of the portfolio depending on how future costs are
allocated and then we did look at some resource adequacy views of this. They are
both below the 5% threshold, actually significantly below that, because the model is
designed in a way to have more renewables and when you have more gas turbines
like in this example, it actually makes the system more reliable. You could actually in
fact need less. But anyway, that's the scenario. Like I said, it's really going to be used
for the CEIP process. It's going to come up again there.
James Gall: Let's move on to the next one. And that's we call the baseline scenario,
and this is very similar to the alternative least cost scenario, but it removes the social
cost of greenhouse gas, it removes NEI calculations. Basically, it's what our portfolio
would look like if we planned our system like it was planned, say, 10-15 years ago
where we were just solely looking at. least cost planning for the system.
It's actually for the Idaho service territory. It's very similar as well, a least cost look.
The results really are basically less renewable generation, 700 megawatts of wind still
remains, but it's less than it was in the PRS and a lot of our capacity needs are no
longer served by energy storage in this scenario where nuclear it's served with natural
gas. And like the previous scenario, costs are lower for Washington, about 17% lower
by 2045. And what I mean by cost, what I'm talking about there, is the average rate of
energy. There's really two looks at costs that we publish, one of them is PVRR that's
present value revenue requirement. The second one is the energy rate, that total cost
to serve divided by how much sales or energy sales or our retail load. I like to show
the average cost of energy more than PVRR. Oftentimes, because it takes into
account the change in load, where if you just looked at PVRR it is kind of misleading
because if you have a low load scenario, your PVRR is going to be lower but your rate,
your energy rate could be higher. This scenario again, it's another one of those
counterfactual results, because we need this scenario one, it helps demonstrate some
of the costs of energy policy, but also helps us with calculating our avoided costs. This
is one of the scenarios we use to help us calculate the capacity value or the energy
value in the in the IRP. So that's baseline scenario. There's going to be a little bit more

Appendix A
detail on each of these in the actual document as we're writing these up, so be on the
lookout for those.
James Gall: The next one in this category is related to CEIP condition #33. This will
likely also show up in the next CEIP as well. But what we were asked to do is look at
a scenario with minimal primary compliance targets by 2030. The reason behind this
scenario is in this last CEIP process customers have a lower cost if we have targets
that are lower than a constant trend towards 80%. The table in here shows the PRS
targets versus what the scenario assumed. The CETA target for primary compliance
is around 62.5% for 2026. We keep that flat and then it jumps up at 2030 to 80% and
then it's a slower trajectory all the way to 2045. And what we found in this scenario is
compared to the Preferred Resource Strategy, there's really no material change in the
in the results and there's a few reasons for that. A lot has changed since this condition
was brought to us. Because one is, we have more renewable energy than is needed
to comply with CETA to around 2034. The second reason why there's not a change is
the renewable energy that's selected in the Preferred Resource Strategy for
Washington is not driven by the percentages in the early years of the study, it's really
driven by an economics where the price forecast of energy is less than the forecasted
average energy cost of wind. In that shorter term period, because of the IRA, the
amount of clean energy required to hold really is not changing the results for this
acquisition. But what does change though, is the amount of revenue the company
would get through REC sales. And that's something we're going to cover more in the
CEIP process. Is that if we have higher targets that force us to retire renewable energy,
that takes away our ability to resell the RECs or potentially into the CCA market at a
higher price, because if we have two options with clean energy, when you have
excess, you can either sell it as specified clean and get a higher price for it on the
energy market. Or you can sell off the REC and either one of those benefits customers.
If we have higher targets, that's less revenue available for our customers. That's like I
said earlier, that's going to get covered in the CEIP process in a similar way as the last
CEIP process when most of the cost impacts were due to the REC value of the
renewable energy. OK.
James Gall: The next one is the opposite of that scenario where we maximized the
amount of RECs that we would hold preceded as that changed the result. Again, this
one surprisingly had no impact as well. And that's really because we are trying to hit
targets out in the future. Now if we lower the targets in 2045, before 2045, you could
see a different target or a different result, but because all of these see the scenarios
are targeting 2045 at 100%. It's not changing the result because that generation's got
to be built. It's just a matter of timing. So, this one really found no significant change
at all. All right.

Appendix A
James Gall: This next one is actually pretty important. I thought that has to do with
the cost cap calculation in 2045. And there was a chart I showed at the last TAC
meeting that showed fairly constant average rate increases through 2044. And then in
2045, the price, the average price of energy in Washington, shot up significantly. And
that's due to a couple things going on in 2045. Number one, we have to have all natural
gas out of the system for Washington unless we have the 2% cost gap. That means
we have a significant resource retiring in 2045. That would be Coyote Springs 2. Two,
the other issue in 2045, is that's when a nuclear plant is selected at near $200 a MWh
we described earlier. Three, that is a switchover and CETA from trying to be matching
clean energy to retail sales to clean energy meeting full load. So, in 2045 versus say
2044, we're trying to not only step our increase towards 100%, but you're also trying
to cover load, which is around an additional 5'/z% of our clean energy requirements.
At that point in time, even if you try to acquire some resources earlier, you have a
significant cost at the tail end of our portfolio. What we tried to do is estimate what
would that 2% cost cap be when you get to 2045. The first line of thought I had is, well,
we could just use our alternative lowest cost, lowest reasonable cost scenario, but
that's really only valid for the first four years. We would need to come up with a
theoretical alternative lowest reasonable cost portfolio that would be created in 2044.
That's what we did. We calculated, basically took our Preferred Resource Strategy,
assume all that happens and then in 2044, what would our portfolio look like if we did
not meet CETA and come up with this future scenario and that creates a cost in 2045.
We then take that cost, calculate the cost cap which is 2% of revenue requirement in
2044. And then we're assuming it's a four-year compliance period. That's a whole other
story, but we're assuming that and that basically limits our 2045 increase to 8%. So,
between 2044 and 2045 you can have an 8% increase in rates. It's not 2%, but that's
how the rules work. And in that scenario, what happens is Coyote Springs 2 remains
an allocated resource to Washington. It does assume we could burn around 30% of
that generation with hydrogen, but what happens is because of that, Idaho would need
more natural gas generation because it's no longer taking what was from Coyote
Springs 2 and then it does shift to less wind, less nuclear, less biomass and energy
storage for 2045. That cascades to lower rates for Washington, about 9% lower in that
2045 case. Idaho would see a slight increase because it no longer has a Coyote
Springs 2 plant it's going to be able to utilize. Hopefully that makes sense, but what
we're trying to illustrate here is that we see in 2045 that we're likely to exceed the cost
cap, but we're not expecting to see a cost cap issue until that period of time to comply
with CETA. OK. That was a lot. I just want to pause there before we go to the load
scenarios. If there's any questions. OK, Molly, go ahead.
Molly Morgan (UTC): Yeah, I still just struggle to wrap my head around this. So, you're

Appendix A
saying that you might not meet the 2% cost cap in 2045. And what would your
resources look like given that?
James Gall: Yeah.
Molly Morgan (UTC): Yeah, I think I'm still not really understanding. Why you would
exceed the cost CAP in 2045 specifically? Can you try to put that another way?
James Gall: Sure. In 2045, we have to replace Coyote Springs 2. And we have to
move to 100% renewable or clean energy in every hour of the day. That's the big
change from 2044 to 2045. And the resources necessary to do that, which is on the
third line or fourth line from the bottom. Washington resource in 2045, use less wind,
nuclear, biomass and energy storage. Those resources that are removed essentially
have a cost that's so much that it's going to trigger that cost cap. And well, one thing
in 2045, it's unclear in the legislation whether or not there is a cost cap. That's, I guess,
an unknown but we're just illustrating here, is based on what we know today. The
resources it's going to take to meet that 2045 goal are going to be significantly more
than an 8% rate increase in 2045.
Molly Morgan (UTC): OK. I guess I just wonder why, given that this is all supposed
to be incremental, and I think I see you're using incrementally less alternative
compliance from 2030 to 2045, why is it all happening in one, why is there a problem
in one year?
James Gall: Yeah. I've looked at what if we try to acquire resources earlier, but it
really comes back down to trying to solve a portfolio that's every hour of the year. So,
what that does is you have to create or build enough resources that your odds of
serving that energy is available. It's just the quantity of resources that you're trying to
comply with. In 2044, the law says we're meeting towards 100% of retail load. That
doesn't include losses. In 2045, we now have to meet our losses with clean energy.
There's a step function in 2045 of a higher compliance threshold. And it's not only a
percentage of time, let's say it was monthly compliance or even annual compliance in
2044. That's a lot different than trying to comply with every single hour of the day.
Renewable, no matter if it's a low hydro year, a low wind month, you're trying to now
comply every second of the day has to be clean energy and that's a significant step
function compared to 2044.
Molly Morgan (UTC): Conceptually, that makes sense.

Appendix A
James Gall: Yeah, and we could acquire those resources, say in 2044, and spread
them out, but then you're going to bring your cost cap earlier.
Molly Morgan (UTC): Yes, I mean I guess that's a question if you're acquiring these
resources even earlier than that and flattening that cost increase. Would it actually
exceed that in any one year if it's spread out over five or six more years, for example?
James Gall: Yeah, I did test that and that was why the model was pushing everything
out to the last year, because it was trying to lower its cost as much as possible by
pushing out. But you could acquire it earlier, but I think you're going to hit the cost cap
earlier in that scenario.
Molly Morgan (UTC): And so I think you said one question is, it's unclear in the law if
there even will be a cost cap going from 2044 to 2045.
James Gall: That's correct.
Molly Morgan (UTC): Which is something we can't know right now.
James Gall: Correct. In the law, I guess I'd say it's written more as a goal in 2045
because the penalties are not described after 2044.
Molly Morgan (UTC): OK. Thank you. Heather has her hand up.
Heather Moline (UTC): James, what do you mean by meeting losses with 100%
renewable?
James Gall: In pre-2045, the law is very specific on the targets for clean energy. It
says retail load and that's defined as sales minus the PURPA generation. And then
minus clean energy that's served to a customer, but in 2045. The language is different
and it basically implies you're serving, you can't use a carbon emitting resource, so
that implies that you're no longer trying to meet loss. Your retail load. You're trying to
meet all of load with clean energy because you can't use a thermal resource.
So that implies you're now going from retail sales to meaning load.
Heather Moline (UTC): OK. Line losses.
James Gall: Yep.

Appendix A
Heather Moline (UTC): I just wasn't clear on that, OK.
James Gall: Sorry. Were there any other hands up, OK. All right. I'm going to try to
describe this a little better in the in the document. Some may argue this scenario would
be more of our Preferred Resource Strategy because it takes into account the cost
cap by given the unknowns of how that's all going to be treated, we thought it'd be best
to leave a scenario and have this discussion. And at the end of the day, this is more
than 20 years out from now and we probably should spend more time in the next five
years than the last year of the plan. We'll move on to the load scenarios. OK.
James Gall: Scenario #5 is low load growth and the idea here is that we have lower
loads than our current forecast. Our current forecast is about 0.85% load growth per
year. This flattens it out to around 0.34%. The theory is that you have less population
growth and that reduces our loads downward. And then in the results of that from lower
loads, we have really no changes in our resource strategy until through 2033. But
when you get out to the longer period of time, when you're actually have less obligation
to meet: wind is lower, solar needs are lower, and the nuclear plant goes away. You
don't need as much demand response. You actually have lower costs if you look at it
from a PVRR point of view, but if you look at it from an average. Annette. A great point
of view. Your rates are slightly higher because you have a fixed cost of our system
that's now being spread out over less energy sales. So, you have slightly higher rates,
but we've been running these types of scenarios for quite a while on how low
trajectories work. This is pretty similar to those past scenarios where you just need
less resources. But you know from our current point of view, when we don't have a lot
of needs, for resources in the short run, unless we have load growth. It's a better
position to be in if you have lower loads than higher loads.
James Gall: Because the next scenario, when you get into higher loads earlier like
some of these other scenarios we are getting into. Then the utility has to respond
quickly. In this case we have a higher population growth leading to higher load needs,
about 1.75% per year. This requires demand response earlier. It's a quick acting
resource like we mentioned, earlier and then also wind shows up earlier as well
because, it's kind of interesting here, this is where wind is actually contributing to
capacity a little bit where if you have small capacity needs and you have clean energy
requirements at the same time. The model will pick wind earlier to help meet those
small low growth increases, but it also saves it from having to buy wind later on. Long
run though, the model is picking more demand response and solar to meet the growth
of higher loads and this has to go back to it reaching the limits of its wind acquisition.
In the long run, where we don't have enough transmission to bring that wind on. So,

Appendix A
it's looking at the next tier of resources. It's used up all of its wind. It's used up all of its
power-to-gas in Washington, so it's using nuclear and solar to help meet that growth.
And then in Idaho, it's simple to meet additional low growth without the CETA
constraints. It just basically builds more natural gas turbines. From a rates perspective,
it's actually higher because in both states you're serving your incremental load with
incrementally more expensive resources. We've seen in other cases, if you have
plentiful resource opportunities, you could actually lower rates sometimes. In some
cases, you'll see that, but in this case it does say slightly less rates, but the PVRR is
higher. It's about 6% higher.
James Gall: OK, so going on to electrification scenarios, this is an enhancement we
did in this IRP to model a very simplified natural gas system so that we could
understand the impacts to total emissions. To potentially natural gas rates, if we move
customers from the natural gas system to the electric system. And what this scenario
assumes is that based on today, if 80% of that demand for natural gas, if we move
80% of that demand to electric by 2045. If you think about what the gas demand is
today versus 2045, the remaining gas demand is about 20% of what it is today. That's
what the scenario is trying to assume, and then that gas load has two options when it
electrifies. If they're in an Avista service territory, they become Avista electric
customers. If they're in another service territory, they would go into, say, Inland Power
and Light. Some analysis we've done a few years ago, we assume around 75% of our
Washington natural gas customers become electric customers.
James Gall: In regard to your last two scenarios, I had a question. Are these high or
low load growth differences driven by changes in the number of customers or by the
changes in usage per customer or both? OK, going back. It's the number of customers
that are the driver or population growth and economic growth. So, they are, I believe
that when AEG did this and Mike, if you might remember, correct me if I'm wrong, but
it's population. It's mostly population. There's a little bit of economic growth but driven
largely by population.
James Gall: All right, so back to electrification. We have customers moving. This first
scenario is just looking at Washington. You have 75% of the 80% loss in customer
going to electric Avista? So, what that does to our electric load is it adds around 356
megawatts of peak load in the winter and around 107 average megawatts to energy.
I think we covered some of the assumptions around this scenario in past IRPs, but the
concept is that these customers who are converting, they'll be using a heat pump
technology and for both water heating and space heating and while heat pumps are
more efficient. It can be more efficient than resistance in cold weather, but at a certain
point when you get to around 5° or less, that efficiency radically decreases. So that's

Appendix A
why you're seeing significant peak load increases for serving that gas load also. Even
if you were more efficient than resistance, you still have added load because it's more
demand. So, what we see going on in this scenario with that added load, basically
trying to serve 356 megawatts more peak load in winter is you're going to have to
move first. The first thing we saw was the wind that we have allocated to Idaho gets, I
guess, gobbled up by Washington. Washington has this higher load, and it wants as
much clean energy as it can get to serve that higher load to meet CETA. That's the
first thing we see. The secondary effect means Idaho gets left with a little bit less
capacity from its wind, and it's got to build more natural gas. And then what
Washington has to do now to meet that extra demand, that 356 megawatts of demand,
it's saying I got to build solar 240 megawatts, I got to build more energy storage and
got to build more nuclear. Question, Fred, go ahead.
Fred Heutte: Hi, it's Fred here at Northwest Energy Coalition. A real quick question
about the heat pumps in really cold weather, do you, is that I agree you know that's
what the I've looked at some of the manufacturers spec sheets for that, but I'm
wondering if you have any actual observational data, you know what's happening in
your? You know, in your territory in those kinds of conditions like back in January.
James Gall: Yeah.
Fred Heutte: Just to hone in on what the actual effects are.
James Gall: Yeah, the best thing we have is the PNNL study. They did a study on
heat pumps in the Spokane area and they had, I believe, 12 different sites. They
monitored, I think, six or seven were in Spokane and few were located in other areas,
and they calculated basically what the efficiencies of that technology was at different
temperatures. And it's looking at the systems, not ductless systems. That's really the
powerfulness of that study is if you're switching a gas customer, most 99% of the cases
that have natural gas heating, they have a ducted system and they'd be replaced with
a heat pump. That is what we used to calculate the efficiency rates at different
temperatures. I have a link to that report, it's in the IRP document. There should be a
footnote link to it, but it's also in one of the slides from a previous TAC meeting. But
we can try to hunt that down and put it in the chat later.
Fred Heutte: Yeah. I appreciate. I do remember that now. Thanks for reminding us.
The one only thing about that, and I don't want to get sidetracked on this, is there are
a lot of ductless or mini splits. I've got one. And just to recognize that this is a real
effect, but I think it needs a little bit more. It's going to be pretty important in the future

Appendix A
with more of the gas to electric conversions happening. In that kind of demand surge,
which we saw in January, is a very important factor for peak load management.
James Gall: Nathan Scott or I'm sorry, Nathan South, asked if the cost savings from
deactivated or abandoned gas infrastructure is included in the electrification scenario.
Yeah. I have a slide coming up on that, but the savings is mostly from the throughput
of less natural gas, abandonment of natural gas systems is likely not to occur. And
actually, what we're finding is due to the Adyl-a replacements, you're actually going to
see further investments in the natural gas system for safety purposes. The only way
you can abandon natural gas lines is if everybody on the system is gone off that line
and on these high-level scenarios, we don't know exactly which part of our system
you're going to turn off, but even if you're abandoning that line, you still have to recover
the costs that the utility is stranding in that line. You just avoid future maintenance, so
would say the answer is no, but the impact of that is, is it say is minimal; potentially,
but we'll cover what that is in about three or four slides from now. That's a good
question. All right. Any other questions on this scenario? Just to finish it up from electric
only point of view, about 12% higher rates. There's a secondary effect that can happen
in these scenarios where you're basically adding more load to existing customers and
that's you're going to have more feeders that are going to need to be upgraded or split
up and that's an additional cost that comes to the system in addition to the generation
that you need.
James Gall: OK. The next scenario, we took that higher building electrification then
added onto it a higher electric transportation trajectory. We already have a pretty high
electrification of transportation in our base case. But this takes it another level up
where we have more and more customers adding EVs to the system. Effectively, this
adds another 127 megawatts to winter peak and then 76 average megawatts of
energy. Like the previous scenario, we have the shift of more wind to Washington,
which puts Idaho into having to go get more gas. But you get the same results.
Basically, building more solar, more energy storage and more nuclear to meet these
higher loads. And then again, you have higher rates. In this case, the rates are actually
a little bit less than the previous case because you're getting, I would say, your energy
concentration is a little bit better, so you get a slightly higher rate. And what I mean by
concentration is a load factor, so a little better in this case.
James Gall: The next scenario we looked at is taking the scenario we did with
Washington, then adding that to Idaho. In this scenario, call it the highest load case
possible, you take all of Washington and Idaho, and you make it the highest
transportation electrification case possible. That adds around a million cars, I believe,
equivalents by 2045. Then you have 80% of your Washington customers from today

Appendix A
converting to electric on the gas system. In Idaho, it assumes 80% of future Idaho
customers are now electric. And in Idaho, we have a little bit greater concentration of
gas customers that are on our system. We assume about 90% of the lost gas
customers stay on electric system, but what this results in is essentially, we assumed
that you wouldn't be taking customers off the natural gas system and building gas
turbines. We turned off the ability to burn new natural gas in this scenario and the
result is we would have to build around 800 megawatts of additional solar to the PRS
and almost 900 megawatts of energy storage. And then another 726 megawatts of
nuclear. That'd be about 826 megawatts of nuclear. That's almost one of the largest
plants that they just built down there in Georgia. So high loads essentially at the end
of the day, implying that nuclear is the lowest cost option because it is the only clean
option that can meet significant load growth out in the out years. I mean obviously
energy storage, wind and solar are helpful, but nuclear is definitely the go to resource.
Costs. This is where costs get a lot higher, mostly because of the nuclear energy.
We're seeing Idaho's rates around 36% higher, Washington's about 25% higher, and
in reality, the rates are about the same. It's slightly higher in Washington at the end of
the day, because Washington's already is required to have higher rates when you get
to the time from a reliability. This is a study we actually got it to do a reliability study
with the level of nuclear and energy storage and solar. The system is still reliable.
0.1% LOLP, which is below our 5%, so theoretically we may need slightly less nuclear
generators to meet this scenario's reliability target, but it definitely is possible with that
amount of new generation.
James Gall: All right. To summarize, back to the question posed earlier, when you
start putting together natural gas costs and the electric costs, that's what this slide is
trying to accomplish. We have it broken up into different categories of costs. The first
category is an estimated impact of converting gas customers to electric that are
impacting other utilities, not just Avista. So, the 25%, customers that would be now on
Inland would have their own cost to comply or to meet that new load growth. That's
estimated in that first line. The second line is estimating the amount of conversion
costs to convert that site to electric. This is on the low end of the costs. This is what
we used in the previous natural gas IRP. We're finding a lot of examples where it's
significantly higher cost to convert, but if you go back to our 2023 Gas IRP, those are
the costs that we're using in this study. And then in the natural gas in Idaho and the
natural gas in Washington, this is the revenue requirement for serving those customers
that are remaining on the system and those do decline as you electrify more
customers, but you still have the fixed costs that you're trying to recover. Now these
costs are really only shown for 2043 to 2045 during the period of time where there's a
higher saturation of natural gas customers. And then you have the cost for the electric
system in Washington and Idaho. So, there's about a, I think it was around 25%

Appendix A
increase in costs for each specific state. Moving to this now, you do have some
emission savings. Today we're around 3 million tons and then between the two
systems, in this example, I should say today in 2026, because today we have Colstrip,
but in 2026 it'd be around 3 million tons. And then we'd be down to between 1.2 million
tons in the scenario #9. Actually, I think I have a typo in scenario #20, that should be
closer to the 1.16, so we'll correct that. So, you're saving around 3 million tons from
today, but only less than 1,000,000 tons. In sense compared to the PRS. I have a
reported number of what this cost per ton of savings Ievelized and I'd like to say it's
around $600 of cost per dollars per ton saved was around $600, if my memory serves
correctly. And then here's some emission savings from greenhouse gas these three
scenarios we have the base case, the PRS in black, and then blue, the Washington
case, and then in nine, as Washington, Idaho in it. So, there's the total savings, I guess
828. Of the average cost for scenario #7. Think 600 for maybe scenario #9, but you
know if you look at cost savings compared to say a social cost of carbon even in the
outer years, you're around $200 a ton. So, this is not the greatest strategy for carbon
reduction, at least from an economic point of view. The gas system heating homes is
extremely efficient, especially in our area. All right. I'm going to move on to scenario
19.
James Gall: And unless there's any questions on those electrification scenarios.
Yeah, we can always go back. And how we doing on time? Let's go another 10 minutes
and we'll take a short break. Because catch my breath. All right, so scenario 19, we
were asked to do a scenario where we used a warmer weather forecast in the winter.
or those of you that have been following along, we chose to use these RCP scenarios
for future weather. Basically, there are two sets of data that we have access to and
are provided by Bonneville Power Administration that help us with our hydro data and
our temperature data. RCP 8.5 assumes you have a greater amount of emissions in
the future, which then lead to higher temperatures in the future, and there's RCP 4.5
which is less emissions in the future, leading to lower temperatures. In the future and
the Preferred Resource Strategy or Expected Case scenario assumes the RCP 8.5
higher temperatures for the summer months and we use a lower temperature forecast,
RCP 4.5 for winter. And just by judging the historical results over the last four years,
compared to these forecasts, for temperatures that were all done pre-2020, we
actually found, and I think we're going to have this in the document, but the RCP 8.5
is probably a closer projection to the summer months. Actually, I think actual
temperatures in the summer are slightly higher. They're slightly warmer and then in
the winter months, we're seeing temperatures have actually trended to be colder than
these weather futures. We are starting to see definitely warmer summers and cooler
winters. I think we're going to see that trend again this year based on some forecast
saw yesterday. At least for this next year, but in this scenario, we test if we have

Appendix A
warmer winters, how much would that change our resource strategy? And at the end
of the day, if you're planning for less winter need, you're going to have less resource
need because the winter is really what's driving the capacity needs in this in this IRP.
And what that ends up doing is it lowers the amount of natural gas for Idaho that's
needed about 46 megawatts and also eliminates the biomass plant that we saw in
2045 at Kettle Falls. But it does increase the amount of energy storage needed and it
does shift around some of the resources that were planned for each individual state.
And then we did see a small increase in nuclear, a couple megawatts. But the change
in the costs is pretty minimal. Point of view is I think you know it's minus 0.2% savings.
But I think from a rates perspective, it's slightly higher if I remember correctly. But
pretty minimal change for the RCP 8.5 while it's warmer. And temperature, we're not
assuming those are what the temperatures are going to be in the future. It's a blend
between history and the RCP 8.5 following our same methodology for calculating
future weather in the future for peak planning, where instead of using the RCP 4.5
case. But at the end of the day, it does give us less resources in the wintertime. We're
still working through the resource adequacy test on this one. We had a preliminary
result, but we're not able to share that yet as we need to do some review of it. It'll be
in the final report in a couple weeks, or I should say the draft report in a couple weeks.
James Gall: The last scenario on load, at least this type of load, is we combined that
previous scenario where we did everything we could to increase load from
electrification and then we assumed the warmer winter. In this case and the
comparison for generation shown here is compared to that scenario #9 and basically
we could get a little bit more wind on the system, less energy storage, less nuclear, a
little more demand response. But again, I think it's the same story. It's just you need
slightly less winter resources in that future, but again you have a similar rate impact
as we saw before. It's just basically higher electric rates also because of its higher load
and you're now using higher cost resources to meet that higher load, so not surprising.
This scenario, #18 is probably the most useful scenario in this whole process.
Honestly, because data centers are knocking on every utility's door around the country
trying to find a place they can build a data center. This is kind of, I'd say, a low case
scenario for a future data center. We assume 200 megawatts in Washington by 2030.
And what we're seeing from data centers is anywhere from this size up to 500
megawatts, the timeline that a lot of these data centers are looking for is what can you
do in three years? What can you do in five years? But this is I'd say, a good illustration
of the type of data centers we're hearing about coming to different utilities. Heather,
go ahead.
Heather Moline (UTC): James, I'm multitasking. Did you say you know of data centers

Appendix A
that are going to be added to Avista's load in their future, or just if that happens, this
is what we're estimating.
James Gall: That's if this happens. There's no data center that's got an agreement to
come to Avista at this time. So, if it happened. In the way we're going to describe the
scenario, this is what it would look like. There's lots of alternatives that could happen
as well. But this is one theoretical scenario put that way. Is that helpful?
Heather Moline (UTC): Yeah. Yeah, it is.
James Gall: OK. All right. The biggest issue we first saw when we were doing the
scenario is what happens. So, I am going to back up, in our IRP world of planning,
which is not always real, we allocate resources by a PT ratio and the model can pick
resources for a specific state, OK. Reality is we don't do that. We just split resources
up by state based on load. So, the big first issue that happens when you have a data
center of this magnitude added to the system is the PT ratio would change if you had
a large load, unless we had some agreement where it didn't. OK. The scenario
assumes the PT ratio gets adjusted, so when you add 200 megawatts to Washington,
more of the existing generation is allocated to Washington and less to Idaho.
James Gall: OK. So that's the first kind of lesson learned here. If you have a large
data center coming on the system now, the same is true if it got built in Idaho. They'd
get more generation, because the model assigns generation to states, when you have
a large load in Washington, that creates a bigger hole for Idaho to fill. Even though in
this scenario the data center is in Washington that's got to comply with CETA, the
model says you got to go build more natural gas in Idaho because effectively, 35% of
our portfolio is Idaho. It has to fill that gap, so that was the first lesson learned is if we
get a data center in the future, should this be treated as a state load or should it be
carved out? If it's carved out, what access does it have to existing resources and what
new resources should be attributed to it? I think there's a gigantic ratemaking issue
that's got to be addressed for the data center and that an IRP is not going to do it. It
can be helpful to understand it, but it's definitely not the place to figure that out.
James Gall: OK, now we got over that. What does it do to our resource strategy? And
I just lost my slides. So, there it goes. In the short run, because you get to meet this
by 2030 it basically pushes a lot of our resource needs sooner, so the wind shows up
sooner, demand response shows up sooner, power-to-gas projects show up sooner,
but overall, we got to build more solar. We got to build more power-to-gas and then
more nuclear. Basically, it just pushes everything up sooner and then adds more of
the existing resource types. It's kind of interesting what it did in this scenario because

Appendix A
it's a high load factor. The shift created a higher rate for Idaho and Washington's rates
actually declined. A data center can be beneficial depending on the rate structure.
Works with the cost allocation, but overall data centers because they have a high load
factor. You're basically spreading more fixed costs of the system to them, so you could
have a lower rate. I did another scenario just for fun because I like to do things for fun.
What if you had 500 megawatts of data center? Well, that takes away some of the
benefits you see here, because then the model has to get extremely creative. How
would you serve 500 megawatts immediately with the constraints we have and
essentially, it's basically maxing out every type of resource it can. Wind, max it out.
Trying to build as much solar as it can and energy storage as it can. Right now, it's
even saying we should build Kettle Falls Unit 2 now and then basically on the back
end has to build a bunch of nuclear. And what the, I guess the concern, we're starting
to see with these data centers, if we had one show up on our system is there's just a
limited amount of low-cost resources that we see today. And if the data center gets
those low-cost resources and they get cost allocated those resources. That's going to
mean all of our non-data center customers in the future are going to get, they're going
to now have to pay for more of a nuclear plant, or they're going to have to pay for
transmission upgrades. So, I'd say rate structure is really, really important on if we
bring in a data center. How do we handle rate structure? So I just wanted to get that
across that if this happens, it is going to be quite the process to figure all this out, but
it's definitely highlighting concerns when you're in a resource constrained environment.
How to make sure that both customers with the data center or the non-data center
customers are protected? We're going to be doing a resource accuracy assessment
of the scenario. It's going to be done tomorrow, I believe. We'll see if it passes. I have
some suspicion it's going to be a close one for 2030 with these sets of resources, but
we may have to actually even acquire more capacity to meet this large load than what
we have here. OK. Let's take a quick break and then we'll go through the remaining
scenarios and then wrap things up at 11 :00. We're going to be here till 11:30, so
another hour. So, let's come back at what, 10:25? Does that sound good? Sure. OK,
10:25.
Break
James Gall: OK. We're going to get started back up again. Hopefully everybody got
refreshed. I was able to get some more water so that was good. Lots of talking today,
but now we're going to move on to resource availability scenarios sharing your screen
don't think. Unless it's me. OK, we have a screen. Problem is it moving, is it working
now? No, not yet. Not yet, nothing. Oh, OK. All right. Sounds like we have a screen
issue. I'll try to reshare. Hopefully you see resource availability now. Yes. OK. We're
in good shape.

Appendix A
James Gall: OK. We're going to start with what's called a clean resource portfolio by
2045. This scenario assumes that we have no gas, or coal for that matter, resources
in 2045. Basically, the portfolio lets our generators retire out or PPA contracts expire,
then we would do likely an early retirement of Coyote Springs 2 in 2044. Essentially,
the model is trying to serve both states, Washington and Idaho, with clean energy.
This kind of aligns with the clean energy strategy the company has talked about over
the last four or five years. And the strategies talked about, this is a goal of the company
to be in this portfolio, but it's got to be cost effective to achieve and as we get to the
costs, you'll see why. The strategy still contains natural gas and continuing to use
Coyote as we do the cost. At the bottom. Now in this scenario, it's kind of similar
because Idaho has a similar objective as Washington. You get a lot of resources that
are, I'd say, more system resources, but it still assigns some resources to each state.
But it does move things around quite a bit. So, when you go to look at say a table, you
can see a lot of resources move around between states. Share the PRS, but at the
end of the day, in order for this to happen in the short run, more wind is needed earlier.
Basically, a movement up in wind and then higher energy efficiency targets because
the energy efficiency avoided cost would be higher in this scenario, especially for
Idaho. You would see more demand response and more energy storage for Idaho.
And obviously less natural gas, so there'd be a significant change for the Idaho portion
of the portfolio without natural gas in the future. And then in the long run in the outer
years, again, nuclear is the main resource that meets this capacity need that's
supported by the power-to-gas resources. We've been talking about the ammonia
turbines. But because Coyote Springs 2, which we had assumed would be burning
30% hydrogen in 2045, it can't go to 100% hydrogen, so that unit would be retired.
That's got to get replaced with something as well. We would have a limited amount of
ammonia gas turbines, but in addition to that, the capacity is met by the nuclear which
adds 384 megawatts to the 100 that we had. A little bit more wind at 130 megawatts
more solar, or demand response. Like I said, more energy storage and energy
efficiency, the power-to-gas losses, again, attributed to Coyote Springs 2. The costs
are 55% higher for Idaho and then in Washington, they're about 17% higher because
of lost resources that would have been allocated to Washington or not allocated to
Idaho.
James Gall: Now we get to resource adequacy. We started to see some interesting
things. One is in 2030, when we ran the loss of low probability model, it did not meet
the 5% threshold, so we actually increased the planning margin and we haven't run
that scenario yet to see if it complies with the 5%. But we saw early on without the gas
CT and the other resource additions in 2030 we would have to have more capacity,
but by 2045 the portfolio solving for the lower planning margin was reliable, likely due

Appendix A
to the amount of nuclear energy on the system. Without some big base load capacity
resource that we've seen later in the portfolio, that scenario is going to have reliability
issues. Definitely an interesting result on this one.
James Gall: Let's move on to the next one. Unless there are any questions, no
questions. OK, did my camera come back on? Yeah, you're showing. OK, good. All
right, since we've been talking about nuclear quite a bit. We were going to run. Oh, go
ahead, Nathan.
Nathan South: Hey, James, thanks for that. Was that the? No, natural gas slide. When
I typed in the earlier question that you, you said we're going to get to that in a few
slides. Was that the one or are you still coming up on a slide that shows the cost
benefits of abandoning the gas resources?
James Gall: Oh. Yeah, that slide was this one right here.
Nathan South: OK. So, I guess my question with that latest slide is the LRP in my
understanding stops at 2045, right?
James Gall: Yep.
Nathan South: So, you're not realizing, you're not accounting for any future
infrastructure or operational savings of getting rid of gas beyond 2045, right?
James Gall: Correct. All of our resources are we call them Ievelized for the period in
time to get around that issue.
Nathan South: OK. Got it. I guess it just appears to me. And again, I'm probably the
most lay person in this group here, that it's kind of like the sum of all bad scenarios
with that in that you're not realizing any of the future benefits of electrification of going
to a single electricity model versus a combined electricity and gas model.
James Gall: I'd say no from the perspective that we model everything as a Ievelized
cost. We're basically assigning the cost and the benefit at the same time.
An example of that is the nuclear plant, where you know you're adding the cost of its
share of that year that it occurs with the benefit of the emission savings of that year. If
you continued it out further in time, you'll see that benefit. I guess that's why I try to
show benefits of the specific year versus spread over time. Because if you look at that
specific year, you're taking into account.

Appendix A
Nathan South: Got it.
James Gall: That cost of that resource of that year and then that emissions benefit.
So if we you could take say 2045 to look at the cost difference and the emission
difference and then that gives you your cost of carbon and that would imply for future
periods as well.
Nathan South: OK. Thank you.
James Gall: But you know what you bring up is an issue, we modeled, say, 40 years,
you can then get around this levelization and do things that's a little bit more accurate.
But then where do you stop the same issue in 40 years?
Nathan South: Right, right.
James Gall: It just continues on forever.
Nathan South: Yep.
James Gall: So that's why we went to this levelization method. It's not perfect, but it's
the best we can do unfortunately.
Nathan South: Understood. Thank you.
James Gall: Yep. OK, back to nuclear. We originally were going to do a test that
looked at what cost is nuclear cost effective, and we did that. We were going to do that
because there were always questions about why is nuclear not picked, it seems to be
the best option out in the future and Io and behold, it got picked in our PRS. So, we
thought, OK that scenario is not really relevant anymore, so we then went
to let's just put in a large nuclear plant, and I should say that should be nuclear by
2040. Instead, 2045 and see how that impacts the model. And what we did is we added
this nuclear plant early. The plant in the PRS showed up in 2045. This brings it in 2040,
which I'd say, we could probably at the earliest build, 2035 is probably the earliest a
nuclear plant could show up. Some may argue sooner, but the 10-year window is what
we're seeing it as. But in this scenario, we did not retire any resources along with it. I
guess in hindsight, maybe we could look at if you brought on 500 megawatts of
nuclear, you could retire Coyote Springs 2. But we looked at it more as the resources
you would avoid building in this scenario, rather than what you could retire from your
existing fleet. The result was that avoids more natural gas resources for Idaho. And

Appendix A
then for Washington, building a nuclear plant earlier has a big impact on meeting CETA
because it reduces a significant amount of wind that would be added to the system.
The solar that's in the back end, a lot of the energy storage in the back end, the Kettle
Falls Unit 2 biomass facility is wiped out. It makes it a lot easier to meet CETA
obligations with a gigantic clean energy base load plant for Washington. That rate
increase is only around 9%, but for Idaho it's a significant increase. If we assume that
nuclear was allocated to Washington or to Idaho, I guess if you ran a scenario where
the nuclear plant was built and only assigned to Washington customers, and it is a pro
rata share, say 300 megawatts to Washington. See, a nine percent increase in Idaho
would be protected and continue on doing natural gas. But unless nuclear prices come
down, we're going to see a significant rate shock for Idaho customers. From a reliability
perspective, it basically solves a lot of our reliability challenges. I guess one thing to
note here is our planning reserve margin. If you calculated it, it would be, I think by
2045 above our planning target cause Coyote Springs 2 is still on the system, but
nuclear definitely, a large base load unit makes reliability a lot easier to manage in the
out years. If cost comes down for nuclear or if the IRA tax incentives get extended out
20 years for this nuclear plant in the future, then maybe that rate increase is closer to
zero for Washington and Idaho could be significantly reduced. But as you see the
common theme I mentioned earlier, nuclear does solve a lot of issues out in the future
when you're in a resource constrained environment. OK.
James Gall: Moving on. One thing that I'd say that the 2023 IRP spent a fair bit of
time on because it was showing this resource, this power-to-gas or ammonia or
hydrogen resource as cost effective, and we're one of the first ones that show that,
and this continues to be cost effective. The one big difference that we did in this IRP
versus the last IRP is we limited how much the model could pick of this resource
because it wanted to build, I think, 800-900 megawatts of it in the last IRP and that
definitely showed it's an attractive resource. That's one reason why we're seeing
nuclear this time around, because we did limit this resource. And the reason why we
limited it is it basically requires new supply chain of moving hydrogen around the
Northwest. It requires storage of either hydrogen if you're going to use it for, say,
Coyote Springs 2. Or requires a conversion to ammonia for burning in a CT. And so,
we have to have a significant supply chain system built up. There are also significant
energy losses of this technology. It's about a 20% round trip efficiency, so if you look
at how much energy you got to build or have excess energy to create this fuel, you
start to get massive amounts of capacity for renewables. That all may happen. Not
saying it won't happen, but it seemed to be you don't want to put all of your future plans
into one technology that's based upon this new infrastructure. I think a lot of it can be
built. There are definitely groups out there trying to build hydrogen infrastructure, so
it's probably going to happen. It's just a matter of how much of that infrastructure is

Appendix A
going to be built. And how much of it can you rely on? So, we did a scenario here that
basically let's say it didn't happen, and we didn't have power-to-gas as a future, we
wanted to test that. What if you had a limited amount of power-to-gas? We kind of
know what that looks like from the last IRP, but in this case, we would have a need for
more for Idaho.
James Gall: We'll start with Idaho; it reduces the share of wind and increases the
need for natural gas. So why is that? It's because Washington is going to need more
of those wind resources that Idaho was allocated that are again, we have a limited
amount of low-cost wind and if we need to, and if Washington is in a pressure point
where it needs more of those resources to meet CETA then it's going to suck those
up and take those away from Idaho. That's what's happening for the Idaho side of the
service territory, for the Washington side of the service territory, it asked to replace
almost 400 megawatts of power-to-gas. And it does that with energy storage, nuclear,
and then a little bit of wind, solar and demand response. We're replacing 400
megawatts of capacity and it's about a similar capacity total between the energy
storage and nuclear. It's a long duration storage, most likely being picked there, but
from a rates perspective, going back to that 2045 future point in time. Washington
rates around 11% higher. Idaho is around 4% higher and from a reliability perspective,
we're still around that 4% threshold. So, it's a little bit higher than I believe our PRS
was, it was around 3.6%, but still definitely a reliable future without this technology.
But that's mostly due to relying more on nuclear.
James Gall: As I project out in the future, we're really going to go down to pass or
both paths. In the future to meet future load needs with CETA is we got to be paying
attention to nuclear technology. We got to be following power-to-gas technology and
long duration storage. It's those three technologies are really going to be, one of those
or all of those are going to be in the future. And if you look at past Northwest build
outs, there's always a run to a certain technology in a period of time. In the 1980s, it
was coal, and in the early 2000s it was a rush to natural gas. And then we had the
rush to wind. It feels like we were in a rush right now, maybe to solar. And then
definitely a rush to the lithium-ion batteries in California. What's that next rush going
to be? Is it going to be one of those three technologies in the 2030s. So, we wanted
to test what each of those do to our portfolio because we don't know exactly what will
happen, but we'll wait and see.
James Gall: See that comment from Fred Hewitt in regards to your last scenario and
he said the problem with the 500 MW nuclear even assuming optimistic cost
projections is forced outage or single shaft risk. Good point. On the shaft risk if, yeah,
if we had a Vogtle unit two or three on a system our size that is definitely a risk. Now

Appendix A
if we have small modular reactors, those hundred MW sized units that actually would
probably lower our shaft risk. Say, for example, Coyote 2 is at 300 megawatts. Now
we have 100 MW shaft risk, so that is I guess a benefit. We'll see where that
technology goes. If the SMRs can get built then that's good potential option for us. And
if not, then if we have a Vogtle style unit, we're going to have to spread that shaft risk,
hopefully with our neighboring utilities, that they're also willing to go nuclear and I'd
say nothing in this IRP says we're going to go build a nuclear plant, but it's just
illustrating that's the type of technology that's needed to meet some of these goals
with the load projections we have. OK.
James Gall: Next one's on transmission and this goes back to the last TAC meeting
where we talked about the Grid United transmission line that goes from Colstrip to
North Dakota. And we talked about we assumed a 300 MW share of that transmission
line in the PRS that starts in 2032. And what we're trying to do in this scenario is
understand if that path was not built, what would that do to our resource choices. How
would it change? Because 2032 is really from an IRP perspective, not that far away.
We are not testing the cost or the change in cost because of a couple reasons. One
is, at the time we're doing all this analysis, we didn't have the benefit side of the
transmission lines arbitrage between markets. So, we're missing a big component of
the cost benefit analysis. We'll do that separately if we decide to move forward with
this line. We'll have a cost benefit analysis. And two, when we did the initial study, we
found it to be cost effective on a capacity basis alone, but it was spread out over time
and that didn't make rational sense. We put it all into the one year in 2032 when the
line would be built. Again, we're testing here for what's the resource change, not for
cost, as that will come later. What does the model do without this line is the question.
First thing it does is basically replacing capacity so that for that line, the benefit of the
line to the PRS, is it provides basically a clean resource capacity benefit. And now it's
got to go build something on the generation side to replace that in this assumption of
the portfolio. For Idaho, it's building more gas, more energy storage, and it's also
reallocating some wind to Washington. Then on top of that, for Washington, we have
to have more energy storage, a little bit more nuclear, little bit more solar, a little bit
less demand response, surprisingly. But basically, it's use what we have today as
options, but do a little bit more. From a cost benefit in the future, if we make a decision
on this plan, it would also likely be a benefit to customers. That's a lost opportunity,
but again from a total portfolio perspective, it's not a big impact, but it does require
some changes. Especially in the 2030 time period, if we don't have that line. OK.
James Gall: The next one that we're looking at, and we're getting to the end of these,
hopefully no one is asleep, but there are no IRA tax incentives. This study really came
about because we were seeing a lot of wind built early in the portfolio before need.

Appendix A
Basically, the PRS is saying we don't have a need for wind from a CETA perspective,
but it's being picked from a cost-effective point of view, because you have this tax
incentive that's pushing it earlier. And you have high market prices compared to the
price of wind. I want to test if we didn't have the high-rate tax credits or they got
repealed in a future administration, would that change our portfolio, would we get a
different answer? We assumed the IRA benefits of just the wind and solar and nuclear
resources, not the energy efficiency side of the equation, but the generation side, the
PTC and the other tax credits went away. What would happen and what we did see is
actually less wind being picked, about 357 megawatts less wind overall and it's actually
moving some of that wind that was allocated to Idaho over to Washington to replace
that wind that it was reducing. The model is allocating wind to Idaho because it's cost
effective compared to the market price because of the PTC and high prices. But
without that IRA, it's saying, well, Washington's got to go get a bunch of wind anyway,
so I'm going to basically go get what Idaho didn't get, but then in total, it also is saying
we would need more energy storage. Kettle Falls Unit 2 would go away, which actually
the PTC doesn't impact on that period, but it's an interesting result. And then a little bit
more solar and demand response. One of the interesting things though is how it affects
rates and the model at least for Washington, no matter if there's a PTC or not with the
IRA, Washington still has to be 100% clean by 2045 because of CETA. But what it
does is it shifts some of the costs from Washington ratepayers to the federal tax base.
So, in the case without the IRA, Washington customers have to pay for those costs.
Real costs rather than shifting it to the federal government. That's about 2.7% higher
in 2045, the IRA being around is more of a benefit for Washington than Idaho. Because
you're able to save money by basically having a different set of customers pay for the
portion of your costs.
James Gall: Alright, so let's go to number 23. This is actually I'd say, in the top 5
portfolios as far as risks to our system. The other top five ones coming up next, but
the on-system wind limitation. So, we had in our model around 500 megawatts of wind
that could be added to our system without major transmission build outs. And what
happens if, let's say a data center or another utility in the Northwest acquires a wind
facility that's in our BA. We have a balancing area or balancing authority that manages
the generation on the transmission system in our area and we have, if you look at our
transmission queue, there's a lot of wind and lot of solar and batteries that are in that
queue and they are applying to connect to our system. And if they are built and they
connect to our system, that generation could serve Avista's load, or it could serve
another utility's load. Or it could be sold on the open market. Who knows what will
happen to it? So, what we're assuming in this scenario is that some of that 500
megawatts that we think is easy to connect based on that cluster study gets taken off
system and when that gets off system that leaves less generation available to Avista's

Appendix A
customers at a low cost. The scenario basically limits that low cost when the 200
megawatts and what we want to see is what does that do to our portfolio and what it
does is quite shockingly, or not shockingly or not surprising, is we're going to have less
wind on our system and because it's just not economic anymore. Because a lot of that
wind, especially built early in our system, is driven by an economic acquisition rather
than need. Now it does end up stealing more from Idaho. Call it stealing, but it does
have to shift more of that wind to Idaho because it's a limited amount. Actually, I am
just now looking at it. I did not change this. Pull it on the 3rd, so I'm going to have to
punt on this one for what other resource changes were made. But I believe it is mostly
just the loss of wind. This bullet here is same as the previous one. I did not update it,
so I'm going to have to update that one. But on the cost side. Oops, let me go back to
here. I believe these cost ones are accurate, Idaho would have slightly higher rates
and then Washington would have 3.3% higher rates without that low-cost wind. But
I'm going to have to update that bullet there.
James Gall: OK, so going on to the next one, we have two scenarios we ran around
the Northeast CT. The Northeast CT is a natural gas turbine built in 1978 that is located
in the north side of Spokane. It's around 66 megawatts in the winter. I think in the 40s
for summer capability, it's limited to 50 run hours a year and its general purpose is an
emergency generator for our system to provide non-spinning reserves and it's
obviously at the end of its life. It's just a matter of what retirement date do we want to
assign to this resource in the IRP. This IRP assumed 2030, the previous IRP assumed
2035. And we want to test in this plan different years when this unit could basically
retire. What if we retired it now? What if we left it in 2030? What if we retired in 2035?
This project doesn't have any book value to it anymore. It's fully depreciated. It is
definitely able to, as long as we can get parts if something breaks on it, it can continue
to be a fully operational facility. But it does have limitations on how much it can run
really due to emissions, and it does not have the NOx control of say a modern gas
plant would have due to its age. That's why it's limited in its number of hours it can
operate.
James Gall: If we lost this resource today, we decided we're going to retire today,
what would happen? We would have to replace it with energy storage. Around 79
megawatts and we would be then looking at adding some wind earlier. One thing that's
interesting it does from the Idaho side is that because you need the resource early,
there's not enough time to build a gas unit elsewhere on the system to replace it. The
model actually picks less natural gas, and it takes on some of that 79 megawatts of
energy storage. It does build a little bit more gas later, but overall, it builds less gas if
we retired Northeast today. It also gets allocated a little bit more wind. For Washington,
we have less wind and less energy storage, but we do have to pick more nuclear in

Appendix A
the long run, but I think the story here is that if we lost the unit today, we're going to
have to go to energy storage to replace it now, even if we retire in 2030. When we go
through the RFP process, there's a good chance that energy storage could be the
lowest cost, or it could be a gas turbine in Idaho. I don't know what the ultimate decision
will be because we haven't done the RFP yet, but it definitely is a viable option. For
us, cost impact of retiring the plant early is about a 1% rate impact for Idaho in 2030.
Washington really didn't see an impact, but long run they're slightly higher rates for
both states retiring earlier compared to 2030.
James Gall: Shifting if it retired in 2035. We would see a little bit different scenario.
You're basically extending the life of this resource and that would defer the need for
the 90 MW gas plant for Idaho in 2030. Instead, you still need some capacity and that
moves over to energy storage, but in total, once Northeast does retire, you'd have to
replace it with something. And so, it does build a little bit of gas, but not as much as
the PRS from a cost perspective. There's no rate impact until after the resource is
retired, but at the end of the day, Idaho's rates would be about 0.7% higher. Going to
retire later, it's kind of an interesting thing, no matter what. If you retired early or later,
rates are higher in 2045 than the PRS, so looks like 2030 is kind of a sweet spot from
a rate perspective. Although I think the PVRR is lower on your entire in 2035, but no
decision has been made yet on the timing of the resource. More to come, I guess in
time.
James Gall: OK, so I got a few more scenarios to go through. We got 30 minutes. OK,
so I think we're going to make it at least through the remaining scenarios. I don't know
if we're going to get to the summary information, but that's going to be high level
anyway. I guess this is a good reason why next IRP we should do less scenarios. It's
just a bug in your ear and we should probably maybe limit to maybe 10 but this is
where we're at today. This scenario is the maximum Washington customer benefit
scenario. This is required by Washington rule for IRPs. And although I'd say the rule
is kind of kind of on specific requirements, but the I think the intent of this is we have
these Customer Benefit Indicators that we track in the CEIP process. The idea is how
can we improve those CBIs simultaneously, if possible, to a maximum capability. So,
what is the theoretical maximum we could do?You can't maximize everything because
for example, if you increased, we'll call it DER solar, that would have a rate increase
and that would cause a CBI of energy burden to also increase. There's got to be some.
I guess negotiation between each of the CBIs. We put together this list of assumptions
on how this would work. I'm going to go through that and then going to go through
some of the results. The first thing we assumed is there would be an increase in DER
solar and energy storage. And what this would do essentially is this would be more
like community solar. An increase in that benefit, will call of that solar, would go to low-

Appendix A
income customers to help with energy burden. So, it helps that energy burden CBI. It
also helps with the CBI regarding increasing DER solar and storage as well. I'd say
this is an arbitrary value to some extent.
James Gall: The second one is no air emitting resources. In Washington, we have a
CBI that tracks NOx emissions and NOx emissions are a result of burning ammonia.
If we didn't have an ammonia plant, we would have less NOx also for biomass plants
like our Kettle Falls facility, there are air emissions that are either NOx or SO2. So,
you would be removing any new emissions of those facilities. We have CBIs regarding
having more local resources and this next one basically prohibits anything outside of
the state. We did allow the 200 megawatts of Montana wind because it ties together
with that transmission line into the east, but the model was only allowed to build that
200 MW share of Montana wind, but nothing else that was really off of our system. We
also increase the energy efficiency credit requirement that's 10% for the Power Act to
increase that to 20% to have the model acquire more energy efficiency than it would
otherwise. I believe the last time we looked at this, we just let it pick all energy
efficiency that was available. We tried to cap that a little bit in this scenario to adding
just another 10% adder and then for those of you that have been following our
process, the DPAG (the distribution planning process similar to this TAC), they hired
a consultant to help them estimate how much solar and EVs would be on our system
in the future. And that study resulted in two forecasts. One is an expected case, and
the second one is that Named Communities, low-income communities or
disadvantaged communities. However, you want to count them. We ran a scenario to
show what if they had similar solar adoption of adoption as other areas? We got a high
case of solar and EV. So that's included in the study. And then lastly, like I mentioned,
the transmission line to the East is included. What does this do to our results? Well,
obviously you're doing more purposely energy storage and solar. That's going to show
up. But because you're losing the power-to-gas and the biomass, you got to replace
that with something. It's pushing more towards storage, nuclear, demand response
and a little bit more energy efficiency. That's what you're getting compared to the PRS
in this scenario, what you're losing is you are losing a little bit of wind. Obviously, the
biomass, geothermal, those improve the CBI. If you remove them because you're
using either less air emitting resources or more on system resources, geothermal is
likely to be off of our system. And then obviously power-to-gas, that's another air
emitting resource. So, there's a cost impact to this and that's about a 13% rate increase
for Washington in 2045 to have this portfolio look this way versus that preferred case.
James Gall: And then I have this chart here that shows the how the maximum
customer benefit scenario compares to the PRS for 2045 for each of the CBIs. I'm not
going to go through all these, but the intent was to show an improvement, or a modest

Appendix A
improvement, to everything that's on this list that was possible from the CBI. Could
one of them be way better? Yes, but that would likely have an impact on another one.
So, I thought it was a good way to thread the needle on trying to improve all of the
CBIs to some extent to comply with this portfolio requirement. OK.
James Gall: I got a few more to go through. We're going to now shift to resource
adequacy scenarios. The 17% planning margin scenario was trying to replicate what
a future WRAP world may be. In this case, what I mean by WRAP is that we all, as a
region, plan together to have lower planning margins so we can build less resources.
Essentially what this portfolio does is it builds less wintertime resources. Very similar
actually to the scenario where we had the RCP 8.5 scenario that had less winter
capacity as well. Again, obviously it's going to pick less capacity resources, less
natural gas, less energy storage. No surprise there. We also see lower rates. You're
building less capacity. You're going to have lower rates. The thing that concentrated
in really is the resource adequacy assessment. It is higher than it would have been at
24%, but it's still meeting the threshold. We're going to be looking into this a little bit
more on why are we still at 5%. That's good news if we're able to have a 5% LOLP
with 17%, that's good news. We can potentially lower our planning threshold. Although
what's curious is this is because the model is building resources early to comply with
2030. And we actually have a higher than, or we have a closer PRM to 24%. That's
probably what's happening in 2030. But by 2045, is our portfolio because we have so
much nuclear. Maybe or power-to-gas. Is it still complying with a lower PRM? So, we
look into this a little bit more because it could definitely mean that we have too much,
or I say too little capacity credit, for certain resources is maybe one way of looking at
this. But the one challenge we have is the capacity value of a particular resource is
really impacted on what other resources are picked. So, if you have a lot of base load
generation that allows, say, a storage project or maybe a wind project, an improved
ELCC as if we didn't have that other resource there. This is going to have to be a little
bit of an iterative process on what's the appropriate PRM. This is to show in 2045 if
there's maybe an opportunity to lower it.
James Gall: But some may argue that 5% LOLP is too high. We've actually done this
other scenario where we increase the PRM to try to get the model to have near zero
LOLP as possible. We got pretty close in 2045. We're at 0.008, so that's just under 1%
LOLP. Guess we need a higher PRM to get to zero, but the intent was what if we had
a system that had basically zero risk of resource adequacy issues. So, we moved it
up to 30%. We were going to have to acquire more wind in this scenario in the short
run. More energy storage as well. We were about 1.6% in this case, and then Idaho
would be a little bit more gas, a little more energy storage, but in the long run it's adding
basically energy storage. Energy storage seems to be the best way to push this up to

Appendix A
30% if loads aren't growing and we're just trying to get more resource adequacy, more
energy storage seems to be the solution. That leads to slightly higher rates about 1.4%
in 2030. For Washington 1.7% in 2045, 2% higher rates for both states. And that gets
you closer to a 0% loss of load probability. I guess there's an economic question, is
the probability of less outages worth 2%?And I'm not going to decide that, but it makes
you think about is that appropriate? I think if you looked at years past, maybe that extra
resource adequacy might have been worth it. Cost more than 2%. We're looking at
around 2% or less and maybe there is some argument that. Higher or lower LOLP
target is what we should be looking at.
James Gall: My last scenario is related to the election in Washington State and in
Washington State, the Climate Commitment Act is on the ballot to be repealed. I don't
know what's going to happen there, but we wanted to run a scenario that looked at
what would happen if the CCA was repealed. So, what the resource changes would
be? The costs are another challenge, I'll get to that reason why in a little bit. But in
order to do this, we had to create a new price forecast that has the CCA gone. The
CCA basically inflated wholesale prices in the Northwest and without the CCA, we'd
see prices fall. If you're a seller with clean energy, higher prices are good. And if you're
not, if you're a buyer, higher prices are bad. That's why I say the cost is a little bit more
of a challenge because there's a lot of complexities to that market that is created in
Washington, but the focus here is on the resource strategy. Near term, what it did
actually is quite interesting, it pushes back wind a little bit because there's not as much
profit potential for the first wind acquisition and then it reduced the CT in Idaho, and
we shifted generation resources around. In Washington, it actually increased
solar slightly; energy storage, slightly; nuclear slightly. It removed the biomass facility.
It no longer became cost effective. And then demand response increased. Basically,
it had to fill the biomass, swap with nuclear and energy storage. It moved resources
around; the CCA; from a Washington perspective, is not really the driver of resources.
That was not a surprise, that little bit of a shift. The challenge will be in the future. Let's
say the CCA is repealed versus looking at the PRS. Now, you basically have a lower
price forecast. So, when we go out to RFP wind resources, we may have thought
would be cost effective may not be cost effective. That would defer its decision. We'll
wait until November to see what happens. Then the question is would we create a new
PRS? If the CCA is repealed, I don't know if we've made that decision yet, and I don't
think this scenario is, we're not using it. We call it stochastic case for it. So, we'd have
to evaluate. Should we be doing additional work to recreate this Preferred Resource
Strategy on the same rigor as our other studies? Do we leave it as is based on the
portfolio really not changing materially? But it's something we're going to have to ask
ourselves if that happens in November before we file the document in January. Love

Appendix A
feedback on if that happens. Maybe we get back together at the TAC. I don't know yet,
but we'll wait and see what happens.
James Gall: Last thing I have is, and we have about 15 minutes, we're going to explain
what's in these slides and not going to go into depth on them. This is really for you to
look at later, and if you have questions on them, we can definitely answer those. But
this slide is intended to look at the rates and PVRR for each state and how this works
is on the PVRR. The first three columns, that shows what the present value revenue
requirement is for each of the state's portfolios. The little graphic on the arrow up or
down is trying to measure how it compares to the PRS. The rate side is on the right
where we have the 2030 average rate and the 2045 for both states. For all 20, only 25
portfolios are shown here the CCA the no CCA portfolio runs off of a different market
price forecast and it would not be comparable. That's why it's excluded on here.
James Gall: This next one is basically a graphical representation of this table here for
those of you that like charts to see the lowest rate versus what's the highest rate in
rank order. And they're ranked by 2045 rank. Rates for Washington and then we have
Idaho here as well. And then this chart is focusing on comparing Ievelized cost to risk
and what we define by risk here is tail var. We did a calculation of the tail var for each
of the portfolios based on the 300 simulations we did, and we can measure, OK, what
resources have less risk compared to cost. For those of you been following Avista's
RPS for a long time, we used to do what's called an efficient frontier. And this kind of
gets you that idea of measuring cost versus risk because you can see there's some
scenarios that have definitely more cost but a lot less risk. For example, on portfolio 4
on the bottom, the clean resource portfolio, there's significantly less risk than the PRS
in 2045, but it has a slightly higher cost. So, it helps you measure your trade-offs
between what you give up for lowering risk. That's what that one is. And then for those
of you that like PVRR comparisons, this is a rank order PVRR. And this one is basically
the same data as you saw on the first table and then we created this. This one it's
PVRR, but it adds risk to it. So, you have a rank order, a PVRR with risk for those of
you that are interested in that type of analysis. The next one is on emissions. If you
want to know how the emissions are changing. This shows the reduction of emissions
from 2045 versus 2026 where all portfolios have reductions in electric emissions with
the exception of the baseline portfolio, which has slightly higher emissions. And then
for those of you who want to compare emissions to cost, his graphic breaks down the
change in emissions versus the change in carbon emissions cost for all the portfolios.
James Gall: And then to wrap things up, we did stress test a few portfolios with high
and low natural gas prices to see their impacts to the portfolio. How this works, is on
the first line Preferred Resource Strategy, we'd look at if you had higher gas prices or

Appendix A
lower gas prices, how would cost change? Compared to our expected case, obviously
if you have higher gas prices, this is showing that we're going to have higher costs to
serve our load under the Preferred Resource Strategy and lower cost low gas prices.
But this shows in relation to some of the other portfolios where the baseline portfolio
that was heavy on building natural gas, you can see the PRS is less sensitive to natural
gas pricing. That's not a surprise. And then if you had the clean resource portfolio, you
become even less sensitive. The natural gas prices, especially for the Idaho side of
the service territory because you have less gas. And then we threw in the nuclear
scenario as well in here to illustrate the same thing. I think this is a requirement I
believe in the State of Idaho that we look at this analysis. But we want to choose the
portfolios that made the most sense, that had more or less natural gas in it. Then we
did similar analysis with the greenhouse gas emissions, and this basically shows the
change in total emissions. Over the 20 years, if you have differences in gas prices, so
we have higher gas prices, our existing natural gas fleets are going to run less, and
we'll have less emissions. And if you have low gas prices in the future, we will have
more emissions from the gas plants. They will be more in the money, and they will be
more cost effective to run. So, that's available there.
James Gall: That's my last slide. I'm actually shocked I was able to get through them
all with keeping my voice, but what's coming next like John mentioned? At the end of
the month, we're going to release the full version of the IRP draft with the missing
chapters mostly from the scenarios. The market price forecast and the introductions.
We're going to add the table Molly requested on the PRS. We'll have the data for each
of the PRiSM studies. We'll have a summary of all the portfolios available as well,
following John's slides that he mentioned earlier. I just want to pause there if there's
any questions that we have before we call it a day. No questions yet, unless something
pops up shortly. OK, absent any reason to get back together for maybe the CCA
discussion, this will be our last TAC meeting. We do have the public meeting you're
definitely invited to come to in November. I believe there will be meetings on the IRP
by both commissions at some point in time. I don't think those have been scheduled
yet to review the IRPs, but absent any questions, I'll keep rambling in case something
comes up. But I just want to thank everybody for hanging in there with us through this
last year and a half. We appreciate the questions that are asked. Definitely the interest
in Avista and in its resource future. Because we did not come up with all this stuff on
our own, we do rely on other people like yourselves to help us refine what the study
helps us find good data sources because we're all kind of working through this together
and appreciate involvement. Also, the changes in how we've done TACs, we hope that
the shorter meetings that are more frequent have been helpful. They're definitely a lot
more work on our side. We're going to be thinking about how we keep short meetings
in the future, but also be able to keep up with the quantity of work at the pace we have

Appendix A
for the next IRP. We may be reaching out to a few of you to help us navigate what the
2027 IRP looks like. That is fast approaching.
James Gall: Any questions or comments? Thank you. Alright, we still have people
awake. That's a good sign. Again, thank you, if you have questions, please reach out
to us through the Teams site or e-mail. The public process I know will be beginning in
each state, so we look forward to reading people's opinions and comments on the IRP
and again the IRP is really a stage that's set for an RFP for resource acquisition where
it meets the road. I guess you could say when we go to actually meet, require
resources, and then the CEIP process for Washington will be kicking off in January for
the 2026 through 2029 time period. We'll see what remains of this IRP that makes it
into that plan. I think I rambled enough. There's no questions yet. So again, thank you
and hopefully we'll have a draft out for you guys to read soon.
James Gall: stopped transcription

Appendix B
2025 Electric Integrated
Resource Plan
Appendix B — Work Plan

Appendix B
Work Plan for Avista's
2025 Electric Integrated Resource Plan
For the
Technical Advisory Committee,
Washington Utilities and Transportation Commission,
Idaho Public Utility Commission
Updated on December 5, 2023
1

Appendix B
2025 Electric Integrated Resource Planning (IRP) Work Plan
This plan outlines the process Avista will follow to develop its 2025 Electric IRP for filing with
the Washington and Idaho Commissions by January 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 electric needs. Avista posts all meetings announcements,meeting
minutes, videos, final IRP documents and data on its website at https://www.myavista.com/about-
us/integrated-resource-planning. Avista will communicate with its TAC members through email
and Microsoft Teams for any meeting information 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 be similar to previous IRPs, although Avista intends to include new
modeling processes in this IRP cycle. Avista recently acquired the PLEXOS model from Energy
Exemplar. PLEXOS will be used to model resource dispatch, resource option valuation, and
market risk analysis. Avista plans to continue to use PRISM' for resource selection but intends to
investigate PLEXOs' ability to provide this functionality in a timely manner for both jurisdictions
while handling energy efficiency selection. IRP modeling with PLEXOS has the potential to
handle more complex resource decisions but it may limit transparency and speed compared with
the PRiSM model. Avista intends to continue to use Aurora for electric market price forecasting
although Avista intends to evaluate options for electric market price forecasting for the 2027
Progress Report/IRP.
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 and peak load forecast using end use techniques to improve estimates for
building and transportation electrification scenarios. AEG is also leading a distribution energy
resource (DER) potential study for Avista. This study includes locational forecasts for electric
vehicles,roof-top solar,energy storage, energy efficiency, and demand response. The Distribution
Planning Advisory Group (DPAG)will use this study for its planning process. Avista also intends
to align the IRP's load forecast and resource options with this study.
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 generating
technologies, engineering studies,vendor estimates, Pacific Northwest National Lab (PNNL), and
the Northwest Power and Conservation Council's studies to estimate resource costs. 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 Power Purchase Agreements (PPA) rather than Company ownership if third
party ownership is likely to be lower cost. Avista will likely not model potential contracts with
existing regional generating resources due to lack of price certainty. Future Requests for Proposals
'PRiSM is Avista's proprietary model it uses to select new resources.Avista first developed this tool for use in the
2003 IRP.
2

Appendix B
(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 Clean Energy Transformation Act (CETA) and the Climate
Commitment Act(CCA) for Washington and using the least cost planning methodology 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,
capacity requirements using Western Resource Adequacy Program (WRAP)2 metrics, and
Avista's energy and capacity planning standards.
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 electric market and public policy, such as
transportation 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.
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: Tuesday, September 26, 2023: 8:30 am to 12:00 pm (PST)
o WA CEIP Biannual Update
o Available Resource Options Discussion
o PLEXOS Overview and Backcast Analysis
o TAC feedback on changes to process, methods, assumptions
o Work Plan and IRP Process Review
• TAC 2: Tuesday, January 30, 2024: 8:30 am to 12:00 pm (PST)
o How Avista includes Equity Principles
o Customer Benefit Indicators
o How Avista Practices Equitable Outcomes
o Equity Planning in the IRP
2 Avista proposes to use the same methodology as described in the 2023 IRP for capacity planning until the WRAP
provides estimates for long range resource Qualifying Capacity Credits(QCC)and the WRAP becomes binding for
their proposed Planning Reserve Margin(PRM).
3

Appendix B
• TAC 3: March 21, 2024: 8:30 to 12:00 (PST)
o Natural Gas Market Overview and Price Forecast
o Wholesale Electric Price Forecast
o Variable Energy Resource Integration Study Results
o Future Climate Analysis Update
o TAC Scenarios or Feedback
• TAC 4: April 25, 2024: 9:00am to 3:00pm (PST)
o Economic Forecast and Five-year Load Forecast
o Long run Load Forecast(AEG)
o Conservation Potential Assessment(AEG)
o Demand Response Potential Assessment(AEG)
o Review Planned Scenario Analysis
• TAC 5: May 7, 2024: 8:30am to 12:00pm (PST)
o IRP Generation Option Transmission Planning Studies
o Distribution System Planning within the IRP & DPAG update
o T&D Modeling in the IRP
o Load& Resource Balance and methodology
o New Resources Options Costs and Assumptions
• TAC 6: Technical Modeling Workshop: June 25, 2024: 9:00 am to 12:00pm
(PST) (Virtual Only)
o PLEXOS Tour
o PRiSM Model Tour
o New Resource Cost Model
• TAC 7: July 16, 2024: 9am to 4pm (PST)
o Preferred Resource Strategy Results
o Washington Customer Benefit Indicator Impacts
o Resiliency Metrics
o Portfolio Scenario Analysis
o Market Risk Assessment
o QF Avoided Cost
• Virtual Public Meeting-Natural Gas &Electric IRP(September 2024)
o Recorded presentation
o Daytime comment and question session(12pm to 1pm- PST)
o Evening comment and question session (6pm to 7pm- PST)
4

Appendix B
2025 Electric IRP Report Outline
This section provides a draft outline of the expected major sections in the 2025 Electric IRP.
Executive Summary
1. Introduction, Stakeholder Involvement, and Process Changes
2. Economic and Load Forecast
a. Economic Conditions
b. Avista Energy&Peak Load Forecasts
c. Load Forecast Scenarios
3. Existing Supply Resources
a. Avista Resources
b. Contractual Resources and Obligations
c. Customer Generation Overview
4. Long-Term Position
a. Regional Capacity Requirements
b. Energy Planning Requirements
c. Reserves and Flexibility Assessment
5. Distributed Energy Resources Options
a. Energy Efficiency Potential
b. Demand Response Potential
c. Generating and Energy Storage Resource Options and Potential
d. Named Community Actions
e. DER Study Conclusions
6. Supply-Side Resource Options
a. New Resource Options
b. Avista Plant Upgrade Opportunities
c. Non-Energy Impacts
7. Transmission Planning&Distribution
a. Overview of Avista's Transmission System
b. Transmission Construction Costs and Integration
c. Merchant Transmission
d. Overview of Avista's Distribution System
8. Market Analysis
a. Wholesale Natural Gas Market Price Forecast
b. Wholesale Electric Market Price Forecast
c. Scenario Analysis
9. Preferred Resource Strategy
a. Preferred Resource Strategy
b. Market Exposure Analysis
c. Avoided Cost
10. Portfolio Scenarios
a. Portfolio Scenarios
b. Market Scenario Impacts
11. Washington Clean Energy Action Plan (CEAP)
a. Decision Making Process
b. Resource Need
c. Resource Selection
d. Customer Benefit Indicators
12. Action Plan
5

Appendix B
Draft IRP will be available to the public on August 30, 2024, and the final draft filed with
Idaho and Washington Commissions on January 2, 2025. Comments from TAC members are
expected back to Avista by November 15, 2024, or through Washington's 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.
Exhibit 1: Major 2025 Electric IRP Assumption Timeline
Task Target Date
Market Price Assumptions December 2023
CCA/Other GHG Pricing Assumptions
Natural gas price forecast
Regional resources and roads forecast
Electric price forecast March 2024
New Resource Options Cost&Availability March 2024
AEG Deliverables April 1, 2024
Final Energy& Peak Load Forecast
Energy Efficiency and Demand Response Potential Assessment
Locational Energy Efficiency and Demand Response Potential
Transmission& distribution studies complete April 2024
Due date for study requests from TAC members March 20, 2024
Determine portfolio &market future studies May 2024
Finalize resource selection model assumptions June 1, 2024
Preliminary 2027 Progress Report/IRP Outline
Avista intends to replicate the 2025 IRP process for the 2027 Progress Report/IRP. Avista intends
to file this IRP on January 2, 2027,with a public draft available October 15, 2026,Avista will file
a complete workplan for this process by October 1, 2025.
Equity Advisory Group Tentative Schedule 2023-2024
Avista is currently working with EAG members on the tentative schedule for 2024 which is shown
in Exhibit 2. The Company continues to take a proactive approach in selecting discussion topics
with the EAG versus a prescriptive approach with their time and efforts. Once meeting dates/times
and agenda topics are solidified for 2024, Avista will post the meeting information, along with
how to join, on its clean energy webpage.
6

Appendix B
Exhibit 2: Equity Advisor Group Schedule
Date Time Topic
October 20, 2023 7:30 9:00 a.m. Named Communities Investment Fund
Rates
November 17, 2023 7:30—9:00 a.m. Clean Energy Benefits Customer Benefit
Indicators
December 2023 EAG Break
January 17, 2024 12:00— 1:30 p.m. TBD
January 19, 2024 7:30—9:00 a.m.
February 21, 2024 12:00— 1:30 p.m. TBD
February 23, 2024 7:30—9:00 a.m.
March 20, 2024 12:00— 1:30 p.m. TBD
March 22, 2024 7:30—9:00 a.m.
April 17, 2024 12:00— 1:30 p.m. TBD
Aril 19, 2024 7:30—9:00 a.m.
May 15, 2024 12:00— 1:30 p.m. TBD
May 17, 2024 7:30—9:00 a.m.
June 19, 2024 12:00— 1:30 p.m. TBD
June 21, 2024 7:30—9:00 a.m.
July 17, 2024 12:00— 1:30 p.m. TBD
July 19, 2024 7:30—9:00 a.m.
August 21, 2024 12:00— 1:30 p.m. TBD
August 23, 2024 7:30—9:00 a.m.
September 18, 2024 12:00— 1:30 p.m. TBD
September 20, 2024 7:30—9:00 a.m.
October 16, 2024 12:00— 1:30 p.m. TBD
October 18, 2024 7:30—9:00 a.m.
November 13, 2024 12:00— 1:30 p.m. TBD
November 15, 2024 7:30—9:00 a.m.
recemb
ber 18, 2024 12:00— 1:30 p.m. TBD
er 20, 2024 7:30—9:00 a.m.
7

Appendix C
2025 Electric Integrated
Resource Plan
Appendix C — AEG Conservation
and Demand Response
Potential Assessments

Appendix C
AEG
AVISTA ELECTRIC
CONSERVATION POTENTIAL
ASSESSMENT FOR 2026-2045
Prepared for:Avista Corporation
By:Applied Energy Group, Inc.
Date:August 30, 2024
AEG Key Contact:Andy Hudson I Phone#[phone]

Appendix C
Avista Electric 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 R. Strange
N.Yung C. Lee
K. Billeci L.Tang
L. Khan C. Struthers
Applied Energy Group,Inc.I appliedenergygroup.com 2 of 89

Appendix C
Avista Electric Conservation Potential Assessment for 2026-2045
Contents
11 Introduction .............................................................................................................9
Summary of Report Contents......................................................................................................... 10
Abbreviations and Acronyms ......................................................................................................... 10
2 Energy Efficiency Analysis Approach and Development............................................... 12
Overview of Analysis Approach ...................................................................................................... 12
LoadMAP Model............................................................................................................................................. 12
Definitionsof Potential................................................................................................................................... 13
Market Characterization................................................................................................................................. 14
BaselineProjection ........................................................................................................................................ 15
Conservation Measure Analysis...................................................................................................................... 16
DataDevelopment........................................................................................................................ 18
AvistaData..................................................................................................................................................... 18
Northwest Energy Efficiency Alliance Data...................................................................................................... 18
Northwest Power and Conservation Council Data........................................................................................... 19
AEGData ....................................................................................................................................................... 19
Other Secondary Data and Reports................................................................................................................. 19
DataApplication ...........................................................................................................................20
Data Application for Market Characterization..................................................................................................20
Data Application for Market Profiles................................................................................................................20
Data Application for Baseline Projection.........................................................................................................21
Conservation Measure Data Application........................................................................................................A-1
Data Application for Achievable Technical Potential.......................................................................................A-2
3 Energy Efficiency Market Characterization ................................................................. A-
4
EnergyUse Summary ...................................................................................................................A-4
ResidentialSector........................................................................................................................A-5
CommercialSector......................................................................................................................A-8
IndustrialSector ........................................................................................................................A-11
41 Baseline Projection .................................................................................................. A-
14
Residential Sector Baseline Projections.......................................................................................A-14
Commercial Sector Baseline Projections.....................................................................................A-17
Industrial Sector Baseline Projections.........................................................................................A-20
Summary of Baseline Projections Across Sectors and States........................................................A-23
5 1 Conservation Potential............................................................................................. A-
25
Overall Summary of Energy Efficiency Potential ...........................................................................A-25
Summary of Annual Energy Savings .............................................................................................................A-25
Summary of Conservation Potential by Sector .............................................................................A-27
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Residential Conservation Potential .............................................................................................A-28
Commercial Conservation Potential............................................................................................A-33
Industrial Conservation Potential................................................................................................A-38
61 Demand Response Potential..................................................................................... A-
44
StudyApproach .........................................................................................................................A-44
Market Characterization.............................................................................................................A-44
BaselineForecast ......................................................................................................................A-45
CustomerCounts........................................................................................................................................A-45
Summer and Winter Peak Load Forecasts by State.......................................................................................A-46
Characterize Demand Response Program Options.......................................................................A-47
ProgramDescriptions..................................................................................................................................A-48
Program Assumptions and Characteristics..................................................................................................A-51
Integrated DR Potential Results...................................................................................................A-54
SummaryTOU Opt-in Scenario....................................................................................................................A-54
SummerOpt-in TOU Scenario......................................................................................................................A-55
WinterOpt-in TOU Scenario.........................................................................................................................A-58
LevelizedCosts...........................................................................................................................................A-61
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List of Figures
Figure 2-1 LoadMAP Analysis Framework..............................................................................................13
Figure 2-2 Approach for Conservation Measure Assessment..................................................................17
Figure 3-1 Sector-Level Electricity Use in Base Year 2021,Washington ..................................................A-4
Figure 3-2 Sector-Level Electricity Use in Base Year 2021, Idaho ...........................................................A-5
Figure 3-3 Residential Electricity Use and Winter Peak Demand by End Use,Washington .......................A-7
Figure 3-4 Residential Electricity Use and Winter Peak Demand by End Use, Idaho.................................A-7
Figure 3-5 Residential Intensity by End Use and Segment,Washington ..................................................A-8
Figure 3-6 Residential Intensity by End Use and Segment, Idaho............................................................A-8
Figure 3-7 Commercial Electricity Use and Winter Peak Demand by End Use,Washington ...................A-10
Figure 3-8 Commercial Electricity Use and Winter Peak Demand by End Use, Idaho.............................A-10
Figure 3-9 Commercial Electric Intensity by End Use and Segment,Washington ..................................A-11
Figure 3-10 Commercial Electric Intensity by End Use and Segment, Idaho..........................................A-11
Figure 3-11 Industrial Electricity Use and Winter Peak Demand by End Use, All Industries,
Washington......................................................................................................................................A-12
Figure 3-12 Industrial Electricity Use and Winter Peak Demand by End Use,All Industries, Idaho ..............A-
13
Figure 4-1 Residential Baseline Projection by End Use,Washington ....................................................A-15
Figure 4-2 Residential Baseline Projection by End Use-Annual Per Household,Washington ................A-16
Figure 4-3 Residential Baseline Projection by End Use, Idaho..............................................................A-17
Figure 4-4 Residential Baseline Projection by End Use-Annual Per Household, Idaho..........................A-17
Figure 4-5 Commercial Baseline Projection by End Use,Washington...................................................A-19
Figure 4-6 Commercial Baseline Sales Projection by End Use — Annual Use per Square Foot,
Washington......................................................................................................................................A-19
Figure 4-7 Commercial Baseline Projection by End Use, Idaho............................................................A-20
Figure 4-8 Commercial Baseline Sales Projection by End Use — Annual Use per Square Foot, Idaho
........................................................................................................................................................A-20
Figure 4-9 Industrial Baseline Projection by End Use(GWh),Washington.............................................A-21
Figure 4-10 Industrial Baseline Sales Projection by End Use — Annual Use per Employee,
Washington......................................................................................................................................A-22
Figure 4-11 Industrial Baseline Projection by End Use(GWh), Idaho ....................................................A-22
Figure 4-12 Industrial Baseline Sales Projection by End Use—Annual Use per Employee, Idaho ................A-
23
Figure 4-13 Baseline Projection Summary(GWh),Washington and Idaho Combined ............................A-24
Figure 5-1 Cumulative Energy Efficiency Potential as a%of Baseline Projection,Washington...............A-26
Figure 5-2 Cumulative Energy Efficiency Potential as a%of Baseline Projection, Idaho ........................A-27
Figure 5-3 Achievable Technical Conservation Potential by Sector, Washington and Idaho
Combined........................................................................................................................................A-28
Figure 5-4 Residential Cumulative Conservation Potential,Washington ..............................................A-29
Figure 5-5 Residential Cumulative Conservation Potential, Idaho........................................................A-29
Figure 5-6 Residential Cumulative Achievable Technical Potential by End Use,Washington .................A-30
Figure 5-7 Residential Cumulative Achievable Technical Potential by End Use, Idaho...........................A-32
Figure 5-8 Commercial Cumulative Conservation Potential,Washington.............................................A-34
Figure 5-9 Commercial Cumulative Conservation Potential, Idaho......................................................A-35
Figure 5-10 Commercial Cumulative Achievable Technical Potential by End Use,Washington..............A-35
Figure 5-11 Commercial Cumulative Achievable Technical Potential by End Use, Idaho .......................A-37
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Figure 5-12 Industrial Cumulative Conservation Potential as a % of the Baseline Projection,
Washington......................................................................................................................................A-39
Figure 5-13 Industrial Cumulative Conservation Potential as a % of the Baseline Projection, Idaho
........................................................................................................................................................A-40
Figure 5-14 Industrial Cumulative Achievable Technical Potential by End Use,Washington..................A-40
Figure 5-15 Industrial Cumulative Achievable Technical Potential by End Use, Idaho............................A-42
Figure 6-1 Demand Response Analysis Approach...............................................................................A-44
Figure 6-2 Coincident Peak Load Forecast by State(Summer).............................................................A-47
Figure 6-3 Coincident Peak Load Forecast by State(Winter)................................................................A-47
Figure 6-4 Summary of Integrated TOU Opt-In Potential(MW @ Generator)..........................................A-55
Figure 6-5 Summary of Summer Potential by Option—TOU Opt-In(MW @ Generator)...........................A-56
Figure 6-6 Summer Potential by Class—TOU Opt-In(MW @Generator),Washington ............................A-57
Figure 6-7 Summer Potential by Class—TOU Opt-In(MW @Generator), Idaho......................................A-58
Figure 6-8 Summary of Winter Potential by Option—TOU Opt-In(MW @ Generator)..............................A-59
Figure 6-9 Winter Potential by Class—TOU Opt-In(MW @Generator),Washington ...............................A-60
Figure 6-10 Winter Potential by Class—TOU Opt-In(MW @Generator), Idaho.......................................A-61
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List of Tables
Table 1-1 Explanation of Abbreviations and Acronyms...........................................................................11
Table 2-1 Overview of Avista Analysis Segmentation Scheme.................................................................14
Table 2-2 Number of Measures Evaluated.............................................................................................18
Table 2-3 Data Applied for the Market Profiles.......................................................................................21
Table 2-4 Data Needs for Baseline Projection and Potentials Estimation in Load MAP ..............................22
Table 2-5 Residential Electric Equipment Standards..............................................................................23
Table 2-6 Commercial and Industrial Electric Equipment Standards......................................................A-1
Table 2-7 Data Needs for Measure Characteristics in Load MAP.............................................................A-2
Table 3-1 Avista Sector Control Totals(2021),Washington....................................................................A-4
Table 3-2 Avista Sector Control Totals(2021), Idaho.............................................................................A-5
Table 3-3 Base Year Electric Consumption Summary(Control Totals),Washington ................................A-6
Table 3-4 Base Year Electric Consumption Summary(Control Totals), Idaho..........................................A-6
Table 3-5 Base Year Electric Consumption Summary(Control Totals),Washington ................................A-9
Table 3-6 Base Year Electric Consumption Summary(Control Totals), Idaho..........................................A-9
Table 3-7 Base Year Electric Consumption Summary(Control Totals),Washington ..............................A-12
Table 3-8 Base Year Electric Consumption Summary(Control Totals), Idaho........................................A-12
Table 4-1 Residential Baseline Sales Projection by End Use(GWh),Washington ..................................A-15
Table 4-2 Residential Baseline Sales Projection by End Use(GWh), Idaho............................................A-16
Table 4-3 Commercial Baseline Sales Projection by End Use(GWh),Washington.................................A-18
Table 4-4 Commercial Baseline Sales Projection by End Use(GWh), Idaho..........................................A-18
Table 4-5 Industrial Baseline Projection by End Use(GWh),Washington..............................................A-21
Table 4-6 Industrial Baseline Projection by End Use(GWh), Idaho .......................................................A-21
Table 4-7 Baseline Projection Summary(GWh),Washington and Idaho Combined...............................A-23
Table 5-1 Summary of Energy Efficiency Potential,Washington...........................................................A-25
Table 5-2 Summary of Energy Efficiency Potential, Idaho ....................................................................A-26
Table 5-3 Achievable Technical Conservation Potential by Sector, Washington and Idaho
Combined........................................................................................................................................A-27
Table 5-4 Residential Conservation Potential,Washington..................................................................A-28
Table 5-5 Residential Conservation Potential, Idaho...........................................................................A-29
Table 5-6 Residential Top 20 Measures in 2045,Washington...............................................................A-31
Table 5-7 Residential Top Measures in 2045, Idaho.............................................................................A-33
Table 5-8 Commercial Conservation Potential,Washington................................................................A-34
Table 5-9 Commercial Conservation Potential, Idaho.........................................................................A-34
Table 5-10 Commercial Top 20 Measures in 2045,Washington ...........................................................A-36
Table 5-11 Commercial Top 20 Measures in 2045, Idaho.....................................................................A-38
Table 5-12 Industrial Conservation Potential,Washington ..................................................................A-39
Table 5-13 Industrial Conservation Potential, Idaho............................................................................A-39
Table 5-14 Industrial Top 20 Measures in 2045,Washington................................................................A-41
Table 5-15 Industrial Top 20 Measures in 2045, Idaho.........................................................................A-43
Table 6-1 Market Segmentation.........................................................................................................A-45
Table 6-2 Baseline Customer Forecast by Customer Class,Washington..............................................A-46
Table 6-3 Baseline Customer Forecast by Customer Class, Idaho.......................................................A-46
Table 6-4 Baseline July Summer System Peak Load (MW @Generation)by State ..................................A-46
Table 6-5 Baseline February Winter System Peak Forecast(MW @Generation)by State........................A-46
Table 6-6 DSM Steady-State Participation Rates(Percent of Eligible Customers)..................................A-52
Table 6-7 DSM Per Participant Impact Assumptions ...........................................................................A-53
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Table 6-8 Summary of Integrated TOU Opt-in Potential(MW @ Generator),Summer ............................A-54
Table 6-9 Summary of Integrated TOU Opt-in Potential(MW @ Generator),Winter...............................A-55
Table 6-7 Summary of Summer Potential by Option—TOU Opt-In(MW @ Generator)............................A-56
Table 6-8 Summer Potential by Class—TOU Opt-In(MW @ Generator),Washington.............................A-57
Table 6-9 Summer Potential by Class—TOU Opt-In(MW @ Generator), Idaho......................................A-57
Table 6-13 Summary of Winter Potential by Option—TOU Opt-In(MW @ Generator).............................A-59
Table 6-14 Winter Potential by Class—TOU Opt-In(MW @Generator),Washington ..............................A-60
Table 6-15 Winter Potential by Class—TOU Opt-In(MW @Generator), Idaho........................................A-60
Table 6-16 Levelized Program Costs and Potential(TOU Opt-In)..........................................................A-62
Table B- 1 Measure Ramp Rates Used in CPA......................................................................................B-1
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Appendix C
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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 electric CPA.
Notable updates from prior CPAs include:
The analysis base year was updated to incorporate the full calendar year of data for 2021.
For the 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). In particular, light-emitting diode (LED) lamps continue to drop in price
and provide a significant opportunity for savings, even accounting for RTF market
transformation assumptions.
The study incorporates updated forecasting assumptions that align with the most recent Avista
load forecast.
A new Department of Energy (DOE) Heat Pump Water Heater (HPWH) standard, making
residential HPWHs baseline in 2029, was published on April 30th. Ordinarily, forecast
assumptions would have been frozen by that point in the study process, but given the impact
on both baseline and major savings measures within the CPA, it was incorporated into the
forecast and models rerun to account for its impact.
Solar and EV projections from the DER study in Washington were incorporated into Baseline
forecasts.
o Solar and EV projections for Idaho were provided by Avista
Enhancement retained from the previous CPA include:
Analysis of economic potential was excluded from this study. Avista will screen for cost-
effective opportunities directly within the IRP model. As such, economic potential and
achievable potential have been replaced by an Achievable Technical Potential case.
In addition to analyzing annual energy savings, the study also estimated the opportunity for
reduction of summer and winter peak demand.This involved a full characterization by sector,
segment, and end use of peak demand in the base year.
The residential segmentation differentiates low income customers from others, with unique
market characterization, building shell and usage characteristics.
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NEEA's 2019 Commercial Building Stock Assessment(CBSA)was used for characterization of
the Commercial sector
The industrial sector, while relatively small for Avista's territory, separates the pumping and
general manufacturing segments for a better understanding of available potential than prior
studies.
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, summarizing the approach, assumptions, and
results of the electric CPA.
Chapter 2 — Energy Efficiency Analysis Approach and Data Development. A detailed
description of AEG's approach to estimatingthe energy efficiency potential and documentation
of data sources used.
Chapter 3— Energy Efficiency Market Characterization presents how Avista's customers use
electricity 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 — Demand Response Potential. Demand response potential results for each state
across all sectors and separately for each sector.
Appendices A through D provide backup detail on market profiles, market adoption (ramp)
rates, measure data, and demand response.
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
Table 1-1 provides a list of abbreviations and acronyms used in this report, along with an
explanation.
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Table 1-1 Explanation of Abbreviations and Acronyms
Acronym ExpLanation
A/C Air Conditioning
AEG Applied Energy Group
AEO ETA's Annual Energy Outlook forecast
AMI Advanced Metering Infrastructure
BEST AEG's Building Energy Simulation Tool
BYOT Bring Your Own Thermostat
C&I Commercial and Industrial
CBSA NEEA's Commercial Building Stock Assessment
CPA Conservation Potential Assessment
DEER California Database for Energy Efficient Resources
DEEM AEG's Database of Energy Efficiency Measures
DLC Direct Load Control
DR Demand Response
DSM Demand Side Management
EIA U.S. Energy Information Administration
EPRI Electric Power Research Institute
EUI Energy Use Index
EVSE Electric Vehicle Supply Equipment
HVAC Heating Ventilation and Air Conditioning
IFSA NEEA's Industrial Facilities Site Assessment
IRP Integrated Resource Plan
LCOE Levelized cost of energy
LED Light Emitting Diode Lamp
LoadMAP AEG's Load Management Analysis and Planning'"tool
MW Megawatt
MWh Megawatt Hour
NEEA Northwest Energy Efficiency Alliance
NREL National Renewable Energy Laboratory
NWPCC Northwest Power and Conservation Council
O&M Operations and Maintenance
PTR Peak Time Rebate
RTF NWPCC's Regional Technical Forum
RBSA NEEA's Residential Building Stock Assessment
TOU Time-of-Use
UEC Unit Energy Consumption
VPP Variable Peak Pricing
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21 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
61
Overview of Analysis Approach
To perform the potential analysis,AEG used a bottom-up approach followingthe major steps listed
below.These steps are described in more detail throughout this section.
1. Perform a market characterization to describe sector-level electricity use forthe residential,
commercial, and industrial sectors for the base year 2021.
2. Develop a baseline projection of energy consumption and peak demand by sector,
segment, and end use for 2021 through 2045.
3. Define and characterize several hundred conservation measures to be applied to all
sectors, segments, and end uses.
4. Estimate Technical and Achievable Technical Potential at the measure level in terms of
energy and peak demand impacts from conservation measures for 2026-2045.
AEG used its Load Management Analysis and Planning tool(LoadMAP'")version 5.0 to develop both
the baseline projection and the estimates of potential. AEG developed LoadMAP in 2007 and has
enhanced it over time, using it for the Electric Power Research Institute (EPRI) National Potential
Study and numerous utility-specific forecasting and potential studies since that time. Built in
Excel, the LoadMAP framework (see Figure 2-1) is both accessible and transparent and has the
following key features:
Embodies the basic principles of rigorous end-use models (such as EPRI's REEPS and
COMMEND) but in a more simplified, accessible form.
Includes stock-accounting algorithms that treat older, less efficient appliance/equipment
stock separately from newer, more efficient equipment. Equipment is replaced according to
the measure life and appliance vintage distributions defined by the user.
Balances the competing needs of simplicity and robustness. 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 for varying
importance and availability of data resources.
Isolates new construction from existing equipment and buildings and treats purchase
decisions for new construction and existing buildings separately.
Uses a simple logic for appliance and equipment decisions. Other models available for this
purpose embody complex decision-choice algorithms or diffusion assumptions. 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 for
lighting is distinct from refrigerators and freezers.
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Can accommodate various levels of segmentation. Analysis can be performed at the sector
level (e.g., total residential) or for customized segments within sectors (e.g., housing type or
income level).
Can incorporate conservation measures, demand-response options, combined heat and
power, 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.
Figure 2-1 LoadMAP Analysis Framework
Base-year Energy Forecast Energy Efficiency
Market Profiles Consumption Assumptions Analysis Forecast Results
• Market size and By energy • Customer, • List of measures • Baseline end use
segmentation source, growth,energy • Saturations and projection
• Equipment technology, prices, applicabilities • Energy efficiency
saturation end use, elasticities . Measure costs projections
• Vintage segment,vintage Efficiency • Technical
d
g an sector • Lifetime
distribution options,codes . Adoption rates • Achievable
• Unit energy and standards, Techical
purchase shares • Avoided costs
consumption • Cost- IRP Inputs
• Existing and new effectiveness • Utility Costs
construction • Levelized cost
of energy
($/MWh)
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
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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 B.
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
VariableDimension Segmentation . .
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 Cooling,lighting,water heat, motors,etc.(as appropriate by sector)
5 Appliances/end uses and Technologies such as lamp type,air conditioning equipment, motors by
technologies application,etc.
6 Equipment efficiency Baseline and higher-efficiency options as appropriate for each technology
levels for new purchases
With the segmentation scheme defined,AEG then performed a high-level market characterization
of electricity 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, energy consumption, and peak demand matched
the Avista system totals from billing data.This information provided control totals at a sector level
for calibrating Load MAP to known data for the base year.
Market Profiles
The next step was to develop market profiles for each sector, customer segment, end use, and
technology. The market profiles provide the foundation for the development of the baseline
projection and the potential estimates.A market profile includes the following elements:
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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 overall electricity use.
Saturations define the fraction of homes or square feet with the various technologies (e.g.,
homes with electric space heating).
UEC (unit energy consumption) or EUI (energy use index) describes the amount of energy
consumed in 2021 by a specific technology in buildings that have the technology. UECs are
expressed in kWh/household for the residential sector, and EUIs are expressed in kWh/square
foot for the commercial sector.
Annual Energy Intensity for the residential sector represents the average energy use for the
technology across all homes in 2021 and is the product of the saturation and UEC. The
commercial sector represents the average use forthe technology across allfloor space 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 GWh.
Peak Demand for each technology, summer peak and winter peak, is calculated using peak
fractions of annual energy use from AEG's load shape library and Avista system peak data.
The market characterization is presented in Chapter 3, and market profiles are presented in
Appendix A.
Baseline Projection
The next step was to develop the baseline projection of annual electricity use and peak demand
for 2021 through 2045 by customer segment and end use without new utility programs.The savings
from past programs are embedded in the forecast,but the baseline projection assumes that those
past programs cease to exist in the future. Possible savings from future programs are captured by
the potential estimates.The 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:
Current economic growth forecasts(i.e., customer growth, income growth)
Electricity price forecasts
Trends in fuel shares and equipment saturations
Existing and approved changes to building codes and equipment standards
Avista's internally developed sector-level projections for electricity sales
AEG also developed a baseline projection for summer and winter peaks by applying peak fractions
from the market profiles to the annual energy forecast in each year. The baseline projection is
presented in Chapter 4.
' The April 2024 federal heat pump water heater standard was also included as an exception to this cutoff
point
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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 along with the 2021 Power Plan's updated ramp rates to identify achievable technical
measure potential.
Conservation Measures
Figure 2-2 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, and calculating the levelized cost of
conserved energy(LCOE). 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.
Since an economic screen was not performed in this study, we calculated the LCOE for each
measure evaluated. This value, expressed in dollars per megawatt hour ($/MWh) saved, can be
used byAvista's IRP model to evaluate measure economics.To calculate a measure's LCOE,first-
year measure costs, annual non-energy impacts, and annual operations and maintenance (O&M)
costs are levelized over a measure's lifetime, then divided by the first-year savings in MWh. Note
that while non-energy benefits are typically included in the numerator of a traditional Total
Resource Cost economic screen, the LCOE benefits have not been monetized. Therefore, these
benefits are instead subtracted from the cost portion of the test. These non-energy benefits are
not included in the Utility Cost Test used in Idaho.
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Figure 2-2Approach for Conservation Measure Assessment
Inputs Process
AEG Universal
Avista Review/Feedback Measure List
Avista Measure Data
Measure
(Program Data,Evaluated Description`
Savings,etc.)
characterizationPA
Measure
AEG Measure Data Library
Energy Savings Costs andNEls
Lifetime Saturation&
Building Simulations Applicability
The selected measures are categorized into the two following types according to the Load MAP
taxonomy:
Equipment measures are efficient energy-consuming pieces of equipment that save energy
by providing the same service with a lower energy requirement than a standard unit. An
example is an ENERGY STAR refrigerator that replaces a standard efficiency refrigerator. For
equipment measures, many efficiency levels may be available for a given technology, ranging
from the baseline unit(often determined by code or standard) up to the most efficient product
commercially available.For instance,in the case of central air conditioners,this list begins with
the current federal standard SEER 14 unit and spans a broad spectrum up to a maximum
efficiency of a SEER 24 unit.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 refrigerator or central
air conditioner).An example would be a programmable thermostatthat is pre-set to run heating
and cooling systems onlywhen people are home. Non-equipment measures can applyto more
than one end use. 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, compressor staging, and controls)
o Equipment maintenance (cleaning filters, changingsetpoints)
o Whole-building design (building orientation, advanced new construction designs)
o Lighting retrofits (assumed to be implemented alongside new LEDs at the equipment's
normal end of life)
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o Displacement measures(ceiling fan to reduce the use of central air conditioners)
o Commissioning and retrocommissioning (initial or ongoing monitoring of building energy
systems to optimize energy use)
We developed a preliminary list of conservation measures, which was distributed to the Avista
project team for review.The list was finalized after incorporating comments.Next,the project team
characterized measure savings, incremental cost, service life, 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. 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
Total Measure Measure Permutations
Sector Measures Permutations
Vintages
Residential 107 214 1,284
Commercial 137 274 3,014
Industrial 74 148 296
Total Measures Evaluated 318 636 4,594
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.
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 survey.
Load Forecasts: Avista provided an economic growth forecast by sector; electric load
forecast; peak-demand forecasts at the sector level; and retail electricity price history and
forecasts.
Economic Information:Avista provided a discount rate, line loss factor, and retail prices for
both electricity and natural gas to inform the customer choice model. Avoided costs for the
TRC perspective were provided based on the previous IRP only for use in benchmarking;
potential was not screened for cost effectiveness by AEG.
• Program Data: Avista provided information about past and current programs, including
program descriptions, goals, and achievements to date.
Northwest Energy Efficiency Alliance Data
The NEEA conducts research for the Northwest region. The following studies were particularly
useful:
• RBSA II,Single-Family Homes Report 2016-2017.
• RBSA II, Manufactured Homes Report 2016-2017.
• RBSA II, Multifamily Buildings Report 2016-2017.
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• 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.We checked our input assumptions and analysis results against the results from
these other studies, which include but are not limited to Tacoma Power, Idaho Power, and
PacifiCorp.
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.
Local Weather Data: Weather from National Oceanic and Atmospheric Administration's
National Climatic Data Center for Spokane, Washington, was used as the basis for building
simulations.
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EPRI End-Use Models (REEPS and COMMEND): These models provide the default
elasticities we apply to electricity prices, household income, home size, and heating and
cooling.
DEER:The California Energy Commission and California Public Utilities Commission sponsor
this database, which is designed to provide well-documented estimates of energy and peak
demand savings values, measure costs, and effective useful life for the state of California.We
used the DEER database to cross-check the measure savings we developed using BEST and
DEEM.
NREL End-Use Load Profiles. Load shapes specific to Avista's geographic region were used
to calculate hourly profiles of the end use projection and hourly savings inputs for the IRR Load
shapes were collected at the sector, segment and technology level where available.
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 Economy.
Data Application
We now discuss how the data sources described above were used for each step of the study.
Data Application for Market Characterization
To construct the high-level market characterization of electricity use and households/floor space
for each sector,we used Avista billing data and customer surveys to estimate energy use.
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 11, 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 electricity use, and annual intensity.
2. Used the Avista GenPOP Survey; NEEA's RBSA, CBSA, and IFSA; and AEG's Energy Market
Profiles database to develop existing appliance saturations, appliance and equipment
characteristics, and building characteristics.
3. Ensured calibration to controltotals for annual electricity sales in each sector and segment.
4. Compared and cross-checked with other recent AEG studies.
5. Worked with Avista staff to vet the data against their knowledge and experience.
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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
US DOE RECS and CBECS data
Residential:Annual use per household
Annual intensity NEEA RBSA and CBSA
Commercial:Annual use per square foot
AEO 2023
Other recent studies
Fraction of dwellings with an
appliance/technology Avista GenPOP Survey
Appliance/equipment Percentage of C&I floor NEEA RBSA and CBSA
saturations
space/employment with AEG's Energy Market Profiles
equipment/technology
UEC:Annual electricity use in homes and NWPCC RTF and 2021 Power Plan and RTF
UEC/EUI for each end- buildings that have the technology Building simulations
use technology EUI:Annual electricity use per square US RECS and CBECS data
foot/employee for a technology in floor
space that has the technology EIA Technical Data
RTF and NWPCC 2021 Power Plan data
Appliance/equipment NEEA regional survey data
Age distribution for each technology
age distribution Utility saturation surveys
Recent AEG studies
AEG DEEM
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
US EIA Tech Data sheets
Peak factors Share of technology energy use that NREL and AEG simulation Load shapes
occurs during the peak hour
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 Key Sources
Customer growth Forecasts of new construction in Avista short term load forecast
forecasts residential,commercial,and industrial AEO 2023 economic growth forecast
sectors
Equipment For each equipment/technology, Shipments data from AEO and ENERGY STAR
purchase shares purchase shares for each efficiency level; AEO 2023 regional forecast assumptions2
specified separately for existing
for baseline equipment replacement and new Appliance/efficiency standards analysis
projection construction Avista program results and evaluation reports
EPRI's REEPS and COMMEND models
Utilization model Price elasticities,elasticities for other
Avista
parameters variables(income,weather) Eshort-term forecast calibration
AEO 2 2023
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Table 2-5 Residential Electric Equipment Standards
TechnologyEnd Use
CentralAC SEER SEER 14.0
Cooling 13.0
Room AC CEER 10.9 CEER 16.0
SEER
Cool/Heating Heat Pumps 14.0/ SEER 15.0/HSPF 8.81 SEER2 14.3/HSPF2 7.5
HSPF
7.7
Water Heater s55Gal UEF 0.92 CCE 2.0
Water Heating (NEEATier 1)
Water Heater>55Gal CCE 2.0(NEEATier 1)
General Service EISA Tier 1 (18.6 EISA Tier 2(45.0 lm/W)
Lighting lm/W)
Linear Fluorescent T8-F32(80.0 lm/W system)
Refrigerator/Freezer 2014 Standard 2029 Standard
Clothes Washer IMEF 1.71/IWF 5.6
Clothes Dryer UCEF 2.29
Appliances Microwave 2016Standard 2026Standard
Stove/Oven Typical 2028 Standard
Air Purifier 1.5 CADR/W 1.9 CADR/W 2.4 CADR/W
Dehumidifier 2016 Standard
Miscellaneous Furnace Fans ECM
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Table 2-6 Commercial and Industrial Electric Equipment Standards
Air-Cooled Chiller COP 4.10(IPLV 14.0)
Water-Cooled Chiller COP 7.03(0.5 kW/ton)
Cooling
RTUs IEER 12.9 IEER 14.8
PTAC EER 10.4
Heat Pump IEER 12.8 IEER 14.1 /COP 3.4
/COP 3.3
Cool/Heating
PTHP EER 10.4/COP 3.1
Ventilation All Constant Air Volume/Variable Air Volume
General Service EISA Compliant(19.8 EISA Compliant(45.0 lm/W)
lm/W)
Lighting Linear Lighting T8-F32(82.5 lm/W system)
High Bay High-Intensity Discharge(56.0 lm/W)
Walk-In 2020 Standard
Refrigeration Reach-In/Glass Door/ 2017 Standard
Open Display
Vending Machine 2019 Standard
Food Service Pre-Rinse Spray Valve 1.0 GPM
Motors All NEMA Premium
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.
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Table 2-7 Data Needs for Measure Characteristics in LoadMAP
Model
Avista measure data
NWPCC workbooks, RTF
The annual reduction in consumption attributable to each NWPCC 2021 Plan
Energy Impacts specific measure.Savings were developed as a percentage conservation workbooks
of the energy end use that the measure affects. AEO 2023
EIA Technical Data
Other secondary sources
Savings during the peak demand periods are specified for Avista measure data
Peak Demand each electric measure.These impacts relate to the energy Building Simulations
Impacts savings and depend on the extent to which each measure is RTF workbooks
coincident with the system peak. NREL End-Use Load Profiles
Equipment Measures: Includes the full cost of purchasing
and installing the equipment on a per-household, per- Avista measure data
square-foot,per employee or per service point basis for the NWPCC workbooks, RTF
residential, commercial,and industrial sectors, respectively.
NWPCC 2021 Plan
Costs Non-equipment measures: Existing buildings—full installed conservation workbooks
cost. New Construction -the costs may be either the full
cost of the measure,or as appropriate,it may be the AEO 2023
incremental cost of upgrading from a standard level to a Other secondary sources
higher efficiency level.
Avista measure data
NWPCC workbooks, RTF
Estimates derived from the technical data and secondary
Measure NWPCC 2021 Plan
Lifetimes data sources that support the measure demand and energy conservation workbooks
savings analysis.
AEO 2023
Other secondary sources
Avista measure data
Estimate of the percentage of dwellings in the residential NWPCC workbooks, RTF
Applicability sector,square feet in the commercial sector, or employees NWPCC 2021 Plan
in the industrial sector where the measure is applicable and
where it is technically feasible to implement. conservation 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 Achievable Technical Potential
To estimate Achievable Technical Potential, two sets of parameters are needed to represent
customer decision-making behavior with respect to energy-efficiency choices.
Technical diffusion curves for non-equipment measures. Equipment measures are installed
when existing units fail. Non-equipment measures do not have this natural periodicity, so rather
than installing all available non-equipment measures in the first year of the projection
(instantaneous potential), they are phased in according to adoption schedules that generally
align with the diffusion of similar equipment measures. Like the 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.
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Adoption rates. Customer adoption rates or take rates are applied to technical potential to
estimate Achievable Technical 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 B.
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3 1 Energy Efficiency Market Characterization
This chapter presents howAvista's customers in Washington and Idaho use electricity 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
Total electricity use for Avista in 2021 was 8,028 GWh, 5,306 GWh in Washington, and 2,722 GWh in
Idaho.The residential sector accounts for around 50%of annual energy use in both states,followed
by commercial at around 40%of annual energy use. For winter peak demand,the total system peak
in 2021 was 1,471 MW: 988 MW in Washington and 483 MW in Idaho. In both states, the residential
sector represents the largest share of the winter peak.
Figure 3-1 Sector-Level Electricity Use in Base Year 2021,Washington
Annual Use (GWh) Winter Peak
Industrial Industrial
11% 9%
CommercialResidential
Commercial .% 55%
L I j k k k L
Table 3-1 Avista Sector Control Totals(2021),Washington
Sector %of Energy Total
Residential 2,671 50% 656
Commercial 2,075 39% 276
Industrial 559 11% 56
Total 5,306 100% 988
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Figure 3-2 Sector-Level Electricity Use in Base Year2021,Idaho
Annual Use (GWh) Winter Peak
Industrial Industrial l
15% 9%
Residential
I49% •
Commercial
Table 3-2Avista Sector Control Totals(2021),Idaho
Sector
Total
Residential 1,320 48% 314
Commercial 986 36% 125
Industrial 416 15% 44
Total 2,722 100% 483
Residential Sector
The total number of households and electricity sales were obtained from Avista's customer
database. In 2021, Avista provided electric service to 234,506 households in Washington; those
households used a total of 2,671 GWh with a winter peak demand of 656 MW. The average use per
household at 11,391 kWh is about average compared to other regions of the country. In 2021,Avista
provided electric service to 120,131 households in Idaho; those households used a total of 1,320
GWh with winter peak demand of 314 MW. The average use per household was 10,986 kWh. Table
3-3 and Table 3-4 show the total number of households and electricity sales in the six residential
segments for each state.
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Table 3-3 Base Year Electric Consumption Summary(Control Totals), Washington
Electric Use Annual %of Annual
Use/CustomerSegment (GWh) Customers
Single Family 1,300 97,304 13,362 49%
Multi-Family 95 12,712 7,459 4%
Mobile Home 155 8,704 17,754 6%
LI-Single Family 790 62,690 12,605 30%
LI-Multi-Family 220 45,261 4,856 8%
LI-Mobile Home 112 7,836 14,248 4%
Total 2,671 234,506 11,391 100%
Table 3-4 Base Year Electric Consumption Summary(Control Totals),Idaho
Electric Use Annual of Annual
CustomersSegment (GWh)
Use
Single Family 934 79,840 11,698 71%
Multi-Family 77 13,065 5,859 6%
Mobile Home 115 8,275 13,906 9%
LI-Single Family 119 9,913 11,956 9%
LI-Multi-Family 47 6,890 6,849 4%
LI-Mobile Home 28 2,148 13,265 2%
Total 1,320 120,131 10,986 100%
Figure 3-3 and Figure 3-4 show the distribution of annual electricity use by end use for all customers
in Washington and Idaho, respectively. Two main electricity end uses -space heating and
miscellaneous- account for approximately 50% of total usage. Miscellaneous includes furnace
fans, pool pumps, electric vehicles, and other "plug" loads (all other usages, such as hair dryers,
power tools, coffee makers, etc.).The figures show estimates of winter peak demand by end use.As
expected, space heating is the largest contributor to winter peak demand, followed by
miscellaneous,water heating, and lighting.
Figure 3-5 and Figure 3-6 present the electricity intensities by end use and housing type for
Washington and Idaho, respectively. Mobile homes have the highest use per customer at 17,754
kWh/year in Washington and 13,906 kWh/year in Idaho.
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Figure 3-3 Residential Electricity Use and Winter Peak Demand by End Use, Washington
Annual Use by End Use Winter Peak Demand
Cooling
Miscellaneous 7% Miscellaneous
21% 18%
Space
Electronics
5% Space
Electronics
m4L.-- I,F,,' Heating Heating
8% s
Exterior
Water Lighting
Heating 2%
Exterior��� 11% Interior Lighting Water
RA
Lighting Interor Lighting 10% Heating
2% 7% 8%
Figure 3-4 Residential Electricity Use and Winter Peak Demand by End Use,Idaho
Annual Use by End Use Winter Peak Demand
Cooling Miscellaneous
Miscellaneous 6% 17%
21%
Electronics
6% ISpace',
Electronics Space
8%
Appliances Lk 39%
Wa �ter °
Heating Interior
° Lighting
Exterior 11/o Exterior °°
Interior Lighting 15/ Water
Lighting Lighting 2% Heating
2% 8% 8%
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Figure 3-5 Residential Intensity by End Use and Segment, Washington
20,000
18,000
16,000 ■Cooling
14,000 - - ■Space Heating
■
12, ■Water Heating
000 -
kWh per 10,000 - —■ -
Household
— Interior Lighting
8,000 -
6,000 ■Exterior Lighting
4,000 -_ ■Appliances
2,000 ■Electronics
Single Family Multi-Family Mobile LI-Single LI-Multi- LI-Mobile •Miscellaneous
Home Family Family Home
Figure 3-6 Residential Intensity by End Use and Segment,Idaho
16,000
14,000
12,000 —
■Cooling
■10,000 Space Heating
■ ■
kWh per ■Water Heating
_
Household 8,000
-6,000 Interior Lighting
: � �
■4,000 Exterior Lighting
■ -
_ ■Appliances
2,000 ■ ■
■Electronics
Single Multi-Family Mobile LI-Single LI-Multi- LI-Mobile ■Miscellaneous
Family Home Family Family Home
Commercial Sector
The total electric energy consumed by commercial customers in 2021 was 2,075 GWh in Washington
and 986 GWh in Idaho. Avista billing data, CBSA, and secondary data were used to allocate this
energy usage to building type segments and to develop estimates of energy intensity (annual
kWh/square foot). Using the electricity use and intensity estimates, AEG inferred floor space (the
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unit of analysis in Load MAP for the commercial sector).The average building intensities by segment
are based on regional information from the CBSA;therefore,the intensity is the same in both states.
However, the overall end-use mix is different due to the different mix of building types.
Table 3-5 Base Year Electric Consumption Summary(Control Totals), Washington
Segment Electric Use Floor Space
•
Large Office 162 6 25.9 8%
Small Office 192 14 14.0 9%
Retail 460 39 11.9 22%
Restaurant 263 6 46.0 13%
Grocery 127 4 28.2 6%
College 116 8 15.3 6%
School 191 19 9.9 9%
Health 54 3 17.6 3%
Lodging 200 11 18.3 10%
Warehouse 145 24 6.1 7%
Miscellaneous 166 18 9.4 8%
Total 2,075 151 13.7 100%
Table 3-6 Base Year Electric Consumption Summary(Control Totals),Idaho
Segment Electric Use Floor Space
• • •
Large Office 125 5 25.9 13%
Small Office 39 3 14.0 4%
Retail 218 18 11.9 22%
Restaurant 152 3 45.9 15%
Grocery 143 5 28.2 14%
College 58 4 15.3 6%
School 11 1 9.9 1%
Health 4 0 17.7 0%
Lodging 85 5 18.3 9%
Warehouse 35 6 6.1 4%
Miscellaneous 115 12 9.4 12%
Total 986 62 15.8 100%
Figure 3-7 and Figure 3-8 show the distribution of annual electricity consumption and winter peak
demand by end use across all commercial buildings in Washington and Idaho, respectively. Electric
usage is dominated by lighting and ventilation, which comprise nearly 40% of annual electricity
usage. Lighting and ventilation also make up the largest portions of winter peak; however, electric
space heating represents a greater part of the peak than it does annual energy.
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Figure 3-7 Commercial Electricity Use and Winter Peak Demand by End Use, Washington
Annual Use by End Use Winter Peak Demand
Cooling Miscellaneous
Miscellaneous 9% Space 13% l
13% Heating Office
Office 8% Equipment
Equipment 8% Spalce ,.
11% Heating
FV Food
Food Preparation
Preparation j 7%6% 7a ,Interio Refrigeration InteriorRefrigeratio Lightinater 8%11% 19% atin Lighting
g 13% ter
Exterior Lighting 3% Exterior Lighting Heating
4% 7% 2%
Figure 3-8 Commercial Electricity Use and Winter Peak Demand by End Use,Idaho
Annual Use by End Use Winter Peak Demand
Miscellaneous Cooling
7% Space Miscellaneous
13o 0 � Heating 14%
Office 6%
Equipment Office Spacl.
10% Equipment�� Heating
8%
Food Ventilation
Preparation' 15% Food J' Ventilation
7% � Preparation 13%
Interior Water 8%
Refrigeration LightingHeating Interior
4% Refrigeration Lighting 0
15/0 19% 12% 4 14%
Water
Exterior Lighting Exterior Lighting- Heating
4% 6% 3%
Figure 3-9 and Figure 3-10 present the electricity intensity in kWh per square foot by end use and
segment for Washington and Idaho, respectively. In Washington, retail, restaurant, lodging, and
small office buildings use the most electricity in the service territory. For Idaho, retail, restaurant,
and grocery buildings use the most electricity in the service territory. HVAC and lighting are the major
end uses across most segments, aside from large offices and grocery,where office equipment and
refrigeration equipment, respectively, are highly concentrated.
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Figure 3-9 Commercial Electric Intensity by End Use and Segment, Washington
50
40 ■Cooling
—
■Heating
30 Ventilation
kWh/sgft
■Water Heating
� —
20 Interior Lighting
■Exterior Lighting
10 ■Refrigeration
�_ • �_ ■Food Preparation
0 — ■Office Equipment
e \\eke ro°� a�`aO ooye e0 ■Miscellaneous
C.o h o r�hee\\a�
Figure 3-10 Commercial Electric Intensity by End Use and Segment,Idaho
250
■Cooling
200 • ■Space Heating
Ventilation
150 . _ ■Water Heating
kWh/sqft —
p Interior Lighting
100 _
■Exterior Lighting
50 _ ■Refrigeration
0 — — — —, ■Food Preparation
�_
■Office Equipment
Ok�Ge Okk�`e �e�a� Jta�w o`etJ ea�cr \\e�z r�o\ aaO�ao 0)y e0
\o 5 e\�ao ■Miscellaneous
c
Industrial Sector
The total electricity used by Avista's industrial customers in 2021 was 976 GWh, 559 GWh in
Washington, and 416 GWh in Idaho. Avista billing data and load forecast, NEEA's IFSA, and
secondary sources were used to develop estimates of energy intensity(annual kWh/employee).We
infer the number of employees (the unit of analysis in LoadMAP for the industrial sector) using the
electricity use and intensity estimates.
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Appendix C
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Table 3-7 Base Year Electric Consumption Summary(Control Totals), Washington
Segment Electric Sales
Industrial 438
Pumping 122
Total 559
Table 3-8 Base Year Electric Consumption Summary(Control Totals), Idaho
Segment Electric Sales
Industrial 352
Pumping 64
Total 416
Figure 3-11 and Figure 3-12 show the distribution of annual electricity consumption and winter peak
demand by end use for all industrial customers in Washington and Idaho, respectively. Motors are
the largest overall end use, accounting for over 50% of energy use. Note that motors include a wide
range of industrial equipment, such as air compressors and refrigeration compressors, pumps,
conveyor motors, and fans.The process end use accounts for over 15%of annual energy use,which
includes heating, cooling, refrigeration, and electro-chemical processes.
Figure 3-11 Industrial Electricity Use and Winter Peak Demand by End Use,All Industries, Washington
Annual Use by End Use Winter Peak Demand
Miscellaneous Cooling Space Miscellaneous
6% (Heating 4%
3
5/0 � a/a Ventilation
5% pp—
'.
Interior
le ,,,
Lighting Heating
5%
Ventilation
Exterior Motors 9%
Lighting Interior
' 5% Lighting
2%
Exterior
Lighting
10%
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Appendix C
Avista Electric Conservation Potential Assessment for 2026-2045
Figure 3-12Industrial Electricity Use and Winter Peak Demand by End Use,All Industries,Idaho
Annual Use by End Use Winter Peak Demand
Miscellaneous Cooling Space Heating Miscellaneous
5% _ 7% 3% 5%
Ventilation
6% F P, I Space"�
Interior Heating
Lighting
5%
Vlation
Exterior Motors enti
9%
Lighting Interior
5% Lighting
2%
• Exterior
Lighting
10%
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Appendix C
Avista Electric Conservation Potential Assessment for 2026-2045
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 electricity 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: economic growth forecasts (i.e., customer growth, income
growth), electricity price forecasts, trends in fuel shares and equipment saturations, and Avista's
internally developed sector-level projections for electricity 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 additional electric 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 1/8760t"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 GWh. Annual energy use for 2021 reflects
weather-normalized values, while future years of energy use and peak demand reflect normal
weather, as defined byAvista.
Residential Sector Baseline Projections
Table 4-1 and Table 4-2 present the baseline projection for electricity by end use for the residential
sector in Washington and Idaho, respectively.Overall,in Washington,residential use increases from
2,671 GWh in 2021 to 3,670 GWh in 2045, an increase of 37.4%. Residential use in Idaho increases
from 1,320 GWh in 2021 to 1,763 GWh in 2045, an increase of 33.6%. This reflects substantial
customer growth in both states. Figure 4-1 and Figure 4-3 display the graphical representation of the
baseline projection in each state.
Figure 4-2 and Figure 4-4 present the baseline projection of annual electricity use per household in
each state. Growth in use per household and across the sector is a net effect of several factors:
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Appendix C
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Lighting continues to decline throughout the forecast period as the impacts of EISA continue
transformation of the lighting market into LED
The federal water heater standard update effective 2029 causes a sharp decline in water heating
usage after that point,such that by2045,total residential water heating loads are lower than 2021
values, despite saturation growth from new construction and electrification
Space heating sees an increase as new construction is assumed to be heated in the majority by
electric heat pumps, in compliance with Washington state energy code'
In the later years of the forecast, expected impacts of electric vehicles increase dramatically,
drawing on research done separately by Cadeo in a concurrent study for Avista'
Table 4-1 Residential Baseline Sales Projection by End Use(GWh),Washington
• Use 20211 1 2030 2040 2045 %Change
Cooling 178 200 178 178 190 188 5.9%
Space Heating 753 789 861 869 961 948 25.8%
Water Heating 294 351 367 374 303 285 -3.3%
Interior Lighting 193 173 155 120 101 98 -49.1%
Exterior Lighting 48 21 20 19 15 15 -68.6%
Appliances 440 446 452 469 507 531 20.6%
Electronics 219 222 227 242 286 312 42.5%
Miscellaneous 554 561 573 667 1,107 1,379 148.8%
Generation (10) (29) (43) (83) (87) (87) 791.0%
Total 2,671 2,734 2,790 2,855 3,383 3,670 37.4%
Figure 4-1 Residential Baseline Projection by End Use, Washington
4,000
3,500 Generation
3,000
■ Cooling
■ Space Heating
2,500 _ ■ Water Heating
GWh 2,000 FP Interior Lighting
1,500 ■ Exterior Lighting
1,000
■ Appliances
■ Electronics
500
■ Miscellaneous
2021 2024 2027 2030 2033 2036 2039 2042 2045
'There are some circumstances where it is possible under the code credit system to reach compliance with
high efficiency gas systems, particularly as backup units, however this baseline assumes >90% of new
construction will be all-electric as the simplest path to compliance
'See Distributed Energy Resources Potential Study,Prepared for Avista Utilities by Applied Energy Group, Inc.,
Cadeo Group,and Verdant Associates.June 17,2024
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Appendix C
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Figure 4-2 Residential Baseline Projection by End Use-Annual Per Household, Washington
14,000
12,000 ■ Cooling
� ■ Space Heating
10,000
■ Water Heating
8,000 — Interior Lighting
kWh/HH 6,000 -- ■ ■_ ■ Exterior Lighting
4,000 ■ ■ ■ ■ ■ Appliances
. ■ .
■ Electronics
■ Miscellaneous
2,000 01-0
Generation
-2,000
2021 2023 2025 2030 2040 2045
Table 4-2 Residential Baseline Sales Projection by End Use(GWh),Idaho
• Use 20211 1 2030 2040 2045
Change
Cooling 73 78 71 71 76 78 5.9%
Space Heating 312 369 406 420 509 540 73.2%
Water Heating 139 171 182 187 138 120 -14.0%
Interior Lighting 139 126 112 88 76 76 -45.6%
Exterior Lighting 35 16 15 15 13 13 -62.4%
Appliances 234 237 240 248 274 292 25.0%
Electronics 115 117 120 129 156 172 49.9%
Miscellaneous 274 277 280 297 419 512 87.0%
Generation (1) (5) (6) (9) (24) (40) 5019.1%
Total 1,320 1,387 1,420 1,447 1,637 1,763 33.6%
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Appendix C
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Figure 4-3 Residential Baseline Projection by End Use,Idaho
2,000
1,800 Generation
1,600 ■ Cooling
1,400 ■ Space Heating
1,200 ■ Water Heating
GWh 1,000 Interior Lighting
800 ■ Exterior Lighting
600 ■ Appliances
400 ■ Electronics
200 ■ Miscellaneous
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045
Figure 4-4 Residential Baseline Projection by End Use-Annual Per Household,Idaho
12,000
10,000 ■ Cooling
■ Space Heating
8,000 ■ Water Heating
6,000 • Interior Lighting
kWh/HH ■ ■4,000 ■ Exterior Lighting
■ ■ ■ ■ -
_ ■ Appliances
2,000 . . . . ■ Electronics
0 ■ Miscellaneous
iNs Generation
-2,000
2021 2023 2025 2030 2040 2045
Commercial Sector Baseline Projections
In Washington, annual electricity use in the commercial sector grows during the overall forecast
horizon,starting at 2,075 GWh in 2021,and increasingto 3,034 in 2045,an increase of 46%. In Idaho,
annual electricity use will grow from 986 GWh in 2021 to 1,240 GWh in 2045, an increase of 25.7%.
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Appendix C
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Table 4-3 Commercial Baseline Sales Projection by End Use(GWh), Washington
040 2045
Cooling 176 149 128 133 142 143 -18.6%
Space Heating 162 184 189 191 198 199 22.4%
Ventilation 329 328 302 281 258 251 -23.6%
Water Heating 70 78 81 97 126 136 94.1%
Interior Lighting 394 394 388 371 351 347 -11.9%
Exterior Lighting 90 89 86 77 71 70 -22.9%
Refrigeration 235 239 242 250 267 276 17.7%
Food Preparation 124 124 122 118 124 129 3.9%
Office Equipment 225 221 213 208 218 223 -0.9%
Miscellaneous 273 283 302 388 908 1,280 369.6%
Generation (2) (7) (7) (10) (15) (20) 713.5%
Total 2,075 2,082 2,046 2,103 2,648 3,034 46.2%
Table 4-4 Commercial Baseline Sales Projection by End Use(GWh),Idaho
• Use 2021 2023 2025 2030 2040 2045
Cooling 73 58 58 63 72 76 4.0%
Space Heating 58 71 83 86 95 99 70.9%
Ventilation 151 152 163 159 159 163 7.3%
Water Heating 35 38 44 52 68 74 113.8%
Interior Lighting 186 191 190 188 189 194 3.9%
Exterior Lighting 40 40 39 36 35 36 -9.6%
Refrigeration 152 158 163 174 199 214 40.4%
Food Preparation 69 69 67 64 63 63 -8.0%
Office Equipment 101 101 98 98 109 115 14.4%
Miscellaneous 123 128 131 140 171 210 70.9%
Generation (1) (1) (1) (1) (2) (3) 274.6%
Total 986 1,004 1,035 1,058 1,158 1,240 25.7%
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Appendix C
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Figure 4-5 Commercial Baseline Projection by End Use, Washington
3,500 V Generation
3,000
■ Cooling
■ Space Heating
2,500
Ventilation
2,000 ■ Water Heating
GWh Interior Lighting
1,500
■ Exterior Lighting
1,000 ■ Refrigeration
500
■ Food Preparation
■ Office Equipment
■ Miscellaneous
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045
Figure 4-6 Commercial Baseline Sales Projection by End Use-Annual Use per Square Foot, Washington
18
16
_ ■ Cooling
14 ■ Space Heating
12 Ventilation
10 ■ Water Heating
kWh/sgft 8 Interior Lighting
6
_ ■ Exterior Lighting
■ Refrigeration
4 ■ Food Preparation
2 -_ ■ Office Equipment
0 ■ Miscellaneous
-2
Generation
2021 2023 2025 2030 2040 2045
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Appendix C
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Figure 4-7 Commercial Baseline Projection by End Use,Idaho
1,400
Generation
1,200 ■ Cooling
1,000 ■ Space Heating
800 Ventilation
GWh
600
■ Water Heating
Interior Lighting
400
■ Exterior Lighting
200
■ Refrigeration
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045
Figure 4-8 Commercial Baseline Sales Projection by End Use-Annual Use per Square Foot,Idaho
18
16
_ ■ Cooling
14 =— =
_ ■ Space Heating
12 Ventilation
10 ■ Water Heating
kWh/sqft 8 ■ ■ ■ Interior Lighting
■ Exterior Lighting
■ ■ ■ ■ ■ Refrigeration
4
_ ■ Food Preparation
2 ■ Office Equipment
0 . ■ ■ Miscellaneous
-2
Generation
2021 2023 2025 2030 2040 2045
Industrial Sector Baseline Projections
Annual industrial use declined through the forecast horizon, consistent with trends from Avista's
industrial load forecast.Overall, in Washington, industrial annual electricity use decreases from 559
GWh in 2021 to 478 GWh in 2045. In Idaho,annual electricity use drops from 416 GWh in 2021 to 309
GWh in 2045.
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Appendix C
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Table 4-5 Industrial Baseline Projection by End Use(GWh), Washington
04
Change
Cooling 35 35 35 33 29 28 -20.6%
Space Heating 17 17 16 15 14 13 -22.7%
Ventilation 31 31 29 26 21 20 -35.7%
Interior Lighting 28 29 27 24 21 19 -30.0%
Exterior Lighting 25 26 24 20 16 14 -43.2%
Process 87 93 92 88 81 78 -11.0%
Motors 307 314 311 302 287 280 -8.7%
Miscellaneous 29 31 30 29 27 26 -10.8%
Total 559 575 565 536 495 478 -14.5%
Table 4-6 Industrial Baseline Projection by End Use(GWh),Idaho
040 2045
Change
Cooling 27 23 22 21 18 17 -39.5%
Space Heating 13 13 13 13 11 10 -19.6%
Ventilation 24 23 22 19 15 14 -42.3%
Interior Lighting 22 21 21 18 14 13 -39.0%
Exterior Lighting 20 19 18 15 11 10 -50.1%
Process 70 69 70 66 58 54 -22.8%
Motors 219 213 214 203 183 174 -20.5%
Miscellaneous 22 22 22 21 18 17 -22.8%
Total 416 403 403 375 328 309 -25.9%
Figure 4-9 Industrial Baseline Projection by End Use(GWh), Washington
700
600 ■ Cooling
500 ■ Space Heating
Ventilation
400 Interior Lighting
GWh ■ Exterior Lighting
300 —
■ Process
200 — ■ Motors
100 —
■ Miscellaneous
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045 2047
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Appendix C
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Figure 4-10 Industrial Baseline Sales Projection by End Use—Annual Use per Employee, Washington
120,000
100,000 ■Cooling
■Space Heating
80,000 Ventilation
KWh/Empl. ■ ■ . ■ ■ ■ Interior Lighting
60,000 ■ Exterior Lighting
■ Process
40,000 ■ Motors
■ Miscellaneous
20,000
0
2021 2023 2025 2030 2040 2045
Figure 4-11 Industrial Baseline Projection by End Use(GWh),Idaho
450
400
■ Cooling
350 ■ Space Heating
300 Ventilation
250 Interior Lighting
GWh 200 ■ Exterior Lighting
■ Process
150
■ Motors
100
■ Miscellaneous
50
2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043 2045 2047
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Appendix C
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Figure 4-12 Industrial Baseline Sales Projection by End Use—Annual Use per Employee,Idaho
140,000
120,000 _
■Cooling
100,000 ■Space Heating
Ventilation
KWh/Empl. 80,000 . . . . . . Interior Lighting
60,000 ■ Exterior Lighting
■ Process
40,000 ■ Motors
■ Miscellaneous
20,000
0
2021 2023 2025 2030 2040 2045
Summary of Baseline Projections Across Sectors and States
Table 4-7 and Figure 4-13 provide a summary of the baseline projection for annual use by sector for
the entire Avista electric service territory. Overall,the projection shows steady growth in electricity
use,driven primarily by customer growth forecasts.
Table 4-7 Baseline Projection Summary(GWh), Washington and Idaho Combined
04
Residential 3,991 4,121 4,210 4,302 5,020 5,432 36.1%
Commercial 3,062 3,086 3,081 3,161 3,806 4,274 39.6%
Industrial 976 978 968 911 823 787 -19.3%
Total 8,028 8,185 8,259 8,374 9,649 10,493 30.7%
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Appendix C
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Figure 4-13 Baseline Projection Summary(GWh), Washington and Idaho Combined
12,000
10,000 —
8,000 ■ Residential
GWh 6,000
■ Commercial
4,000 ■ Industrial
2,000
2026 2028 2030 2032 2034 2036 2038 2040 2042 2044
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Appendix C
Avista Electric Conservation Potential Assessment for 2026-2045
5 1 Conservation Potential
This chapter presents conservation potential results, beginning with a summary of annual energy
savings across all three sectors,followed by detailed savings for each sector. Potential is presented
for annual energy savings (GWh and aMW) as well as the winter peak demand savings (MW) for
selected years. Note that all savings are presented atthe customer meter(i.e.,excluding line losses).
Overall Summary of Energy Efficiency Potential
Summary of Annual Energy Savings
Table 5-1 and Table 5-2 summarize the energy efficiency potential for each state relative to the
baseline projection. Potential as a percent of the baseline projection in each state is shown
graphically in Figure 5-1 and Figure 5-2.
Technical Potential reflects the adoption of all conservation measures regardless of cost-
effectiveness.
o For Washington, first-year savings are 136 GWh or 2.5% of the baseline projection.
Cumulative savings in 2045 are 2,047 GWh or 28.5%of the baseline.
o For Idaho, first-year savings are 67 GWh or 2.4% of the baseline projection. Cumulative
savings in 2045 are 960 GWh or 29% of the baseline.
Achievable Technical Potential modifies Technical Potential by accounting for assumed
customer adoption.
o In Washington, first-year savings potential is 60 GWh or 1.1% of the baseline. In 2045,
cumulative achievable technical savings reach 1,519 GWh or 21.2% of the baseline
projection. Achievable Technical Potential is approximately 56% of Technical Potential in
Washington throughout the forecast horizon.
o For Idaho, first-year savings are 31 GWh or 1.1% of the baseline, and by 2045, cumulative
achievable technical savings will reach 692 GWh, or 20.9% of the baseline. In Idaho,
Achievable Technical Potential reflects 57% of Technical Potential throughout the forecast
horizon.
Table 5-1 Summary of Energy Efficiency Potential, Washington
2026 20271 1 1 2035 2045
Baseline Forecast(GWh) 5,406 5,410 5,422 5,495 5,882 7,182
Potential Forecasts(GWh)
Achievable Technical Potential 5,346 5,282 5,216 5,111 4,976 5,663
Technical Potential 5,270 5,135 5,001 4,820 4,512 5,135
Cumulative Savings(GWh)
Achievable Technical Potential 60 128 206 383 906 1,519
Technical Potential 136 275 421 675 1,370 2,047
Cumulative Savings(aMWh)
Achievable Technical Potential 7 15 24 44 103 173
Technical Potential 16 31 48 77 156 234
Energy Savings(%of Baseline)
Achievable Technical Potential 1.1% 2.4% 3.8% 7.0% 15.4% 21.2%
Technical Potential 2.5% 5.1% 7.8% 12.3% 23.3% 28.5%
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Appendix C
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Table 5-2 Summary of Energy Efficiency Potential,Idaho
2026 202711 1 2035 2045
Baseline Forecast(GWh) 2,851 2,854 2,857 2,879 2,975 3,311
Potential Forecasts(GWh)
Achievable Technical Potential 2,820 2,787 2,749 2,683 2,528 2,620
Technical Potential 2,784 2,718 2,647 2,546 2,312 2,352
Cumulative Savings(GWh)
Achievable Technical Potential 31 67 107 196 447 692
Technical Potential 67 136 209 333 664 960
Cumulative Savings(mMWh)
Achievable Technical Potential 4 8 12 22 51 79
Technical Potential 8 16 24 38 76 110
Energy Savings(%of Baseline)
Achievable Technical Potential 1.1% 2.3% 3.8% 6.8% 15.0% 20.9%
Technical Potential 2.4% 4.8% 7.3% 11.6% 22.3% 29.0%
Figure 5-1 Cumulative Energy Efficiency Potential as a%of Baseline Projection, Washington
30.0%
25.0%
20.0%
%of Baseline 15.0%
10.0%
5.0% �� -,I ■
0.0%
2026 2027 2028 2030 2035 2045
Achievable Technical Potential ■Technical Potential
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Appendix C
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Figure 5-2 Cumulative Energy Efficiency Potential as a%of Baseline Projection,Idaho
35.0%
30.0%
25.0%
20.0%
%of Baseline
15.0%
10.0%
5.0% —Mll -. ■ ,
2026 2027 2028 2030 2035 2045
■Achievable Technical Potential ■Technical Potential
Summary of Conservation Potential by Sector
Table 5-3 and Figure 5-3 summarize the Achievable Technical Potential by sector for both states
combined. As shown, the commercial sector represents the largest share of Achievable Technical
Potential in the early years, with the residential sector representing larger potential over the longer
term.
Table 5-3 Achievable Technical Conservation Potential by Sector, Washington and Idaho Combined
Sector126 2027 20282030 2035 2045
Cumulative Savings(GWh)
Residential 35 76 125 235 605 891
Commercial 48 101 160 294 639 1,173
Industrial 8 18 28 51 109 146
Total 91 194 313 579 1,353 2,211
Cumulative Savings(aMW)
Residential 4 9 14 27 69 102
Commercial 6 12 18 34 73 134
Industrial 1 2 3 6 12 17
Total 10 22 36 66 154 252
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Appendix C
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Figure 5-3 Achievable Technical Conservation Potential by Sector, Washington and Idaho Combined
2,500
2,000
1,500
Cumulative ■Industrial
Savings �
■Commercial
(GWh)
1,000 ■Residential
500
■
2026 2027 2028 2030 2035 2045
Residential Conservation Potential
Table 5-4 and Table 5-5 present state-specific estimates of conservation potential for the residential
sector in terms of annual energy savings. In Washington, residential Achievable Technical Potential
in 2026 is 23 GWh or 0.8% of the baseline projection. By 2045, cumulative Achievable Technical
Potential reaches 616 GWh or 16.8%of the baseline projection. In Idaho,2026 Achievable Technical
Potential is 12 GWh or 0.8% of the baseline, and by 2045 cumulative Achievable Technical potential
reaches 274 GWh or 15.6% of the baseline.
Figure 5-4 and Figure 5-5 show potential as a percent of the baseline projection in each state.
Table 5-4 Residential Conservation Potential, Washington
2026 20271 : 2030 2035 2045
Baseline Forecast(GWh) 2,798 2,804 2,810 2,855 3,063 3,669
Cumulative Savings(GWh)
Technical Achievable Potential 23 50 83 158 414 616
Technical Potential 66 135 210 323 714 1,003
Energy Savings(%of Baseline)
Technical Achievable Potential 0.8% 1.8% 3.0% 5.5% 13.5% 16.8%
Technical Potential 2.3% 4.8% 7.5% 11.3% 23.3% 27.3%
Cumulative Savings(aMW)
Technical Achievable Potential 2.6 5.7 9.5 18.0 47.3 70.4
Technical Potential 7.5 15.4 23.9 36.8 81.6 114.5
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Appendix C
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Table 5-5 Residential Conservation Potential,Idaho
2026 20271 : 2030 2035 2045
Baseline Forecast(GWh) 1,417 1,421 1,424 1,447 1,527 1,763
Cumulative Savings(GWh)
Technical Achievable Potential 12 26 42 78 191 274
Technical Potential 30 63 98 146 321 459
Energy Savings(%of Baseline)
Technical Achievable Potential 0.8% 1.8% 3.0% 5.4% 12.5% 15.6%
Technical Potential 2.1% 4.4% 6.9% 10.1% 21.0% 26.0%
Cumulative Savings(aMW)
Technical Achievable Potential 1.3 2.9 4.8 8.9 21.8 31.3
Technical Potential 3.4 7.2 11.1 16.7 36.6 52.4
Figure 5-4 Residential Cumulative Conservation Potential, Washington
30.0%
25.0%
20.0%
15.0%
%of Baseline
10.0%
5.0%
0.0% ��� �■I •
2026 2027 2028 2030 2035 2045
■Technical Achievable Potential ■Technical Potential
Figure 5-5 Residential Cumulative Conservation Potential,Idaho
30.0%
25.0%
20.0%
15.0%
of Baseline
10.0% -
5.00 �1 I 'I -.�■
0.0%
2026 2027 2028 2030 2035 2045
Technical Achievable Potential ■Technical Potential
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Appendix C
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Figure 5-6 presents the cumulative residential Achievable Technical Potential by end use in
Washington. Space heating and water heating account for a substantial portion of the savings
throughout the forecast horizon.Weatherization, HVAC, and heat pump water heaters account for a
large portion of potential over the 20-year study period. LED lighting, while still present, is reduced
in comparison to prior studies, as RTF market baseline assumptions and the Washington state
Lighting standard have moved a substantial amount of potential from those technologies into the
baseline projection.
Figure 5-6 Residential Cumulative Achievable Technical Potential by End Use, Washington
700
600
500 ■Cooling
■Space Heating
400 ■Water Heating
GWh ■ Exterior Lighting
300
■Interior Lighting
200 ■Appliances
■Electronics
100
■Miscellaneous
2026 2028 2030 2032 2034 2036 2038 2040 2042 2044
Table 5-6 identifies the top 20 residential measures from the perspective of cumulative Achievable
Technical Potential for Washington in 2045, the final year of the planning horizon. The top three
measures include high-efficiency windows, high-efficiency heat pump water heaters(above the new
federal standard after 2030), and level 2 electric vehicles. Note that achievable technical savings do
not screen for cost-effectiveness, and some measures are expected to be screened out during the
IRP process.
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Appendix C
Avista Electric Conservation Potential Assessment for 2026-2045
Table 5-6 Residential Top 20 Measures in 2045, Washington
2045
Rank Residential Measure Cumulative
Savings(MWh)
1 Windows-High Efficiency(ENERGY STAR 7.0) 66,944 10.9%
2 Water Heater(<=55 Gal)-NEEA Tier 5 Heat Pump(CCE 3.5) 54,778 8.9%
3 Electric Vehicles-Level 42,321 6.9%
4 Ducting-Repair and Sealing 24,439 4.0%
5 Windows-High Efficiency(Triple Pane) 22,645 3.7%
6 Insulation-Wall Sheathing 20,502 3.3%
7 Home Energy Reports 19,089 3.1%
8 Clothes Dryer-UCEF 2.62/CEF 3.93-ENERGY STAR 1.1 18,893 3.1%
9 Building Shell-Air Sealing(Infiltration Control) 18,579 3.0%
10 Insulation-Ducting 17,897 2.9%
11 Engine Block Heater Controls 16,557 2.7%
12 Air-Source Heat Pump-SEER 16.0/HSPF 9.2 15,952 2.6%
13 TVs-ENERGY STAR(9.0) 15,752 2.6%
14 Advanced New Construction Designs 15,209 2.5%
15 HVAC-Maintenance and Tune-Up 14,512 2.4%
16 Clothes Washer-CEE Tier 2 12,695 2.1%
17 Insulation-Floor Upgrade-R-30 12,541 2.0%
18 Ducting-Repair and Sealing-Aerosol 12,110 2.0%
19 Home Energy Management System(HEMS) 10,789 1.7%
20 Water Heater-Drainwater Heat Recovery 10,187 1.7%
Total of Top 20 Measures 442,389 71.7%
Total Cumulative Savings 616,674 100.0%
Figure 5-7 presents the cumulative residential Achievable Technical Potential by end use in Idaho.
Results are similar to Washington, where the majority of the savings come from space heating and
water heating measures.
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Figure 5-7 Residential Cumulative Achievable Technical Potential by End Use,Idaho
300 —
250
■Cooling
200 — ■Space Heating
■Water Heating
GWh 150
■Exterior Lighting
100 _ Interior Lighting
■Appliances
50 ' ■Electronics
■Miscellaneous
2026 2028 2030 2032 2034 2036 2038 2040 2042 2044
Table 5-7 shows the top residential measures for Idaho by 2045.The top three measures include two
types of high-efficiency windows, as well as advanced new home construction designs. Note that
Achievable Technical Potential is not screened for cost-effectiveness, and some measures are
expected to be screened out during the IRP process.
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Appendix C
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Table 5-7 Residential Top Measures in 2045,Idaho
04
Rank Residential Measure Cumulative Total
Savings(MWh)
1 Windows-High Efficiency(ENERGY STAR 7.0) 21,294 7.8%
2 Advanced New Construction Designs 13,714 5.0%
3 Windows-High Efficiency(Triple Pane) 12,602 4.6%
4 Engine Block Heater Controls 10,799 3.9%
5 Ducting-Repair and Sealing 9,508 3.5%
6 Insulation-Wall Sheathing-R-19 9,377 3.4%
7 Electric Vehicles-Level 2 9,173 3.4%
8 TVs-ENERGY STAR(9.0) 8,885 3.2%
9 Clothes Washer-CEE Tier 2 8,375 3.1%
10 Water Heater(<=55 Gal)-NEEA Tier 5 Heat Pump(CCE 3.5) 7,750 2.8%
11 Insulation-Ducting-R-8 Ducts(Code) 7,458 2.7%
12 Ducting-Repair and Sealing-Aerosol-Aerosol duct sealing 7,026 2.6%
13 Linear Lighting-LED 2035(152 lm/W system) 6,858 2.5%
14 Home Energy Reports 6,829 2.5%
15 HVAC-Maintenance and Tune-Up 6,715 2.5%
16 Building Shell-Air Seating(infiltration Control) 6,650 2.4%
17 Home Energy Management System(HEMS) 6,092 2.2%
18 Air-Source Heat Pump-SEER 16.0/HSPF 9.2 5,937 2.2%
19 Personal Computers-ENERGY STAR(8.0) 5,624 2.1%
20 Insulation-Ceiling Installation-R-49 5,610 2.1%
Total of Top 20 Measures 176,277 64.4%
Total Cumulative Savings 273,606 100.0%
Commercial Conservation Potential
Table 5-8 and Table 5-9 present state-specific estimates of conservation potential for the
commercial sector. For Washington, Achievable Technical Potential is 32 GWh in 2026 or 1.6% of
the baseline projection. By 2045, achievable technical savings are 816 GWh or 26.9%of the baseline
projection. For Idaho, first-year Achievable Technical Potential is 16 GWh or 1.6% of the baseline,
and by 2045, cumulative Achievable Technical Potential reaches 358 GWh or 28.8%of the baseline.
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Appendix C
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Table 5-8 Commercial Conservation Potential, Washington
2026 20271 1 1 2035 2045
Baseline Forecast(GWh) 2,049 2,056 2,066 2,103 2,305 3,034
Cumulative Savings(GWh)
Technical Achievable Potential 32 68 107 196 428 816
Technical Potential 64 126 190 315 577 938
Energy Savings(%of Baseline)
Technical Achievable Potential 1.6% 3.3% 5.2% 9.3% 18.6% 26.9%
Technical Potential 3.1% 6.1% 9.2% 15.0% 25.0% 30.9%
Cumulative Savings(aMW)
Technical Achievable Potential 3.7 7.7 12.2 22.4 48.9 93.1
Technical Potential 7.3 14.4 21.7 36.0 65.9 107.1
Table 5-9 Commercial Conservation Potential,Idaho
2026 20271 : 2030 2035 2045
Baseline Forecast(GWh) 1,037 1,041 1,046 1,058 1,099 1,240
Cumulative Savings(GWh)
Technical Achievable Potential 16 34 53 97 211 358
Technical Potential 32 64 96 160 287 428
Energy Savings(%of Baseline)
Technical Achievable Potential 1.6% 3.2% 5.1% 9.2% 19.2% 28.8%
Technical Potential 3.1% 6.1% 9.2% 15.1% 26.1% 34.5%
Cumulative Savings(aMW)
Technical Achievable Potential 1.8 3.8 6.1 11.1 24.1 40.8
Technical Potential 3.7 7.3 11.0 18.3 32.8 48.9
Figure 5-8 Commercial Cumulative Conservation Potential, Washington
35.0%
30.0%
25.0%
%of Baseline 20.0%
15.0% -
10.0%
Moroi
2026 2027 2028 2030 2035 2045
■Technical Achievable Potential ■Technical Potential
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Figure 5-9 Commercial Cumulative Conservation Potential,Idaho
40.0% —
35.0%
30.0%
25.0%
of Baseline 20.0%
15.0% —
10.0%
5.0
0.0% _91r..�.
2026 2027 2028 2030 2035 2045
Technical Achievable Potential ■Technical Potential
Figure 5-10 presents a forecast of cumulative commercial energy savings by end use in Washington.
HVAC end uses (cooling, space heating and ventilation) paired with interior lighting account for a
substantial portion of the savings throughout the forecast horizon.
Figure 5-10 Commercial Cumulative Achievable Technical Potential by End Use, Washington
600
■Cooling
500
■Space Heating
Ventilation
400
■Water Heating
GWh 300 . _Interior Lighting
■Exterior Lighting
200 ■Refrigeration
■Food Preparation
100
- ■Office Equipment
■Miscellaneous
2026 2028 2030 2032 2034 2036 2038 2040 2042 2044
Table 5-10 identifies the top 20 commercial sector measures from the perspective of cumulative
energy savings by 2045 in Washington. Electric vehicle chargers and linear lighting are included in
the top 3 measures. Although the market has seen significant penetration of LEDs in some
applications, newer systems—particularly those with built-in occupancy sensors or other controls—
still represent significant savings opportunities. High-efficiency water heaters also contribute a
significant portion to the potential.
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Table 5-10 Commercial Top 20 Measures in 2045, Washington
04
Rank Measure/Technology Cumulative
•
Savings(MWh)
1 Electric Vehicle Chargers-Level 2 156,182 19.3%
2 Linear Lighting-LED 2035(152 lm/W system) 154,543 19.1%
3 Water Heater-UEF 3.9-Heat Pump 70,102 8.6%
4 Air-Source Heat Pump-IEER 20.3/COP 3.7 47,567 5.9%
5 High-Bay Lighting-LED 34,132 4.2%
6 Desktop Computer-ENERGY STAR(8.0) 30,568 3.8%
7 HVAC-Energy Recovery Ventilator 25,087 3.1%
8 Server-ENERGY STAR(4.0) 21,368 2.6%
9 Ventilation-Variable Speed Control 21,259 2.6%
10 Office Equipment-Advanced Power Strips 20,274 2.5%
11 Strategic Energy Management 19,452 2.4%
12 HVAC-Dedicated Outdoor Air System(DOAS) 17,903 2.2%
13 Ductless Mini Split Heat Pump 13,858 1.7%
14 Refrigeration-Economizer Addition 13,660 1.7%
15 Water Heater-Pipe Insulation 12,374 1.5%
16 Lodging-Guest Room Controls 8,534 1.1%
17 Retrocommissioning 7,422 0.9%
18 Water Heater-Solar Systems 6,984 0.9%
19 Laptop-ENERGY STAR(8.0) 5,448 0.7%
20 Windows-Secondary Glazing Systems 5,300 0.7%
Total of Top 20 Measures 692,015 85.4%
Total Cumulative Savings 815,889 100.0%
Figure 5-11 presents a forecast of cumulative commercial energy savings by end use in Idaho.
Similar to Washington, HVAC end uses (cooling, space heating, and ventilation) paired with interior
lighting account for a substantial portion of the savings throughout the forecast horizon.
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Figure 5-11 Commercial Cumulative Achievable Technical Potential by End Use,Idaho
250
■Cooling
200 ■Space Heating
Ventilation
150 ■Water Heating
GWh Interior Lighting
100
■Exterior Lighting
■Refrigeration
■Food Preparation
50
■Office Equipment
■Miscellaneous
2026 2028 2030 2032 2034 2036 2038 2040 2042 2044
Table 5-11 identifies the top 20 commercial-sector measures from the perspective of cumulative
energy savings by 2045 in Idaho. Like Washington, linear lighting is included in the top 3 measures.
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Appendix C
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Table 5-11 Commercial Top 20 Measures in 2045,Idaho
04
Rank Measure/Technology Cumulative
TotaL
Savings(MWh)
1 Linear Lighting-LED 82,600 23.3%
2 Water Heater-UEF 3.9-Heat Pump 28,926 8.2%
3 Air-Source Heat Pump-IEER 20.3/COP 3.7 16,968 4.8%
4 High-Bay Lighting-LED 2035 16,934 4.8%
5 HVAC-Energy Recovery Ventilator 13,198 3.7%
6 Server-ENERGY STAR(4.0) 13,146 3.7%
7 HVAC-Dedicated Outdoor Air System(DOAS) 12,901 3.6%
8 Refrigeration-Economizer Addition 12,831 3.6%
9 Ventilation-Variable Speed Control 12,821 3.6%
10 Strategic Energy Management 11,179 3.2%
11 Office Equipment-AdvancedPowerStrips 11,130 3.1%
12 Electric Vehicle Chargers-Level 2 8,020 2.3%
13 Water Heater-Pipe Insulation 7,328 2.1%
14 Ductless Mini Split Heat Pump 6,943 2.0%
15 Water Heater-Solar Systems 5,032 1.4%
16 Lodging-Guest Room Controls 4,763 1.3%
17 Retrocommissioning 4,445 1.3%
18 Grocery-Display Case-LED Lighting 4,126 1.2%
19 Refrigeration-Floating Head Pressure 3,841 1.1%
20 Refrigeration-High Efficiency Compressor 3,716 1.0%
Total of Top 20 Measures 280,850 79.2%
Total Cumulative Savings 357,589 100.0%
Industrial Conservation Potential
Table 5-12 and Table 5-13 present state-specific estimates for the two levels of conservation
potential for the industrial sector. For Washington,Achievable Technical Potential in the first year,
2026, is 5 GWh, or 0.9% of the baseline projection. In 2045, savings reach 87 GWh or 18.1% of the
baseline projection. For Idaho, Achievable Technical Potential in the first year is 4 GWh or 0.9% of
the baseline projection. In 2045,savings reach 60 GWh or 19.3%of the baseline projection.
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Table 5-12 Industrial Conservation Potential, Washington
2026 20271 : 2030 2035 2045
Baseline Forecast(GWh) 558 551 546 536 514 478
Cumulative Savings(GWh)
Technical Achievable Potential 5 10 16 29 64 87
Technical Potential 7 14 21 37 79 106
Cumulative Savings(%of Baseline)
Technical Achievable Potential 0.9% 1.9% 3.0% 5.5% 12.4% 18.1%
Technical Potential 1.2% 2.5% 3.9% 7.0% 15.3% 22.2%
Cumulative Savings(aMW)
Technical Achievable Potential 0.6 1.2 1.8 3.3 7.3 9.9
Technical Potential 0.8 1.5 2.4 4.3 9.0 12.1
Table 5-13 Industrial Conservation Potential,Idaho
2026 20271 : 2030 2035 2045
Baseline Forecast(GWh) 397 392 386 375 350 309
Cumulative Savings(GWh)
Technical Achievable Potential 4 7 12 21 45 60
Technical Potential 5 10 15 27 56 73
Cumulative Savings(%of Baseline)
Technical Achievable Potential 0.9% 1.9% 3.0% 5.6% 12.9% 19.3%
Technical Potential 1.2% 2.5% 4.0% 7.2% 15.9% 23.6%
Cumulative Savings(aMW)
Technical Achievable Potential 0.4 0.8 1.3 2.4 5.2 6.8
Technical Potential 0.5 1.1 1.7 3.1 6.3 8.3
Figure 5-12Industrial Cumulative Conservation Potential as a %of the Baseline Projection, Washington
25.0%
20.0%
15.0% -
%of Baseline
10.0%
5.0%
2026 2027 2028 2030 2035 2045
■Technical Achievable Potential ■Technical Potential
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Figure 5-13 Industrial Cumulative Conservation Potential as a %of the Baseline Projection, Idaho
25.0%
20.0%
15.0%
of Baseline
10.0%
5.0
■■I
0.0%
2026 2027 2028 2030 2035 2045
■Technical Achievable Potential ■Technical Potential
Figure 5-14 presents a forecast of cumulative industrial energy savings by end use in Washington.
Motor and process end uses make up most of the savings potential in the study horizon.
Figure 5-14 Industrial Cumulative Achievable Technical Potential by End Use, Washington
100
90 ■Cooling
80
■Space Heating
70
Ventilation
60
GWh 50 Interior Lighting
40
■Exterior Lighting
30 ■Process
20 ■Motors
10 ■Miscellaneous
2026 2028 2030 2032 2034 2036 2038 2040 2042 2044
Table 5-14 identifies the top 20 industrial measures from the perspective of cumulative energy
savings by 2045. In Washington, the top measure is linear lighting, which includes savings for
network embedded controls. The measure with the second highest savings is pumping system
optimization, which is the biproduct of the baseline consumption of pumping systems. Installation
of advanced-efficiency industrial motors rounds out the top three.
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Appendix C
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Table 5-14 Industrial Top 20 Measures in 2045, Washington
04
Rank Industrial Measure Cumulative Total
Savings(MWh)
1 Linear Lighting-LED 10,688 12.3%
2 Pumping System-System Optimization 8,945 10.3%
3 Advanced Industrial Motors 8,467 9.8%
4 Pumping System-Controls 7,599 8.8%
5 High-Bay Lighting-LED 6,647 7.7%
6 Fan System-Equipment Upgrade 5,073 5.9%
7 Material Handling-Upgrade and Optimization 4,122 4.8%
8 Retrocommissioning 3,976 4.6%
9 Compressed Air-Equipment Upgrade 3,318 3.8%
10 Fan System-Controls 3,214 3.7%
11 Pumping System-Equipment Upgrade 2,919 3.4%
12 Strategic Energy Management 2,705 3.1%
13 Ventilation-Variable Air Volume 2,154 2.5%
14 Compressed Air-End Use Optimization 1,959 2.3%
15 Fan System-Flow Optimization 1,885 2.2%
16 HVAC-Energy Recovery Ventilator 1,538 1.8%
17 Connected Thermostat-ENERGY STAR(1.0) 1,360 1.6%
18 Interior Lighting-Retrofit-Networked Lighting Controls 1,334 1.5%
19 Insulation-Ceiling 1,183 1.4%
20 Compressed Air-System Controls 1,013 1.2%
Total of Top 20 Measures 80,098 92.4%
Total Cumulative Savings 86,661 100.0%
Figure 5-15 presents a forecast of cumulative industrial energy savings by end use in Idaho. Like
Washington, the motor and lighting end uses make up most of the savings potential in the study
horizon.
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Figure 5-15 Industrial Cumulative Achievable Technical Potential by End Use,Idaho
70 —
60 — ■Cooling
■Space Heating
50
Ventilation
40
GWh Interior Lighting
30 ■Exterior Lighting
20 ■Process
■Motors
10
■Miscellaneous
2026 2028 2030 2032 2034 2036 2038 2040 2042 2044
Table 5-15 identifies the top 20 industrial measures from the perspective of cumulative energy
savings by 2045 in Idaho. Like Washington, the top three measures are linear Lighting, pumping
system optimization, and advanced industrial motors.
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Table 5-15 Industrial Top 20 Measures in 2045,Idaho
04
TotalRank Industrial Measure Cumulative
Savings(MWh)
1 Linear Lighting-LED(152 lm/W system)w/Controls 7,549 12.7%
2 Advanced Industrial Motors 6,264 10.5%
3 Pumping System-System Optimization 5,114 8.6%
4 High-Bay Lighting-LED(181 lm/W)w/Controls 4,754 8.0%
5 Pumping System-Controls 4,331 7.3%
6 Fan System-Equipment Upgrade 3,788 6.4%
7 Material Handling-Upgrade and Optimization 3,076 5.2%
8 Retrocommissioning 2,960 5.0%
9 Fan System-Controls 2,384 4.0%
10 Compressed Air-Equipment Upgrade 2,133 3.6%
11 Strategic Energy Management 2,013 3.4%
12 Pumping System-Equipment Upgrade 1,677 2.8%
13 Ventilation-Variable Air Volume 1,638 2.7%
14 Fan System-Flow Optimization 1,385 2.3%
15 Compressed Air-End Use Optimization 1,342 2.3%
16 HVAC-Energy Recovery Ventilator 1,308 2.2%
17 Connected Thermostat-ENERGY STAR(1.0) 1,013 1.7%
18 Interior Lighting-Networked Lighting Controls 912 1.5%
19 Insulation-Ceiling 856 1.4%
20 Compressed Air-System Controls 683 1.1%
Total of Top 20 Measures 55,178 92.6%
Total Cumulative Savings 59,568 100.0%
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Appendix C
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6 1 Demand Response Potential
AEG has been working with Avista to estimate demand response (DR) potential since 2014. During
that first study,AEG and The Brattle Group assessed winter demand response potential for Avista's
C&I sectors in Washington and Idaho. Since then, AEG has performed five additional DR potential
assessments including the current study expanding the scope and making improvements along the
way as additional DR programs are run around the country.
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 to Avista 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 6-1 outlines the analysis approach used to develop potential and cost estimates, with each
step described in more detail in the subsections that follow.
Figure 6-1 Demand Response Analysis Approach
Potential
•. Estinnati.•
•Segment by •Align with • DLC Measure •Achievable
Sector, efficiency Options Technical
Geography analysis • DR Economic •Realistic
and Size •Use DR Options Achievable
•Align with EE Segmentation • DSR Options •Pilot Realistic
Analysis •Account for Achievable
Interactions
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.
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-
use saturations of the controllable equipment types in each market segment and coincident peak
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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 6-1 summarizes the market segmentation developed for this study.
Table 6-1 Market Segmentation
SegmentationMarket
Dimensions . •
1 State Idaho
Washington
Residential Service
Customer Class General Service: Rate Schedule 11
2
(by rate schedule) Large General Service: Rate Schedule 21
Extra Large General Service: Rate Schedule 25
AEG excluded Avista's two largest industrial customers from the analysis because they are so large
and unique that a segment-based modeling approach is not appropriate.To accurately estimate DR
potential for these customers,we would need to develop a detailed understanding of their industrial
processes and associated possibilities for load reduction. We would also need to develop specific
DR potential estimates for each customer.Avista may wish to engage these large customers directly
to gauge interest in participating in DR programs.
Baseline Forecast
Once the customer segments were defined and characterized, AEG developed the baseline
projection. Load and consumption characteristics, including customer count and coincident peak
demand values, were provided by Avista load forecasts and aligned with the 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 6-2 Baseline Customer Forecast by Customer Class, Washington
State 2026 20271 1 14
Residential 250,635 254,016 257,195 281,642 285,319
General Service 24,761 24,975 25,204 26,869 27,116
Large General Service 1,538 1,526 1,514 1,433 1,421
Extra Large General Service 21 21 21 21 21
Table 6-3 Baseline Customer Forecast by Customer Class,Idaho
State 2026 20271 1 14
Residential 130,883 132,911 134,923 150,303 152,639
General Service 18,519 18,787 19,056 21,046 21,347
Large General Service 593 567 540 540 540
Extra Large General Service 11 11 11 11 11
Summer and Winter Peak Load Forecasts by State
AEG used the baseline peak demand forecasts developed by the EE team for the DR model. These
demand forecasts were produced by state and sector(residential, commercial and industrial) using
the coincident summer and winter peaks from annual hourly load shapes by end use. Since demand
response programs were modeled by customer service class, AEG used the energy forecasts
provided by Avista (by rate schedule)to break out the commercial and industrial demand forecasts
into customer class forecasts.
Table 6-4 and Table 6-5 show the summer and winter system peak for selected future years. The
Summer and Winter peaks are expected to increase by 23%and 30%respectively between 2026 and
2045.
Table 6-4 Baseline July Summer System Peak Load(MW @Generation)by State
State 2026 20271 1 14
Washington 1,234 1,226 1,214 1,357 1,560
Idaho 605 604 592 641 699
Summer Total 1,839 1,829 1,806 1,998 2,258
Table 6-5 Baseline February Winter System Peak Forecast(MW @Generation)by State
State 2026 20272028 2035 2045
Washington 1,237 1,248 1,235 1,336 1,662
Idaho 620 625 620 669 760
Winter Total 1,857 1,873 1,855 2,004 2,422
Figure 6-2 shows the state contribution to the estimated system coincident summer peak. In 2026,
system peak load for the summer is 1,839 MW at the grid or generator level.Washington contributes
67% to the summer system peak, while Idaho contributes 33%. Summer coincident peak load is
expected to grow by an average of 1%annually from 2026-2045.
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Figure 6-2 Coincident Peak Load Forecast by State(Summer)
2,500
2,000
1,500
1,000
500
■Idaho ■Washington
Figure 6-3 shows the state contribution to the estimated system coincident winter peak forecast. In
2026, system peak load for the winter is 1,857 MW at the grid or generator level. The winter system
peak is about 1% higher in 2026 than the summer peak. Like in summer, Washington contributes
67% to the winter system peak, while Idaho contributes 33%. Over the study period, winter
coincident peak load is expected to grow by an average of 1.3%annually.
Figure 6-3 Coincident Peak Load Forecast by State(Winter)
2,500
2,000
1,500
1,000
500
T,
■Idaho ■Washington
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
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of DR options was determined, AEG characterized each option. Several options could also have an
ancillary component depending on the end use and if they could be used as a fast DR tool.
Each selected option is described briefly below.
Program Descriptions
Direct Load Control of Central Air Conditioners
The Direct Load Control (DLC) of Central Air Conditioners (Central AC) targets Avista's Residential
and General Service customers with qualifying equipment in Washington and Idaho. This program
directly controls Central AC load in summer through a load control switch placed on a customer's
air conditioning unit. During events, the Central AC units are cycled on and off. Participation is
expected to be shared with the Smart Thermostats DLC-Cooling program in the integrated scenario
since the programs target the same end-use technology.
DLC Smart Thermostats—Heating/Cooling
These programs use the two-way communicating ability of smart thermostats to cycle heating and
cooling end uses on and off during events. The programs target Avista's Residential and General
Service customers with qualifying equipment in Washington and Idaho.This program was assumed
to be Bring Your Own Thermostat (BYOT); therefore, no equipment or installation costs were
estimated. The cooling and heating programs are modeled separately because the impact
assumptions are quite different; however, the heating program is assumed to piggyback off the
cooling program. Therefore, development and administrative costs were estimated only for the
cooling program. In addition, the participation in the heating program was a subset of the cooling
program participants based on typical heating program participation rates.
CTA-2045 Grid Interactive Water Heater
The CTA-2045 Grid Interactive Water Heater program targets Avista's Residential and General
Service customers in Washington.These water heaters contain a communicating module interface
and can seamlessly fit into a DR program as these become more prevalent in the Avista territory.
Idaho is not mandating this equipment yet;therefore,this program is only modeled for Washington.
Water heaters would be completely turned off during the DR event period.Water heaters of all sizes
are eligible for control. A $150 cost to Avista is expected for each module with an additional
provisioning cost of $100 for each customer (since only 20% of customers will need help
provisioning,a$20 average provisioning cost is applied.)To provide additional granularity,AEG broke
out the participation in this program across electric resistance and heat pump water heaters in the
state of Washington, according to the latest saturation surveys used in the energy efficiency study.
Results are presented separately in this study across the two end-use types.This program is planned
to be offered in the future(this study assumes a start date of 2026).
DLC Water Heating
Because the Grid Interactive Water Heater program is only available in Washington,the DLC Water
Heater program targets Avista's Residential and General Service customers in Idaho. This program
directly controls water heating load throughout the year for these customers through a load control
switch.Water heaters would be completely turned off during the DR event period.The event period
is assumed to be 50 hours during the summer months and another 50 hours during the winter
months. Water heaters of all sizes are eligible for control. AEG assumes a $160 cost to Avista for
each switch,a$200 installation fee,and a permit and license cost of$100 for residential participants
($125 for general service participants).
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Appendix C
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DLC Smart Appliances
The DLC Smart Appliances program uses a wi-fi hub to connect smart wi-fi enabled appliances such
as washers, dryers, refrigerators, and water heaters. During events throughout the year, the smart
appliances are cycled on and off. The program targets Avista's Residential and General Service
customers in Washington and Idaho.A low steady-state participation rate of 5% is assumed for this
program.
Third Party Contracts
Third Party Contracts are assumed to be available for Large General Service,and Extra Large General
Service customers year-round.' For the Large and Extra Large General Service customers, AEG
assumes they will engage in firm curtailment. It is also assumed that participating customers will
agree to reduce demand by a specific amount or curtail their 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 $/kW-month or$/kW-year). Customers are paid to
be on call even though actual load curtailments may not occur.The amount of the capacity payment
typically varies with the load commitment level. In addition to the fixed capacity payment,
participants typically receive a payment for energy reduction during events. Because it is a firm,
contractual arrangement for a specific level of load reduction, enrolled loads represent a firm
resource and can be counted toward installed capacity requirements. Penalties may be assessed
for under-performance or non-performance. Events may be called on a day-of or day-ahead basis as
conditions warrant.
This option is typically delivered by load aggregators and is most attractive for customers with a
maximum demand greater than 200 kW and flexibility in their operations. Industry experience
indicates that aggregation of customers with smaller-sized loads is less attractive financially due to
lower economies of scale. In addition, customers with 24x7 operations, continuous processes, or
with obligations to continue providing service (such as schools and hospitals) are not often good
candidates for this option.
EV V1 G Telematics
The EV V1 G telematics demand response program is an advanced approach to managing electric
vehicle charging that utilizes vehicle telematics systems to control charging based on grid conditions
and energy demand. This program leverages the built-in communication systems in EVs to enable
direct communication between the vehicle and the utility or grid operator.This eliminates the need
for separate charging station hardware to facilitate controlled charging. Avista currently has 98
customers enrolled on this program but is expected to ramp up to 20% of the available EVs in the
next five years.AEG assumed 90%of electric vehicle load could be curtailed on this program.Avista
requested that this program be viewed as a fully-fledged program starting in 2026 to reflect the
technology rollout.Customers are provided a$350 sign-on incentive with an additional$5 per month
if off-peak charging occurs. AEG used the EV forecast from the 2024 Avista DER study to inform the
number of eligible vehicles for this program.
Electric Vehicle Time-of-Use
There is currently an Electric Vehicle Time-of-Use(TOU) program being run in Avista's territory and is
offered to General Service and Large General Service customers with EV loads. The forecasted
5 General Service customers were removed from this program in this study as their loads are too small to justify
the metering and administrative expense by third party aggregator.
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Appendix C
Avista Electric Conservation Potential Assessment for 2026-2045
potential for the electric vehicle TOU program estimated in this study opens this program to the full
fleet of electric vehicles across the General Service and Large General Service classes according to
the electric vehicle forecast performed in the 2024 Avista DER study.
Time-of-Use Pricing
The TOU pricing rate is a standard rate structure where rates are lower during off-peak hours and
higher during peak hours during the day, incentivizing participants to shift energy use to periods of
Lower grid stress. For the TOU rate, there are no events called, and the structure does not change
during the year. Therefore, it is a good default rate for customers that still offers some load-shifting
potential.We assume two scenarios for the TOU rate.An opt-in rate where participants will have to
choose to go on the rate and an opt-out rate where participants will automatically be placed on the
TOU rate and will need to request a rate change if required. This rate is assumed to be available to
Residential and General Service classes.The TOU Opt-in program is planned to be offered as a pilot
offering starting in 2024.
Variable Peak Pricing
The Variable Peak Pricing(VPP) rate is composed of significantly higher prices during relatively short
critical peak periods on event days to encourage customers to reduce their usage. VPP is usually
offered in conjunction with a time-of-use rate, which implies at least three time periods: critical
peak, on-peak and off-peak. The customer incentive is a more heavily discounted rate during off-
peak hours throughout the year (relative a standard TOU rate). Event days are dispatched on
relatively short notice (day ahead or day of), typically for a limited number of days during the year.
Over time, event-trigger criteria become well-established so that customers can expect events
based on hot weather or other factors. Events can also be called during times of system
contingencies or emergencies. In past studies, this rate has been assumed to be offered to all
service classes; however, with the addition of Peak Time Rebate this year, VPP will only be
considered for large and extra-large Service customers.
Peak Time Rebate
The Peak Time Rebate (PTR) program offers participants an incentive for every kW saved during
designated times of high energy demand. Events are called several times per season, and
participants are given incentives in the form of$/kWh saved duringthe event relative to their baseline
usage across previous seasons. The assumptions for this program were based primarily on the
results of Portland General Electric's PTR program and are offered to residential and general service
customers,as not to overlap with the VPP program.
Ancillary Services
Ancillary services refer to functions that help grid operators maintain a reliable electricity system.
Ancillary services maintain the proper flow and direction of electricity,address imbalances between
supply and demand, and help the system recover after a power system event. In systems with
significant variable renewable energy penetration, additional ancillary services may be required to
manage increased variability and uncertainty. In addition, Ancillary Services can provide fast DR
response during grid emergencies. AEG assumes ancillary service DR capabilities are available
across all sectors. Ancillary Service options can be offered to customers who are already on
programs with ancillary capabilities for an additional incentive. For this study, ancillary programs
were modeled for several parent programs: Smart Thermostats- Heating/Cooling, DLC Water
Heating, CTA-2045 Water Heating, Electric Vehicle Charging, and Battery Energy Storage. Ancillary
service results are presented in Appendix D or the Integrated Opt-in scenario.
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Appendix C
Avista Electric Conservation Potential Assessment for 2026-2045
Thermal Energy Storage
Ice Energy Storage,a type of thermal energy storage,is an emerging tech nologythat is being explored
in many peak-shifting applications across the country.This technology involves cooling and freezing
water in a storage container so that the energy can be used later for space cooling. More specifically,
frozen water takes advantage of the large amount of latent energy associated with the phase change
between ice and liquid water, which will absorb or release a large amount of thermal energy while
maintaining a constant temperature at the freezing(or melting)point.An ice energy storage unit turns
water into ice during off-peak times when price and demand for electricity are low,typically at night.
During the day, at peak times, the stored ice is melted to meet all or some of the building's cooling
requirements, allowing air conditioners to operate at reduced loads.
Ice energy storage is primarily being used in non-residential buildings and applications, as modeled
in this analysis, but may see expansion in the future to encompass smaller, residential systems as
well as emerging grid services for peak shaving and renewable integration. Since ice energy storage
is used for space cooling,AEG assumes this program would be available during the summer months
only.
Battery Energy Storage
This program provides the ability to shift peak loads using stored electrochemical energy. Currently,
the main battery storage equipment uses lithium-ion batteries. They are the most cost-effective
battery type on the market today. AEG assumes the battery energy storage option will be available
for all service classes,with the size and cost of the battery varying depending on the level of demand
of the building.
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.
Forthis analysis,we assumed the Behavioral DR program would be offered as part of a Home Energy
Reports program in a typical opt-out scenario.As such,we assume this program would be offered to
residential customers only.Avista does not currently have a Home Energy Report program in place.
Therefore,the Behavioral program is expected to bear the full cost of the program implementation.
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.
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Appendix C
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Participation Rate Assumptions
Table 6-6 below shows the steady-state participation rate assumptions for each demand side
management(DSM)option as well as the basis for the assumptions. Participation for space cooling
is split between DLC Central AC and Smart Thermostat options, so in total,they don't exceed 30%.6
Table 6-6 DSM Steady-State Participation Rates(Percent of Eligible Customers)
Large Extra
DSM OptionLargeResidential General
Service Service Service General
Service
DLC Central AC 10% 10% _ NWPCC DLC Switch cooling
assumption
DLC Smart Thermostats- Piggybacks off cooling-Adjusted to
Heating 5% 3% - reflect realistic participation for
space heating
CTA-2045 Grid Interactive NWPCC Grid Interactive Water
Water Heater(ER/HP) 50% 50% - Heater Assumptions-Ten Year
Ramp Rate
DLC Water Heating 15% 5% Industry experience
DLC Smart Thermostats- 20% 10% NWPCC Smart Thermostat cooling
Cooling assumption
2017 ISACA IT Risk Reward
DLC Smart Appliances 5% 5% - - Barometer—US Consumer Results,
October 2017
Third Party Contracts - 15% 15% Industry Experience
1/3 of TOU opt-in participation rate
EV V1 G Telematics 20% - - - (17%lowered to 15%based on
Avista decision)
Time-of-Use Opt-in 13% 7% Industry experience;Winter impacts
1/2 of summer impacts.
Time-of-Use Opt-out 20% 20%
Based on DTE program achieving
Electric Vehicle TOU Opt-in 20% 10% 2500 EV enrollments in 3 years,with
similar base EV population
Variable Peak Pricing 25% 25% OG&E 2019 Smart Hours Study
Peak Time Rebate 15% 15% 2021 PGE Res Pricing and
Behavioral Pilot Flex PTR Evaluation
Thermal Energy Storage - 0.5% 1.5% 1.5% Industry Experience
Battery Energy Storage 50% 50% Industry Experience
Behavioral 20% - - - PG&E rollout with six waves(2017)
Load Reduction Assumptions
Table 6-7 presents the per participant load reductions for each DSM option and explains the basis
for these assumptions.The load reductions are shown on a M basis for technology-based options
and a percent load reduction otherwise.
6 NWPCC assumption of 30%participation for a space cooling DR program.
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Appendix C
Avista Electric Conservation Potential Assessment for 2026-2045
Table 6-7 DSM Per Participant Impact Assumptions
Large Extra
Residential General General Large Basis for Assumption
Service Service Service General
Service
NWPCC DLC Switch cooling
DLC Central AC 0.5 kW 1.25 kW - - assumption was close to 1.0 kW
reduced to adjust for Avista proposed
cycling strategy,
DLC Smart Thermostats 1.09 kW 1.35 kW _ _ NWPCC Smart thermostat heating
-Heating assumption(east)
ER:0.4-
CTA-2045 Grid ER:0.2-0.4 0.93 kW BPA 2018 Peak Mitigation(ER/HP)-
Interactive Water Heater kW HP: HP: - - derated to align with Wh proportion of
(ER/HP) 0.9-0.14 kW 0.23- peak load from EE study
0.35 kW
NWPCC Electric Resistance Switch
DLC Water Heating 0.2 kW 0.5 kW Summer Impact,derated to align with
Wh proportion of peak load from EE
study
NWPCC DLC Switch cooling
DLC Smart Thermostats 0.50 kW 1.25 kW _ _ assumption was close to 1.0 kW
-Cooling reduced to adjust for Avista proposed
cycling strategy
Ghatikar,Rish.Demand Response
DLC Smart Appliances 0.14 I<W 0.14 kW - _ Automation in Appliance and
Equipment.Lawrence Berkley National
Laboratory,2017.
2012 Statewide Load Impact Evaluation
of California Aggregator Demand
Third Party Contracts - 21% 21% Response Programs Volume 1:Ex post
and Ex ante Load Impacts;Christensen
Associates Energy Consulting;April 1,
2013
EV V1 G Telematics 90%EV _ _ 90%of Avista Light-Duty Vehicle
Average Load or 0.65 kW
1.5%-4% 0.1%_ Avista projected impacts per customer
Time-of-Use Opt-in (w/s) 0 2% (2024);Winter impacts 1/2 of summer
impacts-lowered impacts from 2022
Time-of-Use Opt-out 0.2%-1.5% 0.1%-
(w/s) 0.2%
Electric Vehicle TOU 100%of Avista Light-Duty Vehicle
Opt-in
100%EV 100%EV Average Load or 0.72 kW GS,6.67 kW
LGS
OG&E 2019 Smart Hours Study;
Variable Peak Pricing 10% 4% 4% 4% Summer Impacts Shown(Winter
impacts 3/4 summer)
PGE Res Pricing and Behavioral Pilot
Peak Time Rebate 7.1%(W) 3.6%(W) Flex PTR Evaluation 2021:0.159 or 8.2%
in summer,0.134 or 7.1%in winter
Thermal Energy Storage 8.2%(S) 4.1%(S) 1.5% 1.5% Industry Experience
NREL 2021:5 kW battery*86%round
Battery Energy Storage 2 kW 2 kW 15 kW 15 kW trip efficiency.Xcel Energy CO
Renewable Battery Connect:40%
retention
Behavioral 2% _ _ Opower documentation for BDR with
Consumers and Detroit Energy
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Appendix C
Avista Electric Conservation Potential Assessment for 2026-2045
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.
Integrated DR Potential Results
This section presents analysis results for demand savings and levelized costs for all considered DR
programs. In the interest of succinctness, AEG only presents the Integrated TOU Opt-in scenario
results in this chapter.The integrated approach represents Realistic Achievable Potential and is the
most realistic scenario allowing for multiple DR programs to be run at the same time employing a
hierarchy that eliminates double counting of impacts.
All potential results represent savings at the generator.
The following sections separate out the integrated potential results for the summer and winter
seasons.
Summary TOU Opt-in Scenario
Table 6-8,Table 6-9, and Figure 6-4 show the total summer and winter demand savings for selected
years. These savings represent integrated savings from all available DR options in Avista's
Washington and Idaho service territories.
Summer TOU Opt-In Scenario:Total potential savings are expected to increase from 16 MW in
2026 to 184 MW by 2045.The percentage of system peak increases from 0.8%in 2026 to 8.2%by
2045.
- Winter TOU Opt-In Scenario: The total potential savings are expected to increase from 11 MW
in 2026 to 155 MW by 2045. The percentage of system peak goes from 0.6% in 2026 to 6.5% by
2045.
Table 6-8 Summary of Integrated TOU Opt-in Potential(MW @ Generator),Summer
2026 20271 1 14
Baseline Forecast(Summer MW) 1,839 1,829 1,806 1,998 2,258
Achievable Potential (MW) 15.6 33.7 61.6 127.7 184.2
Achievable Potential (%of baseline) 0.9% 1.9% 3.5% 6.5% 8.3%
Potential Forecast 1,823 1,796 1,744 1,870 2,074
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Appendix C
Avista Electric Conservation Potential Assessment for 2026-2045
Table 6-9 Summary of Integrated TOU Opt-in Potential(MW @ Generator), Winter
2026 20271 1 14
Baseline Forecast(Winter MW) 1,857 1,873 1,855 2,004 2,422
Achievable Potential(MW) 11.1 23.0 39.1 100.5 154.8
Achievable Potential(%of baseline) 0.6% 1.3% 2.2% 5.1% 6.5%
Potential Forecast 1,846 1,850 1,816 1,904 2,267
Figure 6-4 Summary of Integrated TOU Opt-In Potential(MW @ Generator)
Summer Winter
2,500 2,500
2,000 2,000
1,500 1,500
MW 1,000 MW 1,000
500 500
0 O L R o 1b O L R pL° oL4 0 0 1 1 1 OHO o1L OAR
,LODE ,LODE ,LOR ti ti ti ti ti ti ti ti ti ti
Baseline Forecast(Winter MW)
Baseline Forecast(Summer
MW) —Potential Forecast
Summer Opt-in TOU Scenario
Key findings from the summer integrated Opt-in TOU scenario include:
• The EV V1 G Telematics Program has the highest potential savings with 47.1 MW by 2045.
DLC Smart Thermostats (33.4 MW) and Third Party Contracts (26.6 MW) have the next-highest
potential savings, respectively.
• Most of the DR potential in both Washington and Idaho comes from the residential customer
class.
Potential by DSM Option
Figure 6-5 and Table 6-10 showthe summer demand savings from individual DR options.The savings
represent integrated savings from all available DR options in Avista's Washington and Idaho service
territories. Total potential savings as a percentage of summer peak are expected to increase from
1% in 2026 to 8% by 2045.
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Appendix C
Avista Electric Conservation Potential,Assessment for 2026-2045
Figure 6-5 Summary of Summer Potential by Option-TOU Opt-In(MW @ Generator)
_Peak Time Rebate
200
■Variable Peak Pricing Rates
180 - ■Time-of-Use Opt-out
160 ■Time-of-Use Opt-in
■Third Party Contracts
140 ■Thermal Energy Storage
Achievable Potential
(MW) 120 ■Electric Vehicle TOU Opt-in
100 ■DLC Water Heating
■DLC Smart Thermostats-Cooling
80 ■DLC Smart Appliances
60 ■DLC Electric Vehicle Charging
40 ■DLC Central AC
■CTA-2045 ERWH
20 ■CTA-2045 H PW H
■Behavioral
2026 2027 2028 2035 2045 ■Battery Energy Storage
Table 6-10 Summary of Summer Potential by Option-TOU Opt-In(MW @ Generator)
Summer Potential 20261 128 2035 2045
Baseline Forecast(Summer MW) 1,839 1,829 1,806 1,998 2,258
Achievable Potential(MW) 16 34 62 128 184
Achievable Potential(%) 1% 2% 3% 6% 8%
Battery Energy Storage 0.0 0.1 0.3 6.7 12.7
Behavioral 1.1 1.7 1.9 2.2 2.2
CTA-2045 HPWH 0.0 0.0 0.1 3.5 8.5
CTA-2045 ERWH 0.1 0.2 0.5 4.9 2.4
DLC Central AC 1.2 3.6 8.1 12.8 15.4
EV V1 G Telematics 1.2 3.6 5.8 18.8 47.1
DLC Smart Appliances 0.3 0.9 2.2 3.5 4.0
DLC Smart Thermostats-Cooling 2.3 7.0 16.6 27.4 33.4
DLC Smart Thermostats-Heating - - - - -
DLC Water Heating 0.3 0.8 1.9 3.0 3.5
Electric Vehicle TOU Opt-in 0.1 0.3 0.6 3.1 9.6
Thermal Energy Storage 0.0 0.1 0.3 0.6 0.6
Third Parry Contracts 7.9 12.5 17.0 24.1 26.6
Time-of-Use Opt-in 0.2 0.4 0.8 2.9 3.0
Time-of-Use Opt-out - - - - -
Variable Peak Pricing Rates 0.6 1.6 3.6 6.5 7.2
Peak Time Rebate 0.3 0.7 1.9 7.6 7.9
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Appendix C
Avista Electric Conservation Potential Assessment for 2026-2045
Potential by Sector and Segment
Table 6-11 and Table 6-12 show the total summer demand savings by class for Washington and
Idaho, respectively. Washington is projected to save 144 MW (9.2% of summer peak demand) by
2045,while Idaho is projected to save 40 MW(5.7%of summer peak demand) by 2045.
Table 6-11 Summer Potential by Class-TOU Opt-In(MW @ Generator),Washington
2026 20271 1 14
Baseline Forecast(Summer MW) 1,234 1,226 1,214 1,357 1,560
Achievable Potential(MW) 14 29 48 95 144
Residential 5.0 13.5 27.0 61.3 99.1
General Service 0.4 1.0 2.3 9.9 15.2
Large General Service 5.1 8.4 11.0 15.5 21.2
Extra Large General Service 3.4 5.6 7.5 8.2 8.5
Table 6-12 Summer Potential by Class-TOU Opt-In(MW @ Generator),Idaho
2026 20271 1 14
Baseline Forecast(Summer MW) 605 604 592 641 699
Achievable Potential(MW) 2 5 14 33 40
Residential 1.5 4.4 10.4 21.1 25.7
General Service 0.1 0.4 0.9 3.5 5.6
Large General Service 0.0 0.0 0.0 4.4 5.3
Extra Large General Service 0.1 0.3 2.4 3.9 3.6
Figure 6-6 Summer Potential by Class-TOU Opt-In(MW @Generator),Washington
160
140 -
120 Extra Large General Service
100 _
Achievable ■Large General Service
Potential(MW) 80
■General Service
60
40 ■Residential
20
2026 2027 2028 2035 2045
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Appendix C
Avista Electric Conservation Potential Assessment for 2026-2045
Figure 6-7 Summer Potential by Class-TOU Opt-In(MW @Generator),Idaho
50
40
Extra Large General Service
Achievable 30
Potential(MW) ■Large General Service
20
■General Service
10 ■Residential
2026 2027 2028 2035 2045
Winter Opt-in TOU Scenario
Key findings from the winter integrated Opt-in TOU scenario include:
The highest potential options are V1 G Telematics (47.1 MW by 2045) and Third-Party Contracts
(21.0 MW by 2045).
DLC Smart Thermostats have much lower potential savings for heating (14.6 MW by 2045) than
cooling as the heating program is expected to piggyback off the cooling program and be a subset
of the cooling participants.
In previous studies, Variable Peak Pricing has shown high potential savings in both summer and
winter seasons. However, since Variable Peak Pricing is only being considered for large and extra-
large customer classes in this study,the potential is much lower(5.7 MW by 2045)7.
Potential by DSM Option
Figure 6-8 and Table 6-16 presents the levelized costs per kW of equivalent generation capacity over
2026-2035 for Washington and Idaho.The ten-year net present value(NPV)MW potential by program
is also shown for reference in the first two columns. Some options are only available in summer or
winter, such as Thermal Energy Storage,Smart Thermostat programs, and DLC Cooling.
Key findings include:
The Battery Energy Storage option is one of the least expensive programs per kW saved at$34.9
and$35.9/kW-year for winter and summer seasons over the first ten years of the program.This is
a dramatic shift from previous studies. A big contributor to this change is the change is the
addition of the battery storage forecast that was performed for the Avista DER study. This along
with the assumption that this would be a BYOD program added savings potential and reduced
costs.
The Third Party Contracts option delivers the highest savings (96 MW and 137 MW in winter and
summer respectively) by 2035 at approximately $108.5/kW-year cost in winter and $75.5/kW-
year cost in summer. Capacity-based and energy-based payments to the third-party constitutes
the major cost component for this option. All O&M and administrative costs are expected to be
incurred by the representative third-party contractor.
The PTR Program is modeled to target residential and general service customers
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Appendix C
Avista Electric Conservation Potential Assessment for 2026-2045
The Variable Peak Pricing option has the lowest levelized cost among all the DR options. It
delivers 22.7 MW of winter savings and 32.9 MW of summer savings by 2035 at $28.1/kW-year
system-wide and 18.68 MW of summer savings at $19.4/kW-year system-wide. Enabling
technology purchase and installation costs for enhancing customer response is a large part of
deployment costs.
Table 6-16 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 and
Idaho service territories.The total potential savings in the Winter TOU Opt-in scenario are expected
to increase from 11 MW in 2026 to 155 MW by 2045. The respective increase in the percentage of
system peak goes from 1% in 2026 to 7% by 2045.
Figure 6-8 Summary of Winter Potential by Option-TOU Opt-In(MW @ Generator)
180 Peak Time Rebate
160 ■Variable Peak Pricing Rates
■Time-of-Use Opt-out
140
■Time-of-Use Opt-in
120 ■Third Party Contracts
Achievable Potential 100 ■Electric Vehicle TOU Opt-in
(MW) ■DLC Water Heating
80 ■DLC Smart Thermostats-Heating
60 ■DLC Smart Appliances
■DLC Electric Vehicle Charging
40
CTA-2045 ERWH
20 ■CTA-2045 HPWH
■Behavioral
2026 2027 2028 2035 2045 ■Battery Energy Storage
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Appendix C
Avista Electric Conservation Potential Assessment for 2026-2045
Table 6-13 Summary of Winter Potential by Option-TOU Opt-In(MW @ Generator)
Winter Potential 20261 128 2035 2045
Baseline Forecast(Winter MW) 1,819 1,835 1,817 1,963 2,375
Achievable Potential(MW) 11 23 39 101 155
Achievable Potential(%) 1% 1% 2% 5% 7%
Battery Energy Storage 0.0 0.1 0.2 6.6 13.0
Behavioral 1.4 2.2 2.5 3.0 3.2
CTA-2045 HPWH 0.0 0.0 0.1 5.5 13.2
CTA-2045 ERWH 0.1 0.5 1.1 11.4 5.6
DLC CentraLAC - - - - -
EV V1 G Telematics 1.2 3.6 5.8 18.8 47.1
DLC Smart Appliances 0.3 0.9 2.2 3.5 4.0
DLC Smart Thermostats-Cooling - - - - -
DLC Smart Thermostats-Heating 0.8 2.5 6.0 10.9 14.6
DLC Water Heating 0.3 0.8 1.9 3.0 3.5
Electric Vehicle TOU Opt-in 0.1 0.3 0.6 3.1 9.6
Thermal Energy Storage - - - - -
Third Party Contracts 5.8 9.3 12.6 16.8 21.0
Time-of-Use Opt-in 0.2 0.6 1.0 4.0 4.2
Time-of-Use Opt-out - - - - -
Variable Peak Pricing Rates 0.4 1.2 2.6 4.5 5.7
Peak Time Rebate 0.3 0.9 2.4 9.4 10.1
Potential by Sector and Segment
Table 6-14 and Table 6-15 show the total winter demand savings by class for Washington and Idaho,
respectively.Washington is projected to save 128 MW(7.7%of winter system peak demand)by 2045,
while Idaho is projected to save 27 MW(3.5%of winter system peak demand) by 2045.
Table 6-14 Winter Potential by Class-TOU Opt-In(MW @Generator), Washington
2026 20271 1 14
Baseline Forecast(Winter MW) 1,237 1,248 1,235 1,336 1,662
Achievable Potential(MW) 10 21 33 79 128
Residential 3.9 9.8 17.6 53.1 87.6
General Service 0.3 0.6 1.3 9.8 15.6
Large General Service 3.9 6.5 8.6 11.3 18.6
Extra Large General Service 2.3 3.8 5.1 5.2 6.2
Table 6-15 Winter Potential by Class-TOU Opt-In(MW @Generator),Idaho
2026 2027 20281 14
Baseline Forecast(Winter MW) 620 625 620 669 760
Achievable Potential(MW) 1 2 6 21 27
Residential 0.6 1.9 4.4 13.3 16.8
General Service 0.0 0.2 0.4 2.0 3.6
Large General Service 0.0 0.0 0.0 3.3 4.1
Extra Large General Service 0.1 0.2 1.6 2.5 2.3
Applied Energy Group,Inc.I appliedenergygroup.com A-60 of 89

Appendix C
Avista Electric Conservation Potential Assessment for 2026-2045
Figure 6-9 Winter Potential by Class—TOU Opt-In(MW @Generator), Washington
140
120
100 Extra Large General Service
Achievable 80 ■Large General Service
Potential(MW)
60 ■General Service
40
■Residential
20
2026 2027 2028 2035 2045
Figure 6-10 Winter Potential by Class—TOU Opt-In(MW @Generator),Idaho
30
25
20 Extra Large General Service
Achievable
Potential(MW) 15 ■Large General Service
■General Service
10
■Residential
5
2026 2027 2028 2035 2045
I-evelized Costs
Table 6-16 presents the levelized costs per kW of equivalent generation capacity over 2026-2035 for
Washington and Idaho.The ten-year net present value(NPV) MW potential by program is also shown
for reference in the first two columns.Some options are only available in summer or winter, such as
Thermal Energy Storage, Smart Thermostat programs, and DLC Cooling.
Key findings include:
Applied Energy Group,Inc.I appliedenergygroup.com A-61 of 89

Appendix C
Avista Electric Conservation Potential Assessment for 2026-2045
The Battery Energy Storage option is one of the least expensive programs per kW saved at$34.9
and$35.9/kW-year for winter and summer seasons over the first ten years of the program.This is
a dramatic shift from previous studies. A big contributor to this change is the change is the
addition of the battery storage forecast that was performed for the Avista DER study. This along
with the assumption that this would be a BYOD program added savings potential and reduced
costs.
The Third Party Contracts option delivers the highest savings (96 MW and 137 MW in winter and
summer respectively) by 2035 at approximately $108.5/kW-year cost in winter and $75.5/kW-
year cost in summer. Capacity-based and energy-based payments to the third-party constitutes
the major cost component for this option. All O&M and administrative costs are expected to be
incurred by the representative third-party contractor.
The Variable Peak Pricing option has the lowest levelized cost among all the DR options. It
delivers 22.7 MW of winter savings and 32.9 MW of summer savings by 2035 at $28.1/kW-year
system-wide and 18.68 MW of summer savings at $19.4/kW-year system-wide. Enabling
technology purchase and installation costs for enhancing customer response is a large part of
deployment costs.
Table 6-16 Levelized Program Costs and Potential(TOU Opt-In)
NPVWinter NPV Summer Winter Summer
IDSM Option -• Levelized
CostsPotential MW Potential MW
Battery Energy Storage 19.52 18.51 $34.06 Costs$35.93
Behavioral 19.31 14.45 $111.56 $149.13
DLC Central AC 64.72 $162.56
EV V1 G Telematics 64.90 64.90 $414.85 $414.85
DLC Smart Appliances 17.79 17.79 $415.98 $415.98
DLC Smart Thermostats-Cooling 136.67 $362.76
DLC Smart Thermostats-Heating 51.56 $25.90
DLC Water Heating 15.23 15.23 $632.73 $632.73
CTA-2045 ERWH 29.98 12.97 $181.26 $419.16
CTA-2045 HPWH 9.14 5.87 $748.50 $1,164.34
Thermal Energy Storage 3.05 $913.92
Third Party Contracts 95.49 137.17 $108.49 $75.53
Time-of-Use Opt-in 18.52 13.87 $215.37 $287.62
Time-of-Use Opt-out
Electric Vehicle TOU Opt-in 9.12 9.12 $69.45 $69.45
Variable Peak Pricing Rates 22.71 32.91 $28.11 $19.40
Peak Time Rebate 42.75 34.91 $84.63 $103.64
Applied Energy Group,Inc.i appliedenergygroup.com A-62 of 89

Appendix C
Avista Electric Conservation Potential Assessment for 2026-2045
Al
MARKET PROFILES
This appendix presents the market profiles for each sector and segment for Washington and Idaho,
in the embedded spreadsheet.
14-:�:
Avista 2024-Electric
Market Profiles.xlsx
Applied Energy Group,Inc.I appliedenergygroup.com A-63 of 89

Appendix C
Avista Electric Conservation Potential Assessment for 2026-2045
6I
MARKET ADOPTION (RAMP) RATES
This appendix presents the PowerCouncil'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
2039 2040 2041
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%
Retrol2Med 11% 11% 11% 11% 11% 10% 8% 6% 5% 4% 3% 3% 2% 2% 1% 1% 0% 0% 0% 0%
RetroSMed 4% 5% 6% 8% 9% 10% 11% 11% 11% 9% 7% 5% 3% 1% 1% 0% 0% 0% 0% 0%
Retrol Slow 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%
B-1 of 89

Appendix C
C �
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.
Applied Energy Group•www.appliedenergygroup.com C-1 of 89

Appendix C
Applied Energy Group, Inc.
2300 Clayton Road
Suite 1370
Concord, CA 94520
P: 510-982-3526

Appendix D
2025 Electric Integrated
Resource Plan
Appendix D — 1 0-Year
Transmission/ Distribution Plan
°,VV 1sra

Appendix D
I ,l
2023 Avista System Plan
f.3 1 s �M�i�lilrfi
#� _
fr+ 9
yyy((( s
r
0r y
Sunset Station, Spokane, Washington
Transmission System Planning
Avista Utilities
PO Box 3727, MSC-16
Spokane, WA 99220
[e-mail]
Prepared by: System Planning
Version Date Description Author Review
v0 2/7/2024 Released David Thompson John Gross

System Plan 202appendix D
Table of Contents
1. System Planning Overview ...................................................................................... 3
2. System Project List ..................................................................................................4
3. Major System Projects ............................................................................................. 7
3.1. ERT #12: Carlin Bay Station ............................................................................. 7
3.2. ERT #58: Westside Station Rebuild.................................................................. 9
3.3. ERT #62: Lolo Transformer Replacement....................................................... 10
3.4. ERT #131: Garden Springs Station................................................................. 11
3.5. ERT #143: Waikiki Capacity Mitigation ........................................................... 12
3.6. ERT #148: Barker Capacity Mitigation ............................................................ 13
4. Project Prioritization ............................................................................................... 14
5. Project Schedule.................................................................................................... 17
Page 2 of 17

System Plan 202:Appendix D
1 . System Planning Overview
Avista's System Planning department's core responsibilities include the development of
a system plan for system reinforcements to meet transmission system needs for load
growth, adequate transfer capability, requests for generation interconnections, line and
load interconnections, and long-term firm transmission service.
The development of the system plan follows a two-year process with four phases.
Stakeholders have opportunities to participate in the development of the system plan by
collaborating with System Planning and providing comments.
• Phase 1 includes establishing the assumptions and models for use in the
technical studies, developing and finalizing a Study Plan, and specifying the
public policy mandates planners will adopt as objectives in the current study
cycle.
• Phase 2 includes performing necessary technical studies and development of the
Planning Assessment. The results of the technical studies are documented in the
Planning Assessment, including conceptual solutions to mitigate performance
issues.
• Phase 3 includes providing the Avista System Plan report to stakeholders. The
Avista System Plan will include documentation of the electrical infrastructure plan
with preferred solution options. The resulting project list will include additional
information regarding projects and system modifications developed through
means other than the technical studies.'
• Phase 4 comprises most of the year two in the two-year process and includes
refining the preferred plan of service. Conceptual projects identified in Phase 2
which have not been fully developed in Phase 3 will be addressed in Phase 4.
Figure 1 provides a visual representation of the four phases through the two-year
process.
PLANNING ASSESSMENT
TIMELINE
PROJECT START REVIEW OF
SUBMISSION OF STUDY LOCAL
D TA RESULTSIDRAFT TRANSMISSION
STUDY TRANSMISSION PLAN UPDATE
DEVELOPMENT PLANS MEETING
MEE ING .40
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
POST MODELS POST AVISTA
POST VISTA SYSTEM PLAN
POST PLANNING SYSTEM PLAN REVISION
ASSESSMENT
FINALIZE STUDY
PLAN
Year 1 Year 2
Phase I Phase 2 Phase 3 Phase 4
cemmem cemmen, cemm.M
Period 1 Period 2 Period 3
Figure 1: Avista Planning Assessment Timeline
Such other means may include,for example,generation interconnection or transmission service request study
processes under the GATT,or joint study team processes within the region.
Page 3 of 17

System Plan I 202:Appendix D
2. System Project List
The System Project List in Table 1 is compiled by Avista's Engineering Roundtable
(ERT). The list includes projects identified in the 2023-2024 System Assessment with
additional projects evaluated and prioritized by the ERT. New projects identified in the
2023-2024 System Assessment which have not been vetted by the ERT are not
included in the System Project List. TPL CAP refers to Corrective Action Plans (CAPs)
to be implemented in accordance with TPL-001-5.
ScopeERT TPIL
# Project Name Driver
Construct new distribution station to include single
20MVA transformer and two feeders. Transmission
Performance integration to include constructing a new radial
12 Carlin Bay and transmission line from O'Gara Station to Carlin Budgeted
Station Capacity Bay. The second phase of the project includes
rebuilding the existing O'Gara Station to a
switching station. New microwave communication
paths will be established to O'Gara Station.
Davenport Asset Rebuild existing distribution station at nearby
32 Station Rebuild Condition greenfield site. Initial construction will include Complete
single 20MVA transformer with three feeders.
Rebuild existing substation at new location. 115kV
Metro Station Asset bus to be a 6-position ring: 2—30MVA
38 Rebuild Condition transformers, 2— 115kV UG lines from PST, 2— Construction
115kV OH lines; switchgear on the 13kV side, both
Network and Distribution feeders
I 40 Northwest Asset Scope not complete. Budgeted I
Station Rebuild Condition Rebuild existing Northwest Station.
43 Valley Station Asset Scope not complete. Budgeted
Rebuild Condition Rebuild existing Valley Station. g
Scope not complete.
Poleline Performance Construct new distribution station to replace Avista
46 (Prairie) and facilities at existing Prairie Station. New station to Budgeted
Station Rebuild Capacity include two 30MVA transformers, four feeders, and
looped-through transmission without circuit
breakers.
Bronx Station Performance Scope not complete.
56 Rebuild and Reconstruct existing Bronx Station to include Budgeted
Capacity distribution facilities.
Replace the existing Westside 230/115kV
Transformer 2 and construct necessary bus work
Westside Performance and breaker positions. Reconstruct 230 and 115kV
58 Station Rebuild and buses to double bus double breaker 3000/2000 Construction Yes
Capacity Amp standard.
Phase 4: Complete bus work to double bus, double
breaker on both the 230kV and 115kV buses
Ninth and Replace the 795 AAC and ACSR conductor on the
Central - Performance Ninth and Central— Sunset 115kV Transmission
60 Sunset 115kV and Line with 795 ACSS with E3X coating to match the Complete
Transmission Capacity
Line Upgrade rest of the line.
Page 4 of 17

System Plan I 202:Appendix D
Scope# Project Name Driver
Rebuild existing Post Falls Station in green field
location adjacent to existing station. New station
Post Falls Customer will be a ring bus configuration with three
61 Station Rebuild Requested transmission line positions, a metered GSU Budgeted
position, and two 115/13kV distribution
transformers. The distribution transformers will
have four feeders connected.
Replace Lolo#1 230/115kV transformer with
250MVA rated transformer.
Lolo Performance Replace Lolo#2 230/115kV transformer with
62 Transformer and 250MVA rated transformer. Construction
Replacement Capacity 115kV circuit breakers, bus work and other
capacity-limiting elements will be replaced. Circuit
switchers at Clearwater, Lolo, and Sweetwater
stations will be replaced.
Add new 30MVA transformer and two distribution
feeders to the existing Huetter Station. Scope
Huetter Station Performance includes a new panel house and rerouting the
80 Expansion and transmission line to the east side of the station. Construction
Capacity 13kV bus tie switch and a 115kV bus tie switch
located on transmission structures outside the
substation will be added.
Scope not complete.
Clearwater Customer New 115kV relay panels installed on all line
95 Station positions. Existing circuit switchers will be replaced Budgeted
Upgrades Requested as part of the Lolo Transformer Replacement
project.
Kettle Falls Upgrade existing protection schemes on the Addy
Protection Mandatory — Kettle Falls and Colville— Kettle Falls 115kV
96 System and Transmission Lines. New relays at Kettle Falls Construction Yes
Upgrades Compliance Station and a new communication path from Kettle
Falls to Mount Monumental are required.
Scope not complete.
New switching station near existing tap to Four
Performance Lakes Station off the South Fairchild Tap 115kV
100 Melville Station and Transmission Line. Construct new transmission Budgeted
Capacity line from Airway Heights to Melville including
passing through Russel Road and Craig Road
distribution stations. Requires new transmission
line terminal at existing Airway Heights Station.
Lyons and
Standard Customer Add new feeder to existing Lyons and Standard
111 Station Requested Station. Construction
Expansion
Pine Street-
Rathdrum Asset
124 115kV Condition Rebuild transmission line. Construction
Transmission
Line Upgrade
Page 5 of 17

System Plan 202:Appendix D
Scope# Project Name Driver
Construct new 115kV portion of Garden Springs
Station at the existing Garden Springs switching
location. New station will terminate Airway Heights
—Sunset and Sunset—Westside 115kV
Performance Transmission Lines including the South Fairchild
Garden
131 Springs Station and Construct new 230kV portion of Garden Springs Budgeted Yes
Capacity Station including two 250MVA nominal 230/115kV
transformers. Construct new 230kV transmission
line from Garden Springs to a new switching
station, Bluebird, at an interconnection point on the
BPA Bell—Coulee#5 230kV Transmission Line.
Customer will construct new distribution station.
134 Craig Road Customer Avista will provide new radial 115kV transmission Budgeted
Interconnection Requested line from Airway Heights Station as part of the g
Melville Station project.
IEP Asset
136 Transformer Condition Replace existing transformer located at IEP. Budgeted
Replacement
Bunker Hill Customer Install new 20MVA transformer to replace existing
140 Customer transformer and construct new dedicated customer Budgeted
Capacity Requested distribution feeder.
Waikiki Performance Add new 20MVA transformer and two feeders to
143 Capacity and existing Indian Trail substation. Budgeted
Mitigation Capacity
Barker Performance Add new 30MVA transformer and three feeders to
148 Capacity and existing Greenacres substation. Budgeted
Mitigation Capacity
Pleasant View Performance Scope not complete.
151 Capacity and Add new 30MVA transformer and two feeders to Budgeted
Mitigation Capacity existing station.
Replace South Othello A57 circuit switcher with
1220kA or greater rated equipment.
Replace Barker Road A316 circuit switcher with
40kA or greater rated equipment.
Replace Francis and Cedar A676 and A677 circuit
switchers with 40kA or greater rated. equipment.
Safely Performance Replace Lakeview R330 circuit switcher with 20kA
156 Interrupting and or greater rated equipment. Budgeted
Faults Capacity Replace Garfield EG-1 transformer fuse with 10kA
or greater rated fuse.
Replace Leon Junction SMD-213 transformer fuse
with 15kA or greater rated fuse.
Replace Long Lake SMD-213 transformer fuse with
15kA or greater rated fuse.
Replace North Moscow SMD-213 transformer fuse
with 15kA or greater rated fuse.
Page 6 of 17

System Plan 202:Appendix D
Scope# Project Name Driver
Rebuild the existing Colbert Tap 115kV
Performance Transmission Line to accommodate new
Colbert Feeder and distribution underbuild. New underbuild to be an Construction
157 Extension extension of COB12F2 which will offload
Capacity COB12F1. Load from COB12F2 will be transferred
to MEA12F3.
Table 1: Avista System Plan project list2
The Generation Interconnection process evaluates Interconnection Customer requests
to connect to Avista's transmission or distribution system at a specified Point of
Interconnection (POI) through an annual Cluster Study. Table 2 lists the senior-queued
projects represented in the electrical system models used for the Cluster Study
analysis.
Queue
Number MW Output Type Scope
I Construct new 115kV station adjacent to existing
Q59 60MW Solar/Storage Roxboro Station for the POI Drafted LGIA
Q60 150MW Solar/Storage 230kV POI at Dry Creek Station Suspended
I Rebuild of station, distribution, and transmission
Q63 26MW Hydro infrastructure LGIA
I Efficiency improvements and GSU upgrade at
Q66 71 MW Wood Waste Kettle Falls Generation Station LGIA
I115kV POI on South Fairchild Tap at customer
Q80 19MW Solar/Storage collection station PURPA
Q84 5MW Solar/Storage 13.8kV POI adjacent to Chewelah Station PURPA
I Q97 100MW Solar/Storage 230kV POI at Lolo Station Suspended
I TCS-03 80MW Solar/Storage 115kV POI at Warden Station I Suspended
TCS-14 I 375MW Wind/Storage 230kV POI at Dry Creek Station Construction
Table 2: Interconnection Generation Projects
3. Major System Projects
The following list is a subset of the project list provided in Section 2. These projects
were selected based on their relative impact to the system performance and the project
scope has been substantially determined. A general problem statement and summary of
project scope is provided. Detailed project reports may be available, containing
additional scope and technical information.
3.1 . ERT #12: Carlin Bay Station
The population and load demand growth on the east side of Lake Coeur D'Alene has
resulted in rising concerns for Avista to reliably support new customers at the far-
reaching end of two distribution feeders. These feeders cannot support additional
growth in the area considering the increased distances are currently pushing limitations
of the 13.8kV distribution system. Issues have emerged, including voltage drop,
2 Accessed from the Engineering Roundtable SharePoint site December 18, 2023.
Page 7 of 17

System Plan 2023ippendix D
reduced fault current, and cold load pickup, all contributing to system protection
challenges.
The complete scope of the Carlin Bay Project will be executed in a phased approach so
immediate concerns are mitigated and operational while the remainder of the scope can
be completed. The complete scope includes the following:
• Phase 1 includes construction of the Carlin Bay Station and a 115kV
transmission line tap from the Benewah — Pine Creek 115kV Transmission Line
near O'Gara to the Carlin Bay Station. The expected in-service date is 2028.
Feeder Feeder
South North
Phase 1 Project Notes
Carlin-Pay-Substation Tap Benewah-Pine Creek 115kV line near
O ; G Gore and Construct approximately 15 miles of
new 115 kV transmission line with GPGW to
Carlin Bey(min rating
Construct new CeCarlinBayay Substation
ation with one
O 115113 8kV distribution transformer and two
distribution feeders
250 WA 2W WA 260 WA '...., __ r�, Future t0
Blue Creek
115 kV to
Pine Creek
,. 11aukV
20 MVA
---------------------------------------------------------------------------------
Legend: O
Existing Facilities
New 230 W
New 115 W 115 kV to
New Distribution /
KEC Distribution Benewah A71 Al2
Al2 A295
O'Gara 115 kV to
Substation St Marles
Figure 2: Carlin Bay Station Phase One Diagram
• Phase 2 includes a rebuild of the O'Gara Station to a breaker and a half
configuration with space for a future line position and future capacitor bank. The
expected in-service date for this work is 2029.
Page 8 of 17

System Plan 202:Appendix D
Feeder Feeder
South North
1 Carlin Bay Substation Phase 2 Proiect Notes:
(�R*Uw(Vora late I is W Weekr sea one
Ma ruDSIMm wlh rr ItSl3tlkv eleameon
tradamer tie aao mraran tsars.
O2 Ow an aaaaaW We poeaon and spas
IN a tun capaalor twit
' O ro pa VaY Paa+rr b ar at2 F.a wa be sap W
2awA naava� aaaavA � Futan llaea
3 anaartyt¢c
Bkra Creek ®aPA b ado nrlrwp to KEC boar
5 (Vora SktdAw vat Yrbaa a w4mware see
O
• b eataolsh s carnacf, b Ilks Park
TL-
v nraw
s rva
`---------------------------------------------------------------------------------'
115 kV to
ExWftFacilbe' O'Gara Pine Creek
Now 230 kV $U��IO-I
Now 115 kV
New Db3a/en
KEC DWr baaoa
115kVto '
Benewah
115 kV to
St Manes
Mica Peak -
nwav
»iew
\` O
3 4
© `�" Feeder C61
?
O'Gara
(
as ova
1 Feeder 6 t
Ise rr
-----------------------------------------
Figure 3: Carlin Bay Station Phase Two Diagram
' 2. ERT #58: Westside Station Rebuild
Outages causing loss of 230/115kV transformers at the BPA Bell or Avista Beacon
Station, or outages causing increased impedance from the Bell and/or Beacon Stations
to the area's distribution stations cause the Westside #1 and #2 230/115kV
transformers to exceed their applicable facility ratings. The Westside Station Rebuild
project is a complete station rebuild which includes the replacement of the existing
Westside #1 and #2 230/115kV transformers with 250MVA nominal capacity
transformers. Both the 230kV and 115kV configurations will be double bus, double
breaker.
Page 9 of 17

System Plan 202appendix D
TB ID
Grand Norttu'East
Coulee Bell Nine
Hia
Direction
O Sixterminal230 kVdouble bus-double
breaker arrangement(two future
terminals-)Transmission line and
230W transformerterminal position will not
impact System performance
20 Two 2301115 W.250MVA.
Autotransformer w/LTC +±=5%
J 3O Eight terminal 115 kV double bus,
double breaker arrangement(three
future terminals-)Transmission line and
} transformer terminal position will not
impact System performance
® Future Two step capacitor bank
CapacityTBD-
OO Future Two distribution transformers per
Distribution Planning requirements
-
115 kV
O O
t t
College8 Sunset Norhv.+_�: Garden
Walnut
51_ri nri
TB D TB D
Souttvwest N n'hEa.:
Direction E'.ire,�on
Figure 4: Westside Station Rebuild Project Diagram
FRT #62: olo Transformer Replacement
The two 230/115kV, 125MVA transformers at Lolo Substation were identified for
possible overload per TPL-001-5 R2.1.5, which pertains to outages for equipment with
long lead times relative to available spares. When the project was under development,
Avista did not maintain a spare transformer of this size.
The Lolo Transformer Replacement project is the replacement of the existing 125MVA
transformers with 250MVA units as well as replacement of their respective 115kV circuit
breakers to accommodate the increased transformer capacity. The circuit switchers on
the Lolo distribution transformer and the nearby Sweetwater Substation distribution
transformer will also be replaced to meet the additional fault duty associated with the
transformer upgrade.
Additionally, the 115kV bus will be replaced due to inadequacy for existing fault duty
levels. The remaining 115kV breakers will be replaced as part of the bus rebuild.
Page 10 of 17

System Plan 202:Appendix D
Clear Water#2 Clear Water#1
Pound Lane A L Nez Pence
-------------------------------------- ------------------------------------------ ___----•
115113 kV
xfmr#3
♦ 1
I 1
/ 1
1 \
1 1
I 115 kV
\ I
\� I
—— /
\ 1
1
11 2301115 kV 230/115 kV
125 MVA 125 MVA 1
Lolo Substation xfmr#2 xfmr#1 /
/
I
I
S
230 kV Lob Nez Pence
I
/115125 kV
xfmr#1
Sweetwater Substation
Hatwai Drycreek Oxbow
Figure 5: Lolo Transformer Replacement Project Diagram
3.4. ERT #131 : Garden Springs Station
The West Plains and Sunset area (up to 245MW) is served by four 115kV transmission
lines, which may overload for multiple contingency events during summer loading.
Existing mitigation projects (Garden Springs — Sunset 115kV Transmission Line rebuild
and the Ninth and Central — Sunset 115kV Transmission Line rebuild) help reduce the
amount of overloading, but do not correct known contingency issues.
The West Plains System Reinforcement initiative includes the construction of a new
230kV transmission source into the area to mitigate reliability and operability
constraints. A new transmission line is proposed to connect the Bell — Coulee corridor to
a new Garden Springs Station. The Garden Springs Station will include two 250MVA
nominal 230/115kV transformers and intersect the Sunset— Westside and Airway
Heights — Sunset 115kV Transmission Lines.
Additional reinforcements in the area to support distribution system expansion and
interconnect new distribution stations includes a new 115kV transmission line from
Airway Heights Station to a new Melville Station which intersects the South Fairchild
115kV transmission line Tap near Hallett and White Station. New distribution stations at
Flint Road and Russel Road will increase transformation capacity and provide additional
feeders to serve the increased distribution system demands. These additional
Page 11 of 17

System Plan 202:ippendix D
reinforcements will be included in subsequent projects with the intent of providing a
comprehensive approach to meet increased customer demand in the West Plains area.
To De Gap T.:
TOGraU
Catee —
rocreTlrn — 7 XX
w.
da—
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WMI Ter•;non:
PYMa
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-- Near E"'V
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N AA
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1 .MV
Do$"115W
•Reposed 115W
-------- NemnOiYler 115W
EAS"MW
w Rop—dMOW
Ea�rgFImV a130 Av
5pp kV
Figure 6: Garden Springs Station Project Diagram
3.5 FRT #143: Waikiki Capacity Mitigation
The Waikiki Capacity Mitigation project addresses issues in the North Spokane by
installation of a new 20MVA transformer at the Indian Trail Station. This location can
accommodate the additional lineup as it was originally designed for future expansion as
shown in Figure 7. This project also proposes an upgrade to the INT12F1 voltage
regulator. Distribution buildout and load transfers are needed to distribute the additional
transformation capacity.
The project diagram provided in Figure 7 summarizes the project scope, including the
necessary modifications to the distribution system to integrate the new Indian Trail
feeders and mitigate the identified performance issues. Principal projects elements
include the construction of a 1.5-mile feeder tie between INT12F3 and WAK12F4, a 1.2-
mile feeder tie between WAK12F4 and WAK12F1, load transfers, additional feeder tie
switches, and default configuration changes.
Page 12 of 17

System Plan 202:Appendix D
hididli TiAl A�41 0 i
Snlltati�w
O A Tu A 741
-Yd
A 74{ LA741 i L Add20MVA 11V13AVTrM-brm OYI Cd LLMDOc Wd.Mll:..'
A 745 9rtt hMl No Wd 2i0 OgrrlGr� to 1133 W
yq _
2.T dMT V x—TGc&—Rc�Aior Gw a vlo tM 415A.
O ! 3-13tYtu:tc-
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i i_1licV alL:6Tq 11T12'IR:M'TC'I.
4 1
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V i Rm09GC OCYNM4 FYIL6
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' 4T—d July 27.2023
i
1
l/311 i
Figure 7: Waikiki Capacity Mitigation at Indian Trail Station
3.6. ERT #148: marker Capacity Mitigation
This project expands the distribution capacity at Greenacres Station, including the
installation of a new 30MVA 115/13kV transformer, 13kV bus tie, three 13.2kV
distribution feeders, and associated controls, communication, and facilities equipment.
No new transmission work will be required for this project.
Figure 8 provides a preliminary scoping drawing based on the original Greenacres
design and the expansion. The existing distribution lineup, 30MVA transformer, and
grounding will remain in place. The new lineup includes the second 30MVA transformer
and three additional feeders. The regulator capacity will be 438A.
Page 13 of 17

System Plan 202:Appendix D
-XIT
es
':AVR­
CZ0 CM
M
rn rn (q rn en rn
U11 II/El El LI EJ
Figure 8: Barker Capacity Mitigation at Greenacres Station
4. Project Prioritization
Avista's ERT serves to evaluate proposed solutions for recognized system deficiencies
or necessary expansion while considering alternatives, collaborative approaches, and
project prioritization. The ERT considers any transmission, distribution, or substation
project requiring a capital investment greater than $1,000,000, providing validation of
scope and concept.
Projects deemed to be prudent are prioritized and submitted to the Project Delivery
functions to guide the development of work plans, schedules, and budgets. Project
priorities are expected to remain consistent relative to the dynamic needs of the
business.
Page 14 of 17

System Plan 1
Stakdgkler
Stakeholders as needed invdvauel[
required
Preferred sdution
Solutions analyzed in detail
Need Identified considered Preferretl sdutan -Scope
-VRDM
-Schedule
Need,sdutions and
proposed project Projett as proposed meets ERT T agrees to move the project t Retire proposed
presented at ERT requirements? project delive v project for future
ry consideration
ERT prioritizes the ER7 supports projett
project and adds it to delivery as necessary to
the prioritized projett ensue a successful
list. Project delivery is Projett.This may indude
running the project ect1n ERTes thelivery1110
with theposal nts.
(Stakeholders)
Figure 9: Engineering Roundtable Process
The ERT project prioritization process evaluates a combination of Technical Importance
and Initiation Urgency perspectives. Scoring metrics consider the opportunities and
potentialimpact • the system within a1horizon. - project portfolio .
presently prioritized • scored is summarized in Figure1
Page of / lu /�STA

System Plan 2023 Appendix D
Engineering Roundtable Project Priortization
100
90 Garden Springs
Station,96,72
Bronx Station Rebuild,64,78 Waikiki Capacity
80 Mitigation,64,60
South Lewiston Station Valley Station
^1 Rebuild,64,64 Rebuild,68,56
W Huetter Station
L- 70 Expansion,68,56'
o Poleline(Prairie)Station Northeast Capacity
U Rebuild,60,56 Mitigation,72,60
U) 60 Pine Street- Carlin Bay
Rathdrum 115kV Station,76,54
Transmission Line Coeur d'Alene
Upgrade,68,38 Transmission
U50 Barker Capacity Reinforcement,72,52
Melville Station, Mitigation,48,48 North Spokane Transmission
• 32,36 Coert Feeder Metro Station Moscow Capacity Reinforcement,68,52
4exte"nsion,48,44 �„� Rebuild,68,36 Mitigation,68,42
40 Little Falls Station CUpg Upgrades,72,Stationlearwater 38
U Rebuild,28,36
Cabinet Gorge GSU Sunset Station Kettle Falls Protection
1 Protection Upgrade,24,32 Rebuild,64,26 System Upgrades,68,30
30 Kooskia Station Craig Road
Rebuild,28,28 Pleasant View Interconnection
Capacity 72,24 Saddle Mountain
IEP Transformer Mitigation,'44,30 Lyons&Standard Integration,88,24
20 Replacement,24,24 Station Expansion,
Safely Interupting Westside Station
Faults,44,24 Flint Road Rebuild,88,24
Northwest Station Station,72,24
Rebuild,28,26 16
Bunker Hill Customer
10 Daven
Chester Station P ort Station Capacity,68,24
Rebuild,28,16 Ninth&Central-Sunset 115kV Rebuild,56,14
Post Falls Station
Transmission Line Upgrade,48,14 Rebuild,68,10
0
0 20 40 60 80 100 120
Urgency Score
Figure 10: Engineering Roundtable Project Prioritization and Scoring
Page 16 of 17

System Plan I 202:Appendix D
5. Project Schedule
The Project Delivery Roundtable (PDRT) reviews the substation, distribution, and
transmission projects as prioritized by the ERT and aligns internal resources and
coordinates project scheduling within the five-year capital plan and construction
resources. The PDRT construction schedule is shown in Table 3.
Project ERT Reference Start Finish
2024
#111 Lyons &Standard Station
Lyons & Standard Capacity Increase Expansion May 2023 I April 2024
Westside Substation Rebuild - Phase 3 #56 Westside Station Rebuild October 2020 October 2024
2025
Huetter 115kV Substation— Expansion #80 Huetter Station Expansion August 2022 February 2025
Indian Trail 115kV Substation #143 Waikiki Capacity Mitigation December 2022 March 2025
Greenacres 115kV Substation #148 Barker Capacity Mitigation September 2022 April 2025
#46 Poleline (Prairie) Station
Poleline 115kV Substation Rebuild February 2023 September 2025
Cloudwalker/Dry Creek Interconnect TCS-14 May 2024 November 2025
2026
Valley Substation #43 Valley Station Rebuild April 2024 February 2026
Airway Heights to Craig Road #134 Craig Road Interconnection March 2025 April 2026
Metro 115-13kV Substation Rebuild #38 Metro Station Rebuild June 2022 August 2026
2027
#140 Bunker Hill Customer
Bunker Hill Substation Capacity December 2024 January 2027
Bluebird Substation #131 Garden Springs Station June 2024 January 2027
Bronx Substation #56 Bronx Station Rebuild September 2025 November 2027
Post Falls Substation (New) #61 Post Falls Station Rebuild January 2024 December 2027
2028
Garden Springs Substation #131 Garden Springs Station July 2023 April 2028
Metro 115-13kV Substation Rebuild #38 Metro Station Rebuild July 2020 May 2028
#151 Pleasant View Capacity
Pleasant View Substation Mitigation October 2025 June 2028
Carlin Bay Substation #12 Carlin Bay Station July 2023 September 2028
2029
Melville Switching Station #100 Melville Station August 2026 April 2029
O'Gara Substation #12 Carlin BayStation September 2022 August 2029
2030
Northwest Substation #40 Northwest Station Rebuild February 2026 March 2030
Table 3: PDRT schedule
Page 17 of 17

Appendix D
11
2023-2024 System Assessment
Local Planning Report
- . �.. ._
Beacon Station, Spokane, Washington
Electric System Planning
Avista Utilities
PO Box 3727, MSC-16
Spokane, WA 99220
[e-mail]
Distribution [e-mail]
Prepared by: System Planning
Date Description Author Review
A 6/29/2023 2023 initial draft with TPL-001-5 additions Planning Team J Gross
B 9/15/2023 2023 draft released for stakeholder review Planning Team J Gross
11/17/2023 Released Planning Team ` J Gross

System Assessment 2023-2024oPpQndix D
Beacon Station, located in East Spokane at the base of Beacon Hill and north of the Spokane
River, was originally constructed in 1950 and rebuilt in 1987. The station contains two
230/115kV autotransformers rated at 250MVA and two 30MVA distribution transformers.
Beacon serves as a principal hub of Avista's Spokane Area 230kV and 115kV transmission
systems with 230kV connections to Bell (BPA), Boulder, and Rathdrum and 115kV
connections to Bell (BPA), Francis & Cedar, Irvin, Ninth & Central, Northeast, and Ross Park
Stations. Its six distribution feeders serve approximately 8,000 residential, commercial, and
industrial customers in the area.
Several transmission reinforcement projects in the Beacon Station area are included as
planned projects in the 2023-2024 System Assessment.
Page 2 of 89

System Assessment 2023-2024�n dix D
Table of Contents
1. Executive Summary............................................................................................................ 5
2. Introduction......................................................................................................................... 6
2.1. Point of Contact .............................................................................................................. 7
3. Study Assumptions............................................................................................................. 8
3.1. Transmission System...................................................................................................... 8
3.2. Distribution System....................................................................................................... 12
4. Corrective Action Plans .................................................................................................... 15
4.1. Existing Projects ........................................................................................................... 15
4.2. New Projects................................................................................................................. 17
5. Technical Analysis............................................................................................................ 30
5.1. Transmission Steady State Near-Term Analysis (R2.1)................................................ 30
5.2. Transmission Steady State Long-Term Analysis (R2.2) ............................................... 52
5.3. Transmission Short Circuit Analysis (R2.3)................................................................... 55
5.4. Transmission Stability Near-Term Analysis (R2.4)........................................................ 57
5.5. Transmission Stability Long-Term (R2.5)...................................................................... 60
5.6. Transmission Single Point of Failure............................................................................. 60
5.7. Distribution Multi-Year Load-Flow Analysis................................................................... 65
5.8. Distribution Contingency Analysis................................................................................. 71
5.9. Distribution Auto-Transfer Analysis............................................................................... 72
5.10. Distribution Short Circuit Analysis................................................................................. 72
5.11. NERC Compliance Summary ....................................................................................... 77
6. Appendix A— System and Company Description ............................................................. 79
6.1. Overview....................................................................................................................... 79
6.2. Transmission System.................................................................................................... 79
6.3. Generation Resources.................................................................................................. 83
6.4. Distribution System....................................................................................................... 83
6.5. Customer Demand........................................................................................................ 83
7. Appendix B — Transmission Models ................................................................................. 84
7.1. Planning Case Development ........................................................................................ 84
7.2. Case Summary............................................................................................................. 86
8. Appendix C — Investment Driver Definitions ..................................................................... 87
8.1. Customer Requested.................................................................................................... 87
8.2. Customer Service Quality and Reliability...................................................................... 87
8.3. Mandatory and Compliance.......................................................................................... 87
Page 3 of 89 N=

System Assessment 2023-2024
"phandix D
8.4. Performance and Capacity ........................................................................................... 88
8.5. Asset Condition............................................................................................................. 88
8.6. Failed Plant and Operations ......................................................................................... 89
Page 4 of 89
M

System Assessment 2023-2024oRRQndix D
1 . Executive Summary
The Avista System Assessment provides two specific deliverables relating to the electric
transmission and distribution system's performance during normal operating conditions and
when impacted by defined outage conditions and contingencies:
• Documentation of technical analysis results demonstrating system performance
• Conceptual solutions to mitigate operational issues to maintain expected performance
The 2023-2024 System Assessment results are based on models reflecting current conditions
and predictive forecasts. Assumptions in the assessment reflect changes in customer loads
and system configurations representing recently constructed and expected energized system
assets. Customer loads are forecasted to increase an average of 1.16% in winter and 1.24% in
summer across the Avista service territory. These growth rates are inclusive of anticipated
future load modeling changes including forecasted electrification and localized area load
growth. Forecasted load used for the transmission system analysis includes a probable
scenario of high building and transportation electrification. Methods to implement electrification
forecasts for the distribution system are under development and were not included in the
distribution system analysis. Localized load growth in the Coeur d'Alene, Post Falls, North
Spokane, West Plains, and Lewiston areas contribute to new performance issues and
amplifies existing system constraints identified in prior assessments. Generation assumptions
have also changed regarding how Avista dispatches existing generation, partially driven by
Avista's integration into the Energy Imbalance Market in 2022. The Energy Imbalance Market
economically dispatches participating resources to balance supply and demand. Generation
dispatch impacts the expected performance of the electric system by altering the use of
existing infrastructure.
Projects not presently approved by the Avista Capital Planning Group (CPG) or new projects to
address performance issues have been identified through analysis results, internal
collaboration and outside stakeholder input using the Attachment K process. Conceptual
mitigation alternatives for new performance issues are provided and will be refined in
partnership with stakeholders. New requests to the CPG will include the following principal
recommendations:
• Transmission reinforcements in Beacon, Coeur d'Alene, Lewiston-Clarkston, North
Spokane, Palouse, and Sandpoint areas
• Rebuild the Beacon Station to address fault duty and performance issues
• Address fault interruption devices presently underrated and posing potential safety
concerns
• Increase distribution capacity in the Coeur d'Alene, Moscow, North Spokane, Post Falls,
and Spokane Valley areas
The 2023-2024 System Assessment provides the foundation for additional perspectives and
conversations regarding the future of Avista's electric system. The System Planning Team is
appreciative of feedback and additional insights regarding the content of this report and will
incorporate that feedback into comprehensive project solutions for a robust future electric
system.
Page 5 of 89

System Assessment 2023-2024owaiindix D
2. Introduction
The System Assessment document includes distribution and transmission contributions. For
each, assumptions, corrective action plans, and technical analyses are created and produce
current and forecasted system needs. Combined system needs for both distribution and
transmission produce a holistic system view and provide transparency of contributions and
effects of one focus area to another. The System Assessment document also provides a single
point of reference for outside groups requiring system existing and forecasted information.
The 2023-2024 System Assessment (Local Planning Report) is a deliverable from Phase 2 of
a two-year process as defined in Avista's Open Access Transmission Tariff(OATT)
Attachment K. The System Assessment identifies the Transmission System facility additions
required to reliably interconnect forecasted generation resources, serve the forecasted loads of
Avista's Network Customers and Native Load Customers, and meet all other Transmission
Service and non-GATT transmission service requirements, including rollover rights, over a 10-
year planning horizon. The Planning Assessment process is open to all Interested
Stakeholders, including, but not limited to, Transmission Customers, Interconnection
Customers, and state authorities. The Western Electric Coordinating Council (WECC)
facilitates interconnection wide planning and development of wide-area planning proposals.
The two-year planning process desired timeline is illustrated in Figure 1. The completion of
Phase 2 includes providing the documented results of performing necessary technical studies.
The state of the existing and future system is provided. Where the technical studies identified
performance issues, conceptual projects have been proposed.
PLANNING ASSESSMENT
TIMELINE
PROJECT START REVIEW OF
SUBMISSION OF STUDY LOCAL
D TA RESULTS/DRAFT TRANSMISSION
STUDY TRANSMISSION PLAN L PDATE
PLANS MEETING
DEVELOPMENT
MEETING
40
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
POST MODELS POST AVISTA
POST J VISTA
SYSTEM PLAN
POST P NING SYSTEM PLAN
REVISION
ASSESSMENT
FINALIZ STUDY
PLAN
Year 1 Year 2
Phase 1 Phase 2 Phase 3 Phase 4
PofUd 1, PBl'wd 2 Ponotl 3
Figure 1: Planning Assessment Timeline
Phase 3 of the process will follow the completion of the System Assessment. Phase 3 includes
providing the Avista System Plan report to stakeholders. The Avista System Plan will include
documentation of the electrical infrastructure plan with preferred solution options. The resulting
project list will include additional information regarding projects and system modifications
developed through means other than the technical studies'.
Such other means may include,for example, generation interconnection or transmission service request study processes
under the GATT, or joint study team processes under NorthernGrid.
Page 6 of 89

System Assessment 2023-2024oRpQndix D
2.1 . Point of Contact
A Point of Contact for questions regarding this System Assessment and the projects described
within it has been designated. Please contact the party named below with any questions:
Electric System Planning
Avista Utilities
PO Box 3727, MSC-16
Spokane, WA 99220
[e-mail]
[e-mail]
Page 7 of 89

System Assessment 2023-2024,,I@pQ,dix D
3. Study Assumptions
The technical studies performed as part of this System Assessment were conducted according
to the 2023-2024 Avista System Assessment Study Plan. The following sections provide a
summary of key assumptions regarding the representation of the electrical system and
methodologies of analysis.
3.1 . Transmission System
3.1 .1 .System Conditions
A set of transmission system models were developed to represent specific operating
scenarios. The scenarios were selected to capture reasonably expected conditions which may
stress the performance of the transmission system. Figure 2 and Figure 3 provide a
comparison of the Summer and Winter models to historical Balancing Authority Area (BAA)
load and BAA interchange excluding dynamic imports. The model scenarios represented by
green markers represent a 1 in 10 probability of occurrence.
Summer Load vs. Interchange
2,0011
•-1,soo •
3
e -1,000
•2021
l s tt vrt; .
`o r .+ +.a�iYrw�1•+ * ••^.s •2022
-500 Model
m •� , •; '%•1i1 � �•;! •
e 1x i s T�
c
w 0
500
800 1000 12CAJ 1400 1,,iD lHDil 2!Ul 2200 2400 2600 2800
Balancing Authority Area Load(MW)
Figure 2: Historical Avista BAA Load Versus Interchange During Summer Months
Winter Load vs. Interchange
2r;rx1
L -1500 yam+• -'�u.�. ^ !•.:�•.••.•�•�•'�.Nt•,. ••
m ; -1000 .+.•• •�
o
.o J ,•• y 2 + '1• •• •2021-2022
r ;00
mo •2022-2023
c m
0 •Model
A
m
500
8IX1 1000 1200 1400 1+600 tr+.ii` 2000 2200 2400 2600 2800
Balancing Authority Area Load(MW)
Figure 3: Historical Avista BAA Load Versus Interchange During Winter Months
A detailed summary of specific flows and loading levels for the Planning Cases used in the
2023-2024 System Planning Assessment is provided in Appendix 7.2 Case Summary.
Page 8 of 89

System Assessment 2023-2024
"ppandix D
3.1 .2.Projects Modeled
The transmission system models include representation of projects expected to be constructed
within the applicable planning horizon. The models are analyzed with and without these
projects to demonstrate the impact of the projects on the performance of the system. Table 1
provides the list of projects included in the models.
Included in Table 1 are designations for projects that are included in the base, the five-year,
and the 10-year planning models. The Five-Year Planned Projects are significant because they
represent the expected system configuration and performance in the planning horizon. It
should be noted the entire scope of each project is considered complete and operational when
included in the designated planning model.
IncludedProject . .
ScopeERT# Name Driver
Construct new distribution station to include
single 20MVA transformer and two feeders.
Transmission integration to include constructing
Carlin Bay Performance a new radial transmission line from O'Gara
12 Station and Station to Carlin Bay.The second phase of the Budgeted X X
Capacity project includes rebuilding the existing O'Gara
Station to a switching station.New microwave
communication paths will be established to
O'Gara Station.
Sunset Station Mandatory Rebuild the existing Sunset Station as breaker
26 Rebuild and and a half configuration. Complete X X X
Com liance
Rebuild existing station at new location. 115kV
Metro Station Asset bus to be a 6-position ring:2—30MVA xfer's,2
38 Rebuild Condition —115kV UG lines from PST,2—115kV OH Construction X X
lines;switchgear on the 13kV side, both
Network and Distribution feeders
New distribution station located west of
Flint Road Performance Spokane along the Airway Heights-Sunset
53 Station and 115kV Transmission Line.Two new 30MVA Complete X X X
Capacity transformers with four distribution feeders will
be the initial configuration.
Replace the existing Westside 230/115kV
Transformer 2 and construct necessary bus
Performance work and breaker positions. Reconstruct 230
58 Westside and and 115kV buses to double bus double breaker Construction X X X
Station Rebuild Capacity 3000/2000 Amp standard.
Phase 4: Complete bus work to double bus,
double breaker on both the 230kV and 115kV
buses
Ninth&Central Performance Replace the 795 AAC and ACSR conductor on
Sunset 115kV the Ninth&Central—Sunset 115kV
60 Transmission and Transmission Line with 795 ACSS with E3X Construction X X
Line Upgrade Capacity coating to match the rest of the line.
Replace Lolo 230/115kV Transformer 1 with
250MVA rated transformer.
Lolo Performance Replace Lolo 230/115kV Transformer 2 with
62 Transformer and 250MVA rated transformer. Construction X X
Replacement Capacity 115kV circuit breakers, bus work and other
capacity-limiting elements will be replaced.
Circuit switchers at Clearwater, Lolo,and
Sweetwater stations will be replaced.
2 Driver refers to the classification for investment as defined by Avista and referenced in Appendix C—Investment Driver
Definitions.
Page 9 of 89

System Assessment 2023-2024�n dix D
IncludedProject in Model
FERT 41 Name Driver'
. .
Construct a 3-position 230kV DBDB
arrangement with space for two future positions
at the line crossing of the Walla Walla—
Wanapum 230kV and Benton—Othello 115kV
Lines
Construct a 4-position 115kV breaker and a
half arrangement with space for four future
positions
Install 1-230/115kV transformer rated at
250MVA.
Reconstruct Othello SS—Warden#1 115kV
Saddle Performance Transmission Line to minimum 205MVA
75 Mountain and including upgrades to terminal equipment at Complete X X X
Integration Capacity both stations.
Reconstruct Othello SS—Warden#2 115kV
Transmission Line to minimum 205MVA
including upgrades to terminal equipment at all
stations.
Construct 11 miles of 115kV line with a
minimum summer rating of 205MVA from
Saddle Mountain Station to the new Othello
City station with a N/O tap to existing S.Othello
Station.
Reconstruct Othello Station to a 3-position
breaker and a half with 2—30MVA
transformers at new property.
Upgrade existing protection schemes on the
Kettle Falls Mandatory Addy—Kettle Falls and Colville—Kettle Falls
96 Protection and 115kV Transmission Lines. New relays at Construction X X X
System Compliance Kettle Falls Station and a new communication
Upgrades path from Kettle Falls to Mount Monumental are
required.
Scope not complete.
New switching station near existing tap to Four
Lakes Station off the South Fairchild Tap
Performance 115kV Transmission Line.Construct new
100 Melville Station and transmission line from Airway Heights to Budgeted X
Capacity Melville including passing through Russel Road
and Craig Road distribution stations.Requires
new transmission line terminal at existing
Airway Heights Station.
Construct new 115kV portion of Garden
Springs Station at the existing Garden Springs
switching location.New station will terminate
Airway Heights—Sunset and Sunset—
Westside 115kV Transmission Lines including
Garden Performance the South Fairchild Tap.
131 Springs Station and Construct new 230kV portion of Garden Budgeted X
Capacity Springs Station including two 250MVA nominal
230/115kV transformers.Construct new 230kV
Transmission Line from Garden Springs to a
new switching station,Bluebird,at an
interconnection point on the BPA Bell—Coulee
#5 230kV Transmission Line.
Project updates the existing Boulder-lvin#1
Boulder-Irvin 115kV Transmission Line from Boulder to SIP.
#1 115kV Performance Remaining replacements are existing 556AAC
N/A Transmission and on Barker Road and approximately a%mile Construction X X X
Line Upgrade Capacity section just east of SIP,currently delayed by
easement dispute.Replacements will be made
with 795 ACSS. I _
Table 1: Projects Represented in Transmission System Models
Page 10 of 89

System Assessment 2023-2024oRRQndix D
3.1 .3.Performance Criteria
Avista's transmission system performance criteria are defined in TP-SPP-01 — Transmission
System Performance. Specific criteria are provided for acceptable steady state voltage limits,
post-contingency voltage deviations, transient voltage response, thermal performance, load
loss limits and allowable operating plans for the system. Criteria for identifying system
instability, weak systems, and acceptable short circuit equipment loading is also provided.
3.1 .4.Studies Performed
Technical studies are performed as part of the System Assessment. The methodologies for
each study are documented in TP-SPP-01 — Transmission System Performance. The defined
set of technical studies include:
• Steady State Contingency Analysis
• Spare Equipment Analysis
• Short Circuit Analysis
• Stability Contingency Analysis
• Voltage Stability Analysis
• Protection System Failure Analysis
Page 11 of 89

System Assessment 2023-2024�n dix D
3.2. Distribution System
3.2.1 .Svstem Conditions and Modelina Assumptions
The power system model used to analyze the distribution system was based on a snapshot of
the system as it existed in April 2023, with all lines and equipment in service. The loads
characterized in the model used the peak load and load curve SCADA data from 2020, 2021,
2022, and 2023. Collected data for August 15, 2023, was used directly in the model to
represent the Heavy Summer scenario. The Heavy Winter scenario was mostly represented by
data from December 22, 2022. A load forecast was developed using a multivariate regression
analysis with each feeder assumed to have a linearized growth rate over the 10-year planning
horizon. The highest growth rates were observed in the Coeur d'Alene, Rathdrum, and Post
Falls areas.
Figure 4 shows an example of the multiple regression used to project a station's rate of load
growth. The plot represents College & Walnut Transformers 1 and 2 in the orange data, the
10-year forecast in black, and the associated trend in red. Forecasted load is primarily based
on 40-year average heating and cooling degree day data.
ate:
nom
i
V SM
0
ili] d)u ... :i6 d)i7 b dli9 21U ]O2 .._ :.J d'W Ai3 1G8 dli) d1L XRV ]O10 301i d)ll dN
Figure 4: College & Walnut-Example Load Regression Analysis Forecast
Specific seasonal and loading scenarios are represented within the models and are used to
evaluate if the system will meet the performance criteria defined in DP-SPP-02— Distribution
System Performance V5. When analysis indicates an inability of the system to meet the
performance criteria for the scenarios listed in Table 2, projects will be developed addressing
how the performance criteria will be met. Additional sensitivity scenarios may be studied in
addition to those listed in Table 2.
Page 12 of 89
�r

System Assessment 2023-2024
"ppandix D
Ambient
Temperature
Scenario Description
Day-time peak load occurring between June
Heavy and August with loads representing a 1 in 10
Summer probability 40°C (104°F)
Day-time peak load occurring between
Heavy December and March_with loads representing
Winter a 1 in 10 probability -28.9°C (-20°F)
Heavy Same scenario as Heavy Summer with loads
Summer representing the highest summer
Sensitivity temperature on record 42.8°C 109°F)J
Table 2: Distribution System Scenarios
Historical weather data was reviewed to select the scenarios listed in Table 2. DP-SPP-02—
Distribution System Performance V5 outlines the methodology and data for Table 2.
3.2.2.Projects Modeled
The distribution system models include representation of projects expected to be constructed
within the applicable planning horizon. The models are analyzed with and without these
projects to demonstrate the impact of the projects on the performance of the system. Table 3
provides the list of projects which will be included in the models when individual project
analysis is performed.
ScopeERT# Project Name Driver
Construct new distribution station to include single
20MVA transformer and two feeders.Transmission
integration to include constructing a new radial
12 Carlin Bay Station Performance transmission line from O'Gara Station to Carlin Bay. Budgeted
and Capacity The second phase of the project includes rebuilding the
existing O'Gara Station to a switching station. New
microwave communication paths will be established to
O'Gara Station.
I Mandatory Rebuild the existing Sunset Station as breaker and a
26 Sunset Station Rebuild and Complete
Compliance half configuration.
Asset Rebuild existing distribution station at nearby greenfield
32 Davenport Station Rebuild Condition site. Initial construction will include single 20MVA Construction
transformer with three feeders.
Rebuild existing station at new location. 115kV bus to
38 Metro Station Rebuild Asset be a 6-position ring:2—30MVA xfers',2—115kV UG Construction
Condition lines from PST,2—115kV OH lines;switchgear on the
13kV side, both Network and Distribution feeders
Scope not complete.
Performance Construct new distribution station to replace Avista
46 Poleline(Prairie)Station Rebuild and Capacity facilities at existing Prairie Station.New station to Budgeted
include two 30MVA transformers,four feeders,and
loo ed-throu h transmission without circuit breakers.
New distribution station located west of Spokane along
53 Flint Road Station Performance the Airway Heights-Sunset 115kV Transmission Line. Complete
and Capacity Two new 30MVA transformers with four distribution
feeders will be the initial configuration.
Construct a 3-position 230kV DBDB arrangement with
space for two future positions at the line crossing of the
Walla Walla—Wanapum 230kV and Benton—Othello
115kV Lines
Performance Construct a 4-position 115kV breaker and a half
75 Saddle Mountain Integration and Capacity arrangement with space for four future positions Complete
Install 1-230/115kV transformer rated at 250MVA.
Reconstruct Othello SS—Warden#1 115kV
Transmission Line to minimum 205MVA including
upgrades to terminal equipment at both stations.
Reconstruct Othello SS—Warden#2 115kV
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^ppandix D
Project • • Status
-
Transmission Line to minimum 205MVA including
upgrades to terminal equipment at all stations.
Construct 11 miles of 115kV line with a minimum
summer rating of 205MVA from Saddle Mountain
Station to the new Othello City station with a N/O tap to
existing S.Othello Station.
Reconstruct Othello Station to a 3-position breaker and
a half with 2—30MVA transformers at new property.
Add new 30MVA transformer and two distribution
feeders to the existing Huetter Station.Scope includes
80 Huetter Station Expansion Performance a new panel house and rerouting the transmission line Construction
and Capacity to the east side of the station. 13kV bus tie switch and
a 115kV bus tie switch located on transmission
structures outside the station will be added.
111 Lyons&Standard Station Customer Add new feeder to existing Lyons&Standard Station. Construction
Expansion Requested
Customer Install new 20MVA transformer to replace existing
140 Bunker Hill Customer Capacity Requested transformer and construct new dedicated customer Budgeted
distribution feeder.
143 Waikiki Capacity Mitigation Performance Add new 20MVA transformer and two feeders to Budgeted
and Capacity existing Indian Trail Station.
148 Barker Capacity Mitigation Performance Add new 30MVA transformer and three feeders to Budgeted
and Capacity existing Greenacres Station.
Table 3: Projects Represented in Distribution System Models
3.2.3.Performance Criteria
The performance criteria used in evaluating the performance of the distribution system is
outlined in DP-SPP-02— Distribution System Performance V5 Table 1.
3.2.4.Studies Performed
Technical studies are performed as part of the System Assessment. The methodologies for
each study are documented in DP-SPP-02— Distribution System Performance. The defined
set of technical studies include:
• Load Forecast Development
• Multi-Year Load-Flow Analysis
• Contingency Analysis (under development)
• Auto-Transfer Analysis
• Short Circuit Analysis (under development)
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System Assessment 2023-2024opi@Qndix D
4. Corrective Action Plans
When technical studies demonstrate the system's inability to meet performance requirements,
Corrective Action Plans are developed to address how the performance requirements will be
satisfied. Revisions to Corrective Action Plans are allowed in subsequent System
Assessments but the planned system must continue to meet performance requirements.
Corrective Action Plans can be developed to meet the performance requirements for one or
more sensitivity cases analyzed.
Corrective Action Plans developed to address performance issues identified on the
transmission system must be implemented in accordance with TPL-001-53 R2.7. If situations
arise outside Avista's control that prevent the implementation of a Corrective Action Plan within
the required timeframe, Avista is then permitted to utilize Non-Consequential Load Loss and
curtailment of Firm Transmission Service to correct the situation while providing documentation
of the actions and resolution. Avista shall document the problematic performance issue,
alternatives evaluated, and the use of Non-Consequential Load Loss or curtailment of Firm
Transmission Service. (TPL-001-5, R2.7.3)
In some instances, performance requirements can be met using Operating Procedures making
Corrective Action Plans unnecessary. Operating Procedures may also introduce undesired
risks to the system. Projects are developed and recommended to address the instances where
expected system performance using Operating Procedures is not considered acceptable.
Corrective Action Plans for the transmission and distribution system are provided in the
following sections.
4.1 . Existing Projects
Included in Table 4 below are projects identified in prior years' technical studies that have been
incorporated into Avista's Engineer Roundtable prioritized project list.
ProjectTPL
Driver Scope
Construct new distribution station to include
single 20MVA transformer and two feeders.
Transmission integration to include constructing a
Performance new radial transmission line from O'Gara Station
12 Carlin Bay Station and to Carlin Bay.The second phase of the project Budgeted
Capacity includes rebuilding the existing O'Gara Station to
a switching station. New microwave
communication paths will be established to
O'Gara Station.
Scope not complete.
Performance Construct new distribution station to replace
46 Poleline(Prairie)Station and Avista facilities at existing Prairie Station. New Budgeted
Rebuild station to include two 30MVA transformers,four
Capacity feeders, and looped-through transmission without
circuit breakers.
Performance Scope not complete.
47 Stateline Station and New distribution station located between Pullman Budgeted
Capacity and Moscow.
Performance Scope not complete.
56 Bronx Station Rebuild and Reconstruct existing Bronx Station to include Budgeted
Capacity I distribution facilities.
3 NERC Transmission Planning standard TPL-001-5, https://nerc.com/pa/Stand/Reliability%20Standards/TPL-001-5.pdf.
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^phandix D
Scope# Project Name Driver
Replace the existing Westside 230/115kV
Transformer 2 and construct necessary bus work
Performance and breaker positions. Reconstruct 230 and
58 Westside Station Rebuild and 115kV buses to double bus double breaker Construction Yes
Capacity 3000/2000 Amp standard.
Phase 4: Complete bus work to double bus,
double breaker on both the 230kV and 115kV
buses
Ninth &Central-Sunset Performance Replace the 795 AAC and ACSR conductor on
F6O115kV Transmission Line and Transmission Line with 795 ACSS with E3X
Upgrade Capacity the Ninth &Central—Sunset 115kV Construction
coating to match the rest of the line.
Replace Lolo 230/115kV Transformer 1 with
250MVA rated transformer.
Performance Replace Lolo 230/115kV Transformer 2 with
62 Lolo Transformer and 250MVA rated transformer. Construction
Replacement Capacity 115kV circuit breakers, bus work and other
capacity-limiting elements will be replaced.
Circuit switchers at Clearwater, Lolo, and
Sweetwater stations will be replaced.
Add new 30MVA transformer and two distribution
feeders to the existing Huetter Station. Scope
Huetter Station Performance includes a new panel house and rerouting the
80 Expansion and transmission line to the east side of the station. Construction
Capacity 13kV bus tie switch and a 115kV bus tie switch
located on transmission structures outside the
station will be added.
Cabinet Gorge GSU Performance
82 Protection Upgrade and Install circuit breakers on high side of GSU. Budgeted
Capacity
Upgrade existing protection schemes on the
Kettle Falls Protection Mandatory Addy—Kettle Falls and Colville—Kettle Falls
96 System Upgrades and 115kV Transmission Lines. New relays at Kettle Construction Yes
Compliance Falls Station and a new communication path from
Kettle Falls to Mount Monumental are required.
Scope not complete.
New switching station near existing tap to Four
Performance Lakes Station off the South Fairchild Tap 115kV
100 Melville Station and Transmission Line. Construct new transmission Budgeted
Capacity line from Airway Heights to Melville including
passing through Russel Road and Craig Road
distribution stations. Requires new transmission
line terminal at existing Airway Heights Station.
Construct new 115kV portion of Garden Springs
Station at the existing Garden Springs switching
location. New station will terminate Airway
Heights—Sunset and Sunset—Westside 115kV
Transmission Lines including the South Fairchild
Performance Tap.
131 Garden Springs Station and Construct new 230kV portion of Garden Springs Budgeted Yes
Capacity Station including two 250MVA nominal
230/115kV transformers. Construct new 230kV
transmission line from Garden Springs to a new
switching station, Bluebird, at an interconnection
point on the BPA Bell—Coulee#5 230kV
Transmission Line.
Performance
Waikiki Capacity Add new 20MVA transformer and two feeders to
F14 and Mitigation Capacity existing Indian Trail Station. Budgeted
Page 16 of 89

System Assessment 2023-2024�n dix D
ScopeTPIL
# Project Name Driver ERT
Barker Capacity d Performance Add new 30MVA transformer and three feeders
148 an Budgeted
Mitigation Ca to existing Greenacres Station.
Pleasant View Capacity Performance Scope not complete.
151 Mitigation and Add new 30MVA transformer and two feeders to Budgeted
Capacity existing station.
Replace South Othello A57 circuit switcher with
1220kA or greater rated equipment.
Replace Barker Road A316 circuit switcher with
40kA or greater rated equipment.
Replace Francis&Cedar A676 and A677 circuit
switchers with 40kA or greater rated. equipment.
Performance Replace Lakeview R330 circuit switcher with
156 Safely Interrupting Faults and 20kA or greater rated equipment. Budgeted
Capacity Replace Garfield EG-1 transformer fuse with
10kA or greater rated fuse.
Replace Leon Junction SMD-213 transformer fuse
with 15kA or greater rated fuse.
Replace Long Lake SMD-213 transformer fuse
with 15kA or greater rated fuse.
Replace North Moscow SMD-213 transformer fuse
with 15kA or greater rated fuse.
Table 4: Existing Projects Included in Avista's Five-Year Capital Budget Plan
4.2. New Projects
Corrective Action Plans identified by technical analysis completed as part of the 2023-2024
System Assessment are provided in this section. The Corrective Action Plans provided were
not identified during previous years' technical analyses or they were not included in Avista's
prioritized project list. The project scope outlined for each Corrective Action Plan is preliminary
and will require further study including the evaluation of alternatives (traditional and non-
traditional) and coordination with stakeholders to confirm the appropriate scope is executed.
Each Corrective Action Plan will be reviewed in subsequent System Assessments for
continued validity and implementation status of identified System Facilities and Operating
Procedures. (TPL-001-5, R2.7.4)
The new required projects and associated performance issues, in addition to the planned
projects included in the study assumptions, are summarized in Table 5 below.
DesiredCorrective Action Plan System Impact
ScopeIn- Worst
Planning service Performance Impacted Impact
Issue Project Name
Coeur d'Alene New 230kV P2:A-624 breaker OTI-PF and
1 Transmission source station 5-10 years failure at PF-RAM Existing Yes
Reinforcement between Boulder Rathdrum overload
and Rathdrum
Lewiston- New 230kV Yes,
2 Clarkston transmission line 5-10 years P6: HTWA-LOL+ NLW-CLW Existing possible
Transmission between Hatwai DCR-PDL overload Ops
Reinforcement and Lolo stations Plan
Il I
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System Assessment 2023-2024
^phandix D
Corrective . Impact
Desired •
Planning service Performance Impacted Impact
ScopeIssue Project Name
Upgrade 3/0
copper section of
Beacon—Francis
&Cedar,
reconfigure
existing lines
between Bell and
Waikiki including BEA-F&C
North Spokane new P6: F&C-ROS+ overload and
3 Transmission interconnection 4-7 years NW-WES and P6 BEA-BELL Existing Yes
Reinforcement at Bell,Waikiki Bell#6 Outages
Station issues
modifications,
two new lines
between Indian
Trail and Waikiki,
and loop Boulder
—Irvin line into
Trentwood
New 115kV
transmission into
Sandpoint P6: LIBY
4 Transmission the Sandpoint area or upgrades 5-10 years transformer+ CAB overload ALFL-SDCK Existing Yes
Reinforcement of existing transformer
facilities
Rebuild Beacon BEA 115kV
with higher Close in fault on circuit
Beacon BEA 115/13kV breakers
5 Transmission capacity 5-10 years transformer and and 5+years Yes
Reinforcement equipment and Beacon breaker Spokane
redundant bus failures 115kV
design system
Palouse SHN transformer Yes,
6 Transmission Under 5-10 years outage with M23- M23-M15 Existing possible
Reinforcement development TVW outage Ops
Plan
Existing project
scope needs to
Safely be expanded to Faults on
7 Interrupting include 2-5 years distribution AIR, PST Existing No
Faults replacement of transformers
Airway Heights
and Post Street
circuit switchers
Expand RAS for BLD-RAT,
8 West of specific 2-5 years P7 West of OTI-PF, PF- Existing No
Lancaster scenarios Lancaster RAM
I 9 Airway
eights FL Transfer
load to 1 year Peak
capa summer AXR12 21, I 2026 No
Capacity I
Glenrose New East Central Peak summer GLN12F1,
10 Capacity Station 5 years capacity GLN12F2, Existing No
Xfmr 1
Rebuild SLW,
Lewiston expand TEN, and Peak summer TEN, LOL,
11 Capacity new LOID and 5-10 years capacity NEW, SLW Existing No
WHT Stations
Page 18 of 89

System Assessment 2023-2024
^phandix D
Corrective . Impact
Desired •
Planning service Performance impacted Impact
ScopeIssue Project Name
Liberty Lake Peak summer LIB12F1,
12 Capacity TBD 5 years capacity LIB12F3, Existing No
Xfmr 2
Moscow Peak summer
Load transfers, M15512,
13 Capacity new SEL Station, 5-10 years capacity M15514, Existing No
rebuild M15 Xfmr 1
INT expansion, BEA, COB,
North Spokane NE expansion, Peak summer F&C, INT,
14 Distribution feeder re- 5-10 years capacity L&S, MEA, Existing No
Reinforcement configuration, NE, WAK
MEA expansion
Add one
Rathdrum additional feeder
Peak summer
15 Capacity to off load 5-10 years capacity RAT231 2027 No
Mitigation RAT231 and
RAT233
I 16 Orin Capacity TBD TBD Peak winter OR112F3, Existing No I
capacity Xfmr 1
17 Wilbur Upgrade WIL 2-3 years Peak winter Xfmr 1 Existing No
Capacity transformer capacity
18 Valley Upgrade VAL TBD Peak winter Xfmr 1 Existing No
Capacity transformer capacity
Table 5: Corrective Action Plans Identified in 2023-2024 System Assessment
4.2.1 .Transmission
4.2.1 .1 . Coeur d'Alene Transmission Reinforcement
Consistent load growth in the Coeur d'Alene region continues to outpace transmission system
reinforcements. The area summer peak load has increased from 158MW in 2010 to 223MW in
2020, an annual rate of 3.5%. This growing load results in ongoing near-term thermal issues
for the loss of the Rathdrum East 115kV bus (P2.2 and P2.3) and the loss of the 115kV source
with a Rathdrum 115kV bus tie breaker failure (P2.4), both of which require Corrective Action
Plans for mitigation. Additionally, numerous N-1-1 outage issues (P6, A6, and A7) continue to
limit planned outages in the Coeur d'Alene region to shoulder months. Forced outage
combinations may result in load shedding during heavy load periods.
The area load is served by two 230/115kV transformers at Rathdrum Station and four 115kV
transmission lines from neighboring areas. Some of the identified contingency issues were
temporarily corrected in 2014 with a 115kV line reconfiguration at the "Magic Corner", but at
the expense of additional load loss exposure resulting from autotransformer outages at
Rathdrum. The 115kV system was put back into normal configuration after the completion of
the Coeur d'Alene — Pine Creek 115kV Transmission Line Rebuild Project in 2020, which
added a new 115kV source from Pine Creek Station.
Study results show that adding a station in Coeur d'Alene area is the most cost effective and
flexible system reinforcement, minimizing the need for multiple 115kV line reconductors and
adds resiliency to the transmission system. Preliminary scope of the Coeur d'Alene Area
Transmission Reinforcement project is shown in Figure 5.
Page 19 of 89

xx System Assessment 2023-2024An dix D
230kV to
Lancaster? t
230kV to X X X X X I I X X X X X X
Beacon
South 230kV DCT line not used
until Data Center expansion O
230kV to O 230kV to
Boulder Rathdrum
Post Falls Ind
-------- -- ------------
23o kv
Coeur d'Alene Ana Svslam Reinforcements
New•Post Falls Intlustriat substation incorporating(4)230kV line positions in a breaker and a
O half configuration with space for(2)spare 230W bays•(2)M115kV 250MVA
outorransfwmers,(8)115kV line positions in breaker and a halt configuration with space for(1) I
spare 115kV bay space for(21 steps of reactive support and space for 12)distribution line-ups
O Build a new 4.7-mik 230kV single circuit transmission tine utilizing the existing Lancaster Rathdrum
I I 115 kV t0
A118WA155eposdienasa�nr�af«menawsulixi I I
O
via Meyer
Build a rwwv S.2-rmW 2301V wngb cncuM1 bansrmssion line utilizing the cn sting Raualrum I 1 R408IR508 p.i as a source for the new substabon - ' 115kV to
O I Rathdrum
OBuild a new,0 8-mile 115kV doubt-cb Ioam curt Uansmission line far the p- of the Dalton
4 Rathdrum 115kV transmission line into the new substation r 2 ' Via Hayden
OBuild a new,1.3-mile 115kV double circuit transmission line for the loop-in of the Post Fells- I �q3g �gg
Ramsey 115kV transmission line into the new substaton
© Build(2)new 0.1-mile 115kV single circu4 trans min ion Ilnes for the loc in of the Ramsey- I I O
Rathdrum 115kV transmission line into the new substation 115kV I 6
I
115kV to
Operate 11 skV ties to V to Dalton
Spokane Valley
Normally Open Ramsey
via Huetter
115kV to Post --"—""—"—""—"'—"'—'"—""—'"- 115kV to
Falls Ramsey
Figure 5: Coeur d'Alene Transmission Reinforcement
The requirement for the Coeur d'Alene Transmission Area Reinforcement project was
identified through the transmission steady state near-term and long-term contingency analysis.
This specific project and 230kV transmission expansion scope will be provided in the
subsequent Corrective Action Plan and study documents.
4.2.1 .2. Lewiston-Clarkston Transmission Reinforcement
Issues in the Lewiston-Clarkston Area have been understood since the West of Hatwai
projects were completed in 2005. To manage planned outages, the following automatic actions
have been incorporated into current Operational Procedures:
• The Lolo — Oxbow Back Tripping Remedial Action Scheme (RAS) is in place for
planned 11 RV and 230kV line outages. The contingency issues are more pronounced
during late spring and summer seasons due to heavy system loading and high ID-NW
transfers south into Idaho Power's system.
• A Thermal Trip Scheme has been established to trip the Clearwater— North Lewiston
115kV Transmission Line when overloaded based on existing transmission line load
and ambient temperature data within a prescribed time limit.
This area has several N-1-1 issues that require the above automatic actions in addition to
schedule reductions and requisite sectionalizing of the 115kV system for more problematic
outages.
The Clearwater— North Lewiston 115kV Transmission Line, which currently loads above 90%
under N-1 conditions, is the weak link in this area. This condition limits planned outages in the
Page 20 of 89

System Assessment 2023-2024oppendix o
area to shoulder months. The most extreme contingency is an outage of the Hatwai — Lolo
230kV Transmission Line for which the RAS is implemented, and multiple 115kV transmission
lines must be sectionalized to avoid overloads for the next contingency.
Evaluation results show a preliminary concept of a second Hatwai — Lolo 230kV Transmission
Line will resolve the Clearwater - North Lewiston adverse results shown in the steady state
results described in Section 5 Technical Analysis below.
4.2.1 .3. North SpoKane Transmission Reinforcement
Load growth in the North Spokane area has contributed to inadequate transmission system
performance. Near-term P6 contingencies result in thermal issues for both Beacon — Francis &
Cedar 115kV Transmission Line and Beacon — Bell 115kV interconnections.
The Francis & Cedar Station is served by three 115kV transmission lines. A category P6
outage involving the Francis & Cedar— Ross Park and Northwest—Westside 115kV
Transmission Lines leave only the Beacon — Francis & Cedar 115kV Transmission Line
serving the Northwest and Francis & Cedar Stations. The Beacon — Francis & Cedar 115kV
Transmission Line is constrained by a section of seven strand 3/0 copper conductor between
the Bell and Waikiki Taps. Upgrading the conductor to present construction standards will
mitigate the observed performance issue. This outage combination under forced conditions
may result in load shedding during Heavy Summer scenarios.
There are four 115kV facilities between the Beacon and Bell stations that result in near-term
thermal issues under P6 contingencies and long-term single contingency thermal issue with
loss of the Bell 230/115kV Transformer 6. Near-term thermal issues result when two of the
following facilities are out of service.
• Bell 230/115kV Transformer 6
• Beacon — Bell #1 115kV Transmission Line
• Beacon — Northeast 115kV Transmission Line
• Bell — Northeast 115kV Transmission Line
A transformer outage followed by an outage of one of three interconnecting 115kV
transmission lines (Beacon — Bell, Beacon — Northeast, or Bell — Northeast) results in system
overloads on the remaining 115kV transmission line between Beacon and Bell stations.
Preliminary scope to address the Beacon — Francis & Cedar thermal concern and some of the
Beacon — Bell interconnection concerns are shown in Figure 6.
Page 21 of 89

System Assessment 2023-2024
"phandix D
116kvaneey`I 11skv Bell Substation
NorM S.oh.n.R.InMedm.nl. T
ONnw Yi nkwi 115kV SIaMn wth IM1a 115kV
Nxe Ixnaum.n,xl o,wr lulu..I I5%v hn.
Ix:!al:on I I
OI 1—13 akV T—fonn.f
2 12ecanlq RoaCM-k.anas eM Ceear
11:wcV I.,eu.e and Wakk,lep ra .,h%. 1 M.ro to Wilbur
Iwi FM:. r.n,rn
1
eM C Mm 15k\'.wr n:wf 116W
ltennw, Wnkkl tfSkV l,nr I
Naw 116kV b..,ko.pos,l:on nl f1o11RP"I n,wl 27akV
nlarcl.ange melemq
I
®Roaw 1,,BM Wn,ktlo sa:IwnM n.w Roll
h fanc.s end CeOar 11SkV Ilna
OR.rxxwkrin,W—,T,to W--l—,nl I
Indian Trail Substation rew Re.a,-W.ww 116kv I'm
©It nN....sing Nnw.M,w Wah., I O
11SkV In.nto mw Wa,ww 11 SkV Station
I I I
�11tL13w� HSn3wl o61m I-_--_ — -----J
II —--116kv cp Tnm.1
1 I © 115101 W Tnnl M3
115kV to
Nine Mile
203-
115kv to 1
Westslde I I � T Nerou..IcT I
1 I I I
1 I I
I - 11 3w 115113� I I I
I
Waikiki O I 116n3w 116113w
Substation
Francis 3 Cedar 1 --—- ---
1 I
Substation L_____ TT
—__—__—_I
r-- --- -- --—-- Northeast Substation I
I I
I I I � I
In9u w L.vl I 1
1 1
Lyons&Standard
-- -- ---- ----� Substation I
115kV to —�- Ross Park I I
Northwest 1 Substation
I I
1116n3kV' 11513wTT
1
I-------
YI Beacon Substation
115kv to l mI �yI"�
Third 8 I I
Hatch
Figure 6: Beacon — Francis & Cedar 115kV Reinforcement
Preliminary scope to mitigate the remaining thermal issues for Beacon — Bell interconnections
is shown in Figure 7.
Page 22 of 89
�j

System Assessment 2023-2024An dix D
Reinforcement Notes
OInstall two new line positions at BPA's
Trentwood Substation,requiring coordination
with BPA.
O Loop existing Boulder—Irvin 111 115111
'2 Transmission Line into BPA's Trentwood
115kV to Bell#1 Substation with two,0.5 mile single circuit
115kV to 115kV to Bell#2 115KV transmission lines.
Beacon#2 Interchange metering is required for the new
Boulder
to 115kV tor#2 Beacon#1 Boulder—Trentwood 115kV and Irvin—
Trentwood 115kV Transmission lines,to be
coordinated with BPA. Boulder Substation
—I ———— 230M15kV—————,
115kV I Transformer
115kV
I West Bus 115kV
East Bus I
Irvin Station I y T
O115kV to Spokane
Millwood 0_5,11 Ind.Park
115kV to Otis 91&#2
115kV to
Opportunity I
115kV
I
I
I O
Trentwood
Substation(BPA)
Figure 7: Boulder— Irvin #1 115kV Loop into Trentwood
The requirement for the North Spokane Transmission Reinforcement project was identified
through the transmission steady state near-term and long-term contingency analysis. Specific
project scope will be provided in subsequent study documents.
4.2.1 .4. Sandpoint Transmission Reinforcement
The Sandpoint area is served by three transmission lines. An N-1-1 (P6 long lead) outage
involving the Libby 230/115kV Transformer 1 and Cabinet 230/115kV Transformer 1 leaves
only the Albeni Falls — Sand Creek 115kV Transmission Line serving load in the area. This
outage combination under forced conditions may result in load shedding during Heavy Winter
scenarios.
A reinforcement project needs to be developed to mitigate the observed transmission line
overloads and low voltages under outage conditions. Several alternatives exist and vary in
scope. The project may include the construction of a new 115kV transmission line to the
Sandpoint area from Rathdrum or Albeni Falls Stations, providing a fourth transmission line
into the area. Coordination of a project with Bonneville Power Administration (BPA) could
include upgrades to the Albeni Falls — Sand Creek 115kV Transmission Line and the
construction of additional capacitor banks in the area. The optimum long-term mitigation
alternative has not been determined. Further analysis of the project is necessary and will be
evaluated in subsequent system assessments.
The need for the Sandpoint Transmission Reinforcement project was identified through the
transmission steady state near-term contingency analysis.
4.2.1 .5. Beacon Transmission Reinforcement
Performance of Beacon Station is a critical part of reliably serving load in Spokane. Short
circuit and contingency analysis indicate improvements are necessary to meet reliability
requirements.
Page 23 of 89

System Assessment 2023-2024�n dix D
The available fault duties for high voltage circuit breakers at the Beacon Station presently
exceed 95% of their interrupting ratings. The A-608 and A-614 positions, protecting Beacon
115/13kV Transformer 1 and 2 respectively, have an available fault current above 38kA.
Several other 115kV transmission line positions have fault duties greater than 90% of their
equipment rating or exceeding the equipment rating after planned projects are constructed in
the area. Initial review of the mechanical capability of the bus indicated adequacy to the 40kA
level. Further evaluation of the existing station's mechanical design for fault withstand is also
necessary.
In addition to the underrated interrupting capabilities, a breaker failure of either the 115kV or
230kV tie breakers causes performance issues in the area. Outages including either Beacon
230/115kV transformer and the Bell 230/115V Transformer 6 also cause performance issues.
Long term outages of either Beacon transformers, even with an available spare, will cause
possible load serving constraints during heavy loading times. Bell Transformer 6 capacity also
needs to be addressed with BPA.
Protection system single point of failure analysis identified contingencies at Beacon as
problematic. Evaluation of design alternatives is required.
A rebuild of the Beacon Station is proposed. Evaluation of a feasible construction plan for the
rebuild needs to be developed. The resulting rebuilt station will require circuit breakers rated at
industry standard 50kA or greater, and bus configuration either as double bus double breaker
or breaker and a half. Additional consideration on whether a third 230/115kV transformer is
necessary or prudent is warranted.
The need for the Beacon Transmission Reinforcement project was identified through the
transmission short circuit analysis, steady-state contingency analysis, spare equipment
analysis, and single point of failure analysis. Further development of the scope for the Beacon
Transmission Reinforcement project is necessary and will be reviewed in subsequent system
assessments.
4.z. i .e. raiouse i ransmission meintorcemen
Two primary deficiencies in the Palouse area revolve around outages of the two 230/115kV
transformers or the two 115kV transmission lines connecting Moscow 230 Station to Shawnee
Station.
First, the combined N-1-1 (P6) outage of the Moscow 230 and Shawnee 230/115kV
transformers cause voltage collapse in the Palouse area if there are no mitigating actions
taken following the outage of the first transformer. System deficiencies are observed in all
scenarios studied but the worst performance occurs in the Heavy Winter scenario.
The current Operating Procedure to correct the voltage collapse, results in this load center
being served by only two 230/115kV transformers. Given a forced or planned outage of the
first transformer, followed by a second transformer outage (N-1-1, P6 long lead) a system
blackout (up to 200MW of load loss) is localized to the Palouse area. Some of the dropped
load can be restored by transferring to neighboring 115kV sources, but up to 60MW of load
would be permanently off-line during heavy load conditions until a 230/115kV transformer was
restored. The Operating Procedure permits the deferral of a Corrective Action Plan to meet the
TPL-001-5 requirements.
Secondly, the two 115kV transmission lines connecting Moscow Station to Shawnee Station
are nearing their load serving capacity. The primary issue is low voltage being observed for an
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System Assessment 2023-2024oplaendix o
N-1-1 (P6) outage of the Shawnee 230/115kV Transformer followed by either an outage of the
Moscow— South Pullman or Moscow 230 — Terra View 115kV Transmission Lines. A
maintenance issue is the N-1-1 (A6.1) combination of either of these lines open at Moscow
and the loss of the Shawnee 230/115kV transformer resulting in thermal overloads on the
remaining 115kV transmission line serving the loop.
These line issues occur during the heavy summer scenarios and can be addressed with an
Operating Procedure to transfer Moscow City Station south to the North Lewiston Station.
A preliminary concept to resolve these issues was explored. The first issue could be corrected
with a third 230/115kV transformer in the area and the 115kV line issues could be corrected by
extending the Moscow City — Leon Junction— North Lewiston 115kV Transmission Line into a
new 115kV line position at Moscow 230 Station, leaving Moscow City station on the new
networked line.
The requirement for the Palouse Transmission Reinforcement project was identified through
the transmission steady state near-term and long-term contingency analysis. Specific project
scope will be provided in subsequent study documents.
4.2.1 .7. Safely Interrupting Faults
The A-187 and A-511 circuit switchers at Airway Heights and the A-435 and A-436 circuit
switchers at Post Street are part of fault reduction schemes; none of which were evaluated in
detail in the previous system assessment.
The Airway Heights circuit switchers reach 90% of interrupting rating in the 2028 Heavy
Summer scenario and are overdutied in the 2033 Heavy Summer scenario utilizing the existing
fault reduction scheme. Replacement with appropriately rated circuit switchers or another
design alternative is required.
The Post Street circuit switchers are presently overdutied. Replacement with appropriately
rated circuit switchers and elimination of the fault reduction scheme is recommended.
The existing Safely Interrupting Faults project needs to expand scope to include the circuit
switcher replacements at Airway Heights and Post Street. The additional project scope was
identified through the transmission short circuit analysis. The distribution short circuit analysis
also identified two midline reclosers which are underrated. The C909R located on CDA121 and
E170 located on SP112F2 need to be replaced with recloser capable of interrupting 3500A.
4.2.1 .8. West of Lancaster
The transmission system located west of the Lancaster Station is constrained during period of
high generation. The outage of 230kV transmission lines, including the P7 outage of the
Beacon — Rathdrum and Lancaster— Rathdrum 230kV double circuit, will overload the parallel
115kV transmission lines.
Mitigation of the overloads can be achieved through modifications to Avista's Clark Fork RAS.
Further evaluation of proposed arming levels, triggering events, and generation tripping is
necessary.
4.2.2.Distribution
4.2.2.1 . Airway Heights Capacity Mitigation
The AIR12F1 feeder and Airway Height 115/13kV Transformer 2 do not meet the performance
criteria as identified in the distribution multi-year load-flow analysis. A proposed project scope
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System Assessment 2023-2024
"phendix D
to mitigate the identified issue is to transfer a portion of AIR12F1 along Highway 2 to FLN12F1.
The completion of the Flint Road Station in 2023 provides for sufficient new capacity to transfer
the load.
,npR,m Lbu
{.lr
n
®1
D g
8
.3 ennaA w
omnox �P
crAm�c aron,:... P I
Figure 8: Airway Heights Capacity Considerations
4.2.2.2. Glenrose Capacity Mitigation
A new station referred to as East Central Station is proposed to mitigate the Glenrose feeders
and transformers not meeting the performance criteria as identified in the distribution multi-
year load-flow analysis. Feasibility of constructing a new station within the timeframe required
to meet performance requirements may require additional mitigation measures. Upgrading the
existing feeder regulators to 438A regulators and replacing the transformer with a 30MVA
nominal transformer is a potential near-term mitigation project. The increased transformer size
would not include adding a third feeder to the station.
The following figure illustrates the proximity of the proposed East Central Station to existing
stations. In addition to offloading Glenrose Station, the new station will provide capacity to
reduce loading on Third & Hatch, Beacon, Ross Park, and Ninth & Central Stations.
Page 26 of 89
�j

System Assessment 2023-2024oRRQndix o
3HT12F1
■3HT12F2
■3HT12F3
■3HT12F4
■3HT12F5
■3HT12F6
3HT1ZF7
■3HT12F8
■9CE AUX Bus
■9CE12F1
■9CE12FZ
9CE12F3
■9CE12F4
.9CE12F5 N•�r
9CE12F6
BEA AUX Bus -
■BEA12F1
■BEA12F2 1
■BEA12F3
■BEA12F4
■BEA12F5
BEA12F6
BEA13T09
■GLN12F1
■GLN12F2 �L
■ROS12F2
rJilY���
ROS12F3
R0512F4
■ROS12F5
■ROS12F6
1—
Figure 9: Spokane Area Station Coverage
4.2.2.3. Lewiston Capacity Mitigation
The equipment at the stations located in the Lewiston area are shown to not meet the
performance criteria as identified in the distribution multi-year load-flow analysis. A proposed
mitigation project will require several individual projects which collectively will provide the
required system performance. The individual projects conceptually include:
• Rebuild existing South Lewiston Station with increased capacity
• Expand existing Tenth & Stewart Station to have six feeders
• Construct a new distribution station in the Lewiston Orchards neighborhood
• Construct a new distribution station previously referenced as Wheatland Station.
4.2.2.4. Liberty Lake Capacity Mitigation
A project is under development to mitigate equipment at the Liberty Lake Station not meeting
the performance criteria as identified in the distribution multi-year load-flow analysis.
Traditional mitigation alternatives are viewed to be challenging due to specific geographic
constraints surround the Liberty Lake area. Further evaluation of the identified performance
issues and possible non-traditional project alternatives is warranted.
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System Assessment 2023-2024�n dix D
4.2.2.5. Moscow Capacity Mitigati,.
A combination of projects is proposed in the Moscow area are proposed to address the
M15512 and M15514 feeders and Moscow 115/13kV Transformer 1 not meeting the
performance criteria as identified in the distribution multi-year load-flow analysis. Some
transfer of load between existing feeders will provide near-term capacity improvements until
more substantial capacity projects can be implemented. A new distribution station referred to
as Selkirk Station is proposed to be located south of Moscow. With the additional capacity
provided by the new station the existing Moscow Station can be rebuilt or upgraded to have
standardized equipment sizing of six 600A feeders and two 30MVA transformers.
4.2.2.6. North Spokane Distribution Reinforcement
Several projects are proposed when a reinforcement plan to address the performance issues
identified in the North Spokane area. There has been some infrastructure investment in the
area including new feeder ties, regulator upgrades, phase balancing, and load transfers. One
of the projects is the expansion of the existing Indian Trail Station with the addition of a 20MVA
transformer and two feeders. The project is already included in the five-year budget and
construction plan. New projects identified as part of the reinforcement plan include the
following:
• Add an additional 20MVA transformer to the Indian Trail Station and add two new
feeders.
• Replace the existing 20MVA transformers at the Northeast Station with 30MVA
transformers and add a sixth feeder.
• Reconfigure the feeder system to best utilize the added transformation capacity by
building new lines, adding switches and reconductoring where needed.
• Add an additional 30MVA transformer to the Mead Station and add two new feeders.
4.2.2.7. Rathdrum Capacity Mitigation
Installing a second feeder connected to the Rathdrum 115/13kV Transformer 2 is proposed to
mitigate the RAT231 not meeting the performance criteria as identified in the distribution multi-
year load-flow analysis. The existing Rathdrum 115/13kV Transformer 2 is a nominal 20MVA
transformer with sufficient capacity for a second feeder. The new feeder will be able to directly
offload RAT231 from either the south or west out of Rathdrum Station.
4.2.2.E Orin Capacity Mitigatior
A project is under development in the Colville area to mitigate the OR112F3 feeder and Orin
115/13kV Transformer 1 not meeting the performance criteria as identified in the distribution
multi-year load-flow analysis. Station equipment upgrades combined with upgrades on the
OR112F3 feeder could provide some additional capacity. Additional project concepts include
constructing a new distribution station near BPA's Colville Station or Avista's Colville Service
Center. Feeder integration work would include new main trunk construction to connect portions
of CLV12F4 and OR112F3.
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System Assessment 2023-2024�n dix D
o �
d:.
Figure 10: Colville Area Orin Feeder Mitigation
4.2.2.9. Wilbur Capacity Mitigation
A project is under development mitigate the Wilbur 115/13kV Transformer 1 not meeting the
performance criteria as identified in the distribution multi-year load-flow analysis. Upgrading
the existing transformer will provide sufficient capacity to meet the performance criteria. The
feasibility of upgrading equipment at Wilbur Station needs to be evaluated. Additional
alternatives include the implementation of non-traditional projects such as demand response,
targeted energy efficiency, and distribution connected generation.
4.2.2.10. Valley Capacity Mitigation
Valley 115/13kV Transformer 1 does not meet the performance criteria for summer and winter
as identified in the distribution multi-year load-flow analysis. Additionally, there are known
voltage issues that need to be addressed. Upgrading the existing transformer combined with
feeder protection upgrades will provide sufficient capacity to meet the performance criteria. A
project is under development to assess the feasibility of upgrading equipment at Valley Station.
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System Assessment 2023-2024�n dix D
5. Technical Analysis
5.1 . Transmission Steady State Near-Term Analysis (R2.1 )
Steady state analysis was performed on the transmission system models representing the
near-term planning horizon that represented peak, off peak, and sensitivity scenarios. If the
analysis indicates an inability of the system to meet the performance requirements, the System
Assessment shall include Corrective Action Plans addressing how the performance
requirements will be met. (TPL-001-5, R2.7)
5.1 .1 .Planning Events (R3.1)
The steady-state analysis of system normal conditions, described by the PO event,
demonstrated all Bulk Electric System (BES) facilities in the Avista system are within the
continuous thermal ratings and all transmission facility voltages are within the specified limits.
The following sections describe the study results from the steady state contingency analysis
for contingencies categorized as P1 through P7. The contingency analysis of P3 and P6
events considered Operating Procedures executed as part of system adjustments following the
initial outage condition. Some Operating Procedures associated with P2 and P6 events
consider corrective actions to utilize nonconsequential load loss.
5.1 .1 .1 . Heavy Summer Scenario (R2.1 .1 )
Beacon Station Breaker Failure and Bus Outages
A breaker failure condition on the R-427 breaker at Beacon Station results in system overloads
even with Five-Year Planned Projects implemented. These overload conditions occur on three
11 RV transmission lines including Bell — Northeast, Francis & Cedar— Northwest, and
Northwest —Westside, and the Bell 230/115kV Transformer 6. Overloads range from 102% to
112% within the five-year horizon, assuming the planned projects are implemented within that
same timeframe.
._.. ._. _ . _ —- _ .�. � ._ _ _ _T�'��T ��.a-V:°��� !•o.oragi�1'rnw!u.eiw ~Cj 4`�'" T�"„"
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.y.
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LATta°An.w ��
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ar nw i°n.. un�w. 'r'i
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Figure 11: R-427 Breaker Failure at Beacon In 2028 Heavy Summer with Projects Scenario
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System Assessment 2023-2024
"phandix D
An Operating Procedure to drop nonconsequential load can be used following the P2
contingency events at Beacon Station. The thermal overload violations are below emergency
ratings, allowing time for the System Operator to take a single action to reduce loading of the
equipment. The Operating Procedure permits the deferral of a Corrective Action Plan to meet
the TPL-001-5 requirements. The Beacon Transmission Reinforcement Planning Initiative will
be developed to address the performance concerns.
Bell 230/115kV Transformer 6 Outage
A contingency consisting of an outage of the Bell 230/115kV Transformer 6 followed by an
outage of the Beacon — Bell, Beacon — Northeast, or Bell — Northeast 115kV Transmission
Lines results in system overloads on the remaining 115kV transmission line between Beacon
and Bell stations. Overload magnitudes of 184% in the current year and 188% within the five-
year horizon are projected assuming all Five-Year Planned Projects are implemented.
Spk­
ME
,au v+r ,lA,Mr•�'.00i phi IAMM 1
w[ni N.WMS � �88PN n . a„ro,• �ii�� 1]�rs V�1� - ' ' -
r.ne pKct � ,iiiFB + n •
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�■�,MDwWH. , "'�1[�i. ._.\.. ,4[r ^J r_.. rl,onnw, MLIi ■ ,w.�iw ' ,..,n..nu w.r
■ TL
■. [[as o
<mQrnsv \1 ��r
'k�
Figure 12: Bell 230/115kV Transformer 6 and Beacon — Northeast 115kV Line Outage In
2028 Heavy Summer with Projects Scenario
An operating plan is required to mitigate this condition. The operating plan states that following
the initial outage, close Bell switch B-839 and open the line section between Waikiki and Bell
on the Beacon — Francis & Cedar 115kV Transmission Line.
The Operating Procedure permits the deferral of a Corrective Action Plan to meet the TPL-
001-5 requirements. The North Spokane System Reinforcement Planning Initiative and
Beacon Transmission Reinforcement Projects will be developed and proposed to address the
performance concerns.
Ninth and Central Station Bus Tie Breaker Failure
A breaker failure condition on the A-688 breaker at Ninth and Central Station results in system
overloads even with Five-Year Planned Projects implemented. The overload condition occurs
on the Ross Park— Third and Hatch 115kV Transmission Line. Overloads range from 104% to
115% within the five-year horizon, assuming the planned projects are implemented within that
same timeframe.
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System Assessment 2023-2024An dix D
as;M• 1.1 i gar ^+-,�
r '
9oIN• TM•
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I �A ..« It 95bSo: 9 /w 7) N*I � V MIIrIK YIM� ISTMW
Figure 13: A-688 Breaker Failure at Ninth & Central In 2028 Heavy Summer with Projects Scenario
An Operating Procedure to drop nonconsequential load can be used following the P2
contingency events at Ninth and Central Station. The thermal overload violations are below
emergency ratings, allowing time for the System Operator to take a single action to reduce
loading of the equipment. The Operating Procedure permits the deferral of a Corrective Action
Plan to meet the TPL-001-5 requirements. The Garden Springs Station project addresses the
performance concerns.
Rathdrum Station Breaker Failure and Bus Outages
A breaker failure condition on the A-624 breaker at Rathdrum Station results in system
overloads, even with Five-Year Planned Projects implemented. These overloads occur on the
Otis Orchards — Post Falls and Post Falls — Ramsey 115kV Transmission Lines. Overloads
range from 127% to 143% within the five-year horizon assuming all Five-Year Planned
Projects are implemented.
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1.7 MWr OMvn, 1.1Mvnr I1.1 Mrnr 1F
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Figure 14: A-624 Breaker Failure at Rathdrum in 2026 Heavy Summer with Projects Scenario
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System Assessment 2023-2024
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A Corrective Action Plan is necessary to mitigate the performance issues identified for an A-
624 breaker failure at Rathdrum Station. An effective Corrective Action Plan, the Coeur
d'Alene Transmission Reinforcement, will include projects to mitigate the observed overloaded
transmission lines and provide improved system resiliency for serving new customer growth in
the area.
Clearwater — North Lewiston Line Overload
A contingency consisting of an outage on the Dry Creek— Pound Lane 115kV Transmission
Line and a simultaneous outage on the Hatwai — Lolo 230kV Transmission Line results in
system overloads on the Clearwater— North Lewiston 115kV Transmission Line. An overload
of 116.3% exists within the five-year horizon assuming all Five-Year Planned Projects are
implemented. Other outages in the area, combined with an outage of the Hatwai — Lolo 230kV
Transmission Line, will also cause the Clearwater— North Lewiston 115kV Transmission Line
to exceed applicable facility ratings. WW
HAJ
.`
w'0 NIIWM Lewiston Clarkston Area
1 I.016 W
AN
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Figure 15: Hatwai — Lolo 230kV Line and Dry Creek— Pound Lane 115kV Line Outage In
2028 Heavy Summer with Projects Scenario
A Corrective Action Plan is necessary to mitigate the performance issues identified for the
Clearwater— North Lewiston 115kV Transmission Line exceeding applicable facility ratings. An
effective Corrective Action Plan, the Lewiston-Clarkston Transmission Reinforcement, will
include projects to mitigate the observed overloaded transmission line as well as provide
improved system resiliency for serving new customer growth in the area.
Francis & Cedar Transmission Line Outages
An outage of both the Francis & Cedar— Ross Park and Northwest— Westside 115kV
Transmission Lines leaves the Beacon — Francis & Cedar 115kV Transmission Line serving
the Northwest and Francis & Cedar stations.
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System Assessment 2023-2024
^phandix D
1.
- Y-----------------
Am
t S�okam
In
Mtl9l
�Te00 _. _.___.- arnw !,.•...,... a Zls_�inl,.. ~ i 1 r
pis lm t `
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If'� f-,, Ilrlw x,•Iw
"d"3''•"• �� w nr».. r':.....
Figure 16: Francis & Cedar— Ross Park and Northwest -Westside 115kV Line Outage In
2026 Heavy Summer with Projects Scenario
A Corrective Action Plan is necessary to mitigate the performance issues identified. A North
Spokane Transmission Reinforcement project will be developed and proposed to address the
performance concerns.
West Pitw iz�- i ie OULaycb
A contingency consisting of an outage on the College & Walnut — Westside 115kV
Transmission Line and a simultaneous outage on the Garden Springs — Westside 115kV
Transmission Line open at Westside results in system overloads. These overloads occur on
four 115kV transmission lines, Francis & Cedar— Northwest, Metro — Third & Hatch, Northwest
— Westside, and Ross Park — Third & Hatch. Overloads range from 103% to 116% within the
five-year horizon assuming all Five-Year Planned Projects are implemented.
Page 34 of 89

System Assessment 2023-2024�n dix D
I }
—
' fw IV w f
+�isl.w wY.ww Iff� e.)wv.. �f�aNG CO iW.. i I
(,�OIIwO is i 1
01)w 1RX11O N. i )0�)�0
o-%'
N.f N.welnrn 'IDI)w '� � I
n• _ 1,0 *—
fD ��II{{•.��_I.Om O'i 0' al.O w.r Il)� aDYv li0
i.l Wl 0 i�aw01� ~ � r I,uw wr
_, w WNw -r-- •— eN OOB W ICY
AK
Ix . * - .. °.�_ ��g'wve �s ^ I .OIO ww D0�,11f1 i/• � Ivw...) _
Figure 17: College & Walnut—Westside and Garden Springs —Westside 115kV Transmission Line
Open at Westside Outage In 2026 Heavy Summer with Projects Scenario
A Corrective Action Plan is necessary to mitigate the performance issues. An effective
Corrective Action Plan will include projects to mitigate the observed overloaded transmission
lines and provide improved system resiliency for serving new customer growth in the area.
Completion of the Garden Springs Station project, which includes scope to provide a 230kV
source into the area, will sufficiently address the identified performance issues. The Garden
Springs Station project is planned but will not be completed within the near-term planning
horizon.
heavy vvinier ,:)cenai,u krxZ. I . I)
Palouse Transformers
The combined outages of the Moscow 230 and Shawnee 230/115kV Transformers cause
potential voltage collapse in the Palouse area if there are no mitigating actions taken following
the outage of the first transformer. System deficiencies are observed in all scenarios studied
but the worst performance occurs in the Heavy Winter scenario. Low voltage issues are also
observed for an outage on the Shawnee 230/115kV Transformer 1 and subsequent outage on
the Moscow 230 — Terra View 115kV Transmission Line.
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System Assessment 2023-2024�n dix D
* �ww
..w ew.. P 1�P pp11AApp1f
UNP OIYOm1... nv�
i win
w. t.�.►..> a.a.s.s�►w -,-—s -.>-•►--s.�.s.�.i w P 7.��. o m
Lewiston Clarkston Area TIP
Figure 18: Moscow 230 230/115kV Transformer and Shawnee 230/115kV Transformer Outage In
2028 Heavy Winter with Projects Scenario
An Operating Procedure to reconfigure the system can be used following the first outage of
either Moscow 230 230/115kV Transformer 1 or Shawnee 230/115kV Transformer 1. The
results of the second transformer outage with the system reconfigured is a system blackout
localized to the Palouse area. The Operating Procedure permits the deferral of a Corrective
Action Plan to meet the TPL-001-5 requirements. A Palouse Transmission Reinforcement
project will be developed to address the performance concerns.
Sandpoint Area Outages
The outage of both the Libby 230/115kV Transformer 1 and Cabinet 230/115kV Transformer 1
will cause the Albeni Falls — Sand Creek 115kV Transmission Line to exceed applicable facility
ratings along with low voltage violations in the heavy loading scenarios. The remaining source
to the local area is the Albeni Falls — Sand Creek 115kV Transmission Line which is incapable
of providing sufficient reactive power support even if shunt capacitors are added at Sand
Creek, Bonners Ferry, and Sandpoint Stations.
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System Assessment 2023-2024�n dix D
j��
y .• _
MHIJN.Yt i,11lYYP. F)bIM w••• • IM.A
�e TIM
.d.�=.per... .-•�A;w%w._.�S aew. �--�oM`ilin I®Z,�ri
:.ire. •=-321�r�. y+os� jb° ,� as.«, �®i,�w.r
g,�, 1 — _� �.1�'q• (yam
ene. u� ` f�� i nor.^ � �e E,i.� ►'^
-7�r^ i ram
„n..
—
Figure 19: Cabinet 230/115kV Transformer 1 and Libby 230/115kV Transformer 1 Outage In
2028 Heavy Winter with Projects Scenario
A Corrective Action Plan is necessary to mitigate the performance issues as there is not a
feasible Operating Procedure to address the performance issues. An effective Corrective
Action Plan will include projects to mitigate the observed overloaded transmission lines as well
as provide improved system resiliency for serving new customer growth in the area. The
Sandpoint Transmission Reinforcement project will be developed to address the performance
concerns.
5.1 .1 .3. Light Spring Scenario (R2.1 .2)
Devil's Gap Area Overgeneration
The Addy — Devil's Gap 115kV Transmission Line overloads for the P6 outage of Airway
Heights — Devil's Gap and Nine Mile — Westside 115kV Transmission Lines. The Ford — Long
Lake — Devil's Gap sections of the Addy — Devil's Gap 115kV Transmission Line was recently
rebuilt, but the Devil's Gap A521 CTs continue to be a limiting element. Under P6 conditions, a
reduction in local generation is acceptable, therefore an existing Operating Procedure can be
used to meet performance requirements.
Page 37 of 89

System Assessment 2023-2024�n dix D
0.7 MW 0.996 pu _ r
0.0 Mvar LOON LK CLAYTOAL -y-;DE AtK+~
x 1.5 MW 3.3 M W 0.998 pu 1.00 pu L pu
s7%.5 Mvar 0.0 -r.
"^a 4.1 MW .4.9 MW 30.7 MW MILAN# MILAN 1.002yu
VALLEY A 0.0 Mvar 1.6 Mvar 0.3 Mvar �T 1.004 pu' t` 6.7 MW
p L - . ..1 0.1 Mvar
�0.994 u 9.6 MW 0.0 Mvar F -9:9 MW
3.2 Mvar 0.2 Mvar
x 8.3 MW
93�.2 Mvar �IU03 T.M.0
CORD 11.0 MW
1.005 pu 3.6 Mvar.,
5.7 MW
0.1 Mvar �NALFMOON+ v
1.011 pu
coL6ERT
LONGLAKT 9.4 MW I Y 1.0126yu
Z 1.009 3.1 Mvar'
LnTFALL
r 0.2 Mwr
L0110 Ism LNOD RTf"'
MW IO.010 P W
0.6MW �L.011pu - 14,2Mvar
0.0 Mnr Naar Solo pu NI.012 c v
1 21 MW 1.012 pu
��O IMMf� DlVII0" v O Mvar 7 MW v 8.7 MW
BMW 1.0M pu 1. pu "�yj 21 MW I -7 Mvar 0.2,Mvar
f 0 ME 0 Mvar [.. 7 MW V MEAD 5
�1L�/�/n��' ^�1 1 -O Mvar �1.014p
1 *0 N1Rf 'ems! ■ r I�J 01Mvar �.� 7 MIN - Y
d 8 MW '.e+r' •w E I 21 MW -0 Mvar
0 Mwr W LONGLAKEl Mvar �. 0 Mvar [NDTRAIL ' E p
■ 1.010 Du _ ■ (7 \ �0.00 Du 1.Dld q
�J O.O MW
/ 0.0 Mvar „ y
Figure 20: Airway Heights - Devil's Gap and Nine Mile - Westside 115kV Transmission Line Outage In
2024 Light Spring Scenario
Stratford Area Overgeneration
The Chelan - Stratford 115kV Transmission Line overloads based on outage combinations
from the Stratford Station. The 49.4 miles long transmission line is composed of 1948 CU, 250
CU, and 556.5 ACSR conductor segments resulting in a capacity limitation of 92.41VIVA at
40°C. Under P6 conditions, a reduction in local generation is acceptable, therefore an existing
Operating Procedure can be used to meet performance requirements until the Chelan -
Stratford 115kV Transmission Line is rebuilt based on age and condition.
CHELAN
BRAYS LD
1.013pu •- - - � -•- - - +
11.018 �lGlipu 0.00MW y I t
p' OAO Mvar r
0.00MW / s `►- - - '
1.2 Mvar F0M,.,
p 0.,Mvar /'
, /' / / / COUL2GPD
ORONDO ,�,`�•/' ! 1.038 pu
NNRYTAP / f - -
5.4 MW / .2 MW
0.5 Mvar /N�EADWORK lOUL CTY / 1 Mvar
W
/ d NW 64W •�/�
OC K S M9r 0.1 MNrar
I�
/ I•// /%M � WILSONCK
T-0.000 Pu
��!/ / /•I•/I - 0.0 MW
0.0 Mvar
45 MW
Mvar
Cll STRATFRD
1.031 pu
C31 �/•/ /
Figure 21: Devil's Gap - Stratford and Larson - Stratford 115kV Transmission Line Outage In
2024 Light Spring Scenario
Page 38 of 89

System Assessment 2023-2024�n dix D
5.1 .1 .4. Light Summer High Transfer Sensitivity (R2.1 .4)
West of Lancaster Overloads
The Boulder— Rathdrum, Otis Orchards — Post Falls and Post Falls — Ramsey 115kV
Transmission Lines overload for the P7 outage of the Beacon — Rathdrum and Lancaster—
Rathdrum 230kV double circuit. Similar overloads occur for the P7 outage of Beacon —
Rathdrum and Boulder— Lancaster 230kV double circuit outage. There are also multiple N-1-1
(P6) 230kV outage combinations that result in overloading the underlying 115kV system during
this condition.
In the past the underlying 115kV system was protected via thermal relays which opened both
115kV lines in the event of an overload. The protection scheme was removed with the loop-in
of Lancaster given the action now resulted in an overload of BPA's Bell — Lancaster 230kV
Transmission Line.
This has become more of an issue since Avista entered the Energy Imbalance Market (EIM).
Prior to entering the EIM, the Rathdrum CTs were rarely on-line during spring runoff (high
transfer season). The N-1-1 (P6) issue has shown up in real-time recently during planned
outages and the 230kV double circuit (P7) outage issue is now common.
Local generation can be reduced to mitigate N-1-1 contingency issues. A Remedial Action
Scheme (RAS) to drop local generation to mitigate the 230kV double circuit (P7) outage issues
will be required if future generation is incorporated in the Rathdrum area. This new RAS would
be armed based on West of Lancaster flows and would have to be coordinated with BPA and
generation at Rathdrum and Lancaster. The Operating Procedure permits the deferral of a
Corrective Action Plan to meet the TPL-001-5 requirements.
OASTR 7A KW
IAV P. 0.11WOr
RATMOLIN
-• • • 1.037 w
°Pw#PwR » OWN
3 = O NN RMIIDR111Y O 0 MT10R11[
i\"!\• /: -./`'� 7 M 0M 1.037w 1A37DO 4P M
W 1 1 BOUIDERE� » OWN T 1.7NW 3A NW 2.9 MW 75 NW 75 NW
1.009 w 0 r*_ DA Ph- GO NWR 0.0 m-0.0 m- 13 W_17 NV W
ON- 1 b U147d PLEASANT • ••
MDOH 1A NO10 P. EDA RD ._
ADT L014 w MII[E3ER
3A14w
NAYDEN
1A30 w
0.0 �0.1 Aw 0.11 M V alb AV DALE
P.P . w7
E.G.1.6111Y - .�0.S NW 3.013Pu
„ / 0.0 Nvn I flmx
0 NOR, T fAu w KW
a1 W.,
P {^y
W POST PIS PRAd1l0 ARM W_yoA
1 OEgiROAD lAfOw L011
T Adh 7.0 RAIWEY DALTON A
L011 w 3.011 P.
4lA Pk- FL3jwOJ 11v.r aGA fA Nw 0.S NW J
0.3 Mv.r I OA W.- 3a0 MW
0.6 Mv.1
4 NW
y - ~0"", A 711L3A R3
A
MW
eUECR K• M
I.SS0I
Sim
.0
PN pan
LIBT W : DOWRRD APPLEWAY 1011
,jig
M �L P. 7.4_N 1.033w 1,012
I4 00 MW
ONV. DA 1.0NW
120 MW 4NV 5.2 Mw 17.7 NW 1.017 Pu 0. y 0.1
O.i My ONvu01 OA .1
4MP 1.0 NW 16.3w OMv., !O.O Nva.
Figure 22: Beacon - Rathdrum and Boulder- Rathdrum 230kV Transmission Line Outage In
2028 Light Summer West of Hatwai (WOH) Scenario
Page 39 of 89

System Assessment 2023-2024oRRQndix D
5.1 .1 .5. Voltage Ride-Through (R3.3.1 .1 )
Voltage ride-through analysis includes evaluating the tripping of generators where simulations
indicate generator bus voltages or high side of the generation step up voltages are less than
known or assumed minimum generator steady state or ride-through voltage limits. Voltage
ride-through limits are monitored according to PRC-024 —Attachment 2 (TPL-001-5, R3.3.1.1).
Analysis shows no instances where generator bus voltages and generation step up voltages
exceed PRC-024 limits in the near-term planning horizon.
5.1 .1 .6. Cascading
Relay Loadability Tripping (R3.3.1 .2)
The tripping of transmission elements when relay loadability limits are exceeded was studied
for P1 - P7 contingency events. Transmission elements are monitored at 115% of their
maximum ratings. Avista's PRC-023 R6 study methodology includes monitoring circuit loading
at 130% of the facility rating for double contingency combinations. If transmission elements
exceed 130% of the facility rating in the PRC-023 R6 study, then their protection settings are
set to not operate at or below 115% of the highest seasonal facility rating. When applicable for
P3 and P6 contingency events, mitigation alternatives were evaluated following the first outage
to prevent elements from exceeding 115% of their maximum rating following the second
outage.
In all scenarios studied, the Beacon — Northeast 115kV Transmission Line and Bell 230/115kV
Transformer 6 (P6) outage causes the Beacon — Bell 115kV Transmission Line to exceed
115% of its maximum rating. The subsequent tripping of the Beacon — Bell 115kV
Transmission Line separates Avista's system from BPA at Bell and results in voltage collapse
in BPA's 115kV system. The observed voltage collapse is contained to the local area and is a
known issue on BPA's system. Figure 23 shows the results of the voltage collapse condition.
There is a temporary Operating Procedure to reconfigure the system to make a third Beacon —
Bell 115kV Transmission Line as an interim measure until a more permanent solution is
developed. The Operating Procedure permits the deferral of a Corrective Action Plan to meet
the TPL-001-5 requirements. A North Spokane System Reinforcement Planning Initiative will
be developed and proposed to address the performance concerns.
Page 40 of 89

System Assessment 2023-2024,,iapQndix D
T
:1 f
vpm
Lill-,
4mr
"M V&
L
"Mr7t
"VAT,
61 �7
M X
770—'"n
Figure 23: Northwest—Westside 115kV and Bell Bank#6 Followed by Opening Beacon — Bell 115kV
in 2028 Heavy Summer with Projects Scenario
The loading of transmission elements exceeding 115% of their maximum facility ratings is
provided in Table 6. With mitigation alternatives included between outages of the listed P6
contingency events there was no further tripping of transmission elements to simulate.
28HS
P2 Contingency 24LSp 24HS I 28HSp 28HS Projects 28AHW
BF:A624 Rathdrurn East&West 115kV
Otis Orchard-Post Falls 115kV(Beck Road Tap-Post Falls) 745.2
P6
N-1: Beacon-Northeast 115kV+T-1: Bell#6 230/115kV
Beacon-Bell#1 115kV 873.7 11 879.3 1 791.1 896.5 1 895.6 987.5
Table 6: Loading of Transmission Elements Exceeding 115% of Highest Rating in
Near-Term Planning Horizon (Amps)
System Instability (WR4 4)
Cascading is identified when a post contingency analysis of category PO - P7 events result in
steady-state facility loading that is either more than a known BES facility trip setting or exceeds
125% of the highest seasonal facility rating for the BES facility studied and when subsequently
tripped causes additional facilities to exceed 125% of the highest seasonal facility rating. Table
7 provides the filtered results of the steady state near-term contingency analysis to show only
elements exceeding 125% of the monitored seasonal rating.
28HS 28LS
OH
P2 Contingency 24LSp � 24HS 28HSp 28HS Projects W 28HW
BF:A624 Rathdrum East&West 115kV
Otis Orchard-Post Falls 115kV(East Farms Tap-Beck Road Tap) 132.7 129.6 132.8
Otis Orchard-Post Falls 115kV(East Farms Tap-Otis Orchard) 142.7 139.7 143.0
Post Falls-Ramsey 115kV(Post Falls-Prairie) 128.6 122.9 127.1 106.1
P6 I
4 WR4 represents the WECC definition of cascading as defined in TPL-001-5. (TPL-001-WECC-CRT-3.2)
Page 41 of 89

System Assessment 2023-2024An dix D
Contingency -:12411-Sp 24HS 28HSp 28HS Projects •
N-1: Beacon-Bell#1 115kV+T-1: Bell#6 230/115kV
IBeacon-Northeast 115kV 128.8 147.5 116.9 149.6 149.4 112.4
N-1: Beacon-Northeast 115kV+T-1: Bell#6 230/115kV
IBeacon-Bell#1 115kV 1 165.7 189.5 150.1 192.2 192.0 122.7 145.7
N-1: Beacon-Rathdrum 230kV+N-1: Lancaster-Rathdrum 230kV
Boulder-Rathdrum 115kV(Boulder-Moab) I I I 131.1
Boulder-Rathdrum 115kV(Moab-Pleasant) 132.5
IBoulder-Rathdrum 115kV(Pleasant-Idaho Rd) 138.9 I
N-1: Bell-Northeast 115kV+T-1: Bell#6 230/115kV
Beacon-Bell#1 115kV I 142.9 130.0 119.4 1 130.0 1 129.9 1 101.9 109.2
I N-1: Cabinet-Rathdrum 230kV+N-1: Noxon-Pine Creek 230kV I I I I I
IXON WEST(40787)->IANCASTR(40624)CKT 1 at
NOXO 132.7 I I I 124.0 I I
P7 I I I I
N-2: Beacon-Rathdrum 230kV&Boulder-Lancaster 230kV
I 2o Beacon m 230kVulder-
o- m 130.2
Rathdrum &Lancaster Rathdru 230kV N I
Boulder-Rathdrum 115kV(Boulder-Moab) I 131.1
I Boulder-Rathdrum 115kV(Moab-Pleasant) I I I I 132.5 I
Boulder-Rathdrum 115kV(Pleasant-Idaho Rd) 138.9
Table 7: Facility Loading Exceeding 125% Of Seasonal Rating in Near-Term Planning Horizon (%)
The Rathdrum A-624 breaker failure contingency causes the Otis Orchards - Post Falls and
Post Falls - Ramsey 115kV Transmission Lines to exceed 125% of their seasonal rating. Load
in the Coeur d'Alene area directly impacts the loading of the remaining transmission lines
following the outage. Subsequent tripping of the Otis Orchards - Post Falls 115kV
Transmission Line causes the CdA 15th St. - Pine Creek 115kV Transmission Line to exceed
125% of its seasonal rating with a localized voltage collapse in the Coeur d'Alene area. Figure
24 shows the results of the cascading condition. A Corrective Action Plan is necessary to
address the performance issues.
. . . . . . . . . . . . . _
NAIMINtUM
1.010 W
Ra nM�,..
8 = :.w 01 NW T a "AT rR r r
BOUtDEpge -, p:w T 0.0NW aONW 0.0NW 0 �Nw
i LUUI) a o.oN.. o.aN.r ooN.arao ogM.r oNw Coeurd'AlencKEPSAM u�
1 1AIXi
MN ,21
00I, otwl It
33MW NW W
P�
ffR a9 N fig, .� A10.7NW AVO LL
A W- 3.106-
..I M1 r...Mlv•...
r TIrF9 N.7RNaA
)M.WSE L9 L358
a
La PAN
1.-1MW 7OSTTTS VOAIRMS M-
E
P. 99Q0[UW
W OLLTMA%J 09771W
N 1914�4 1% p:MI.MW ,...
IIO97Tyy .,»10IWMW
r OF DU6]ry. ` )p
I.pI9�g1 0Nwr 1 0.1-m4nIWr �0.5 7)NW
l4./MW ;»OMW S.7 NW '..�.•• 70.6 MW O.
a.!Mvar O Mwr LS Nw 7A Ilvar ,/ r
0 Mwr 0.4 N ml.�T M E71Mf
F7a9 Nw
Figure 24: Rathdrum A-624 Breaker Failure Followed by Opening Otis Orchards- Post Falls in
2028 Heavy Summer with Projects Scenario
The N-1-1 (P6) Bell 230/115kV Transformer 6 outage paired with various local 115kV
transmission lines causes the remaining 115kV lines between Beacon and Bell to exceed
125% of their seasonal rating. The subsequent tripping of the remaining 115kV transmission
lines separates Avista's system from BPA at Bell and results in voltage collapse in BPA's
Page 42 of 89

System Assessment 2023-2024�n dix D
115kV system but does not result in the remaining transmission lines to exceed 125% of their
seasonal ratings. Figure 25 shows the results of the cascading condition. A Corrective Action
Plan is not necessary to address the performance issues as an Operating Procedure can be
used, though the system issues mentioned above, will warrant a solution to this deficiency.
rAWW
�e r=seAli
�.ffid— s�o-m�• 3 .v:tee•
07:
-}moo^,,.
Figure 25: Bell #6 and a Second 115kV Local Outage Followed by Opening the Remaining Beacon to
Bell 115kV Transmission Line in 2028 Heavy Summer with Projects Scenario
The remaining N-1-1 (P6) and N-2 (P7) issues associated with the 2028 Light Summer High
Transfer scenario are addressed in Section 5.1.1.4 above.
With mitigation alternatives included between outages of the listed P6 contingency events in
Table 7, there was no further tripping of transmission elements to simulate.
5.1 .1 .7. Unsolved
The P1 — P7 contingency events in the near-term planning horizon were monitored for
unsolved power flow solutions. The results are provided in Table 8.
•
A6
N-1:Albeni Falls-Sand Creek 115kV Open @ ALB+
N-1: Bronx-Cabinet 115kV • • . • . . 116.3
I N-1:Albeni Falls-Sand Creek 115kV Open @ ALB+
N-1: Bronx-Sand Creek 115kV • -•
N-1:Albeni Falls-Sand Creek 115kV Open @ ALB+
T-1: Cabinet Gore 230/115kV 148.4 149.8 149.8 . -.
A7
N-1:Albeni Falls-Sand Creek 115kV Open @ ALB+
N-2: Flathead-Libby 230kV&Libby-Noxon
230kV . -.
N-1: Brownlee-Hells Canyon 230kV+N-2: Flathead
-Libby 230kV&Libby-Noxon 230kV unsolved unsolved unsolved
IN-1: Columbia Falls-Flathead 230kV+N-2:
Conkelley-Libby 230kV&Libby-Noxon 230kV • -• 154.6
N-1: Flathead-Hot Springs 230kV+N-2: Flathead-
Libby 230kV&Libby-Noxon 230kV 217.1
N-2:Albeni Falls-Sand Creek 115kV&Bronx-Sand
Creek 115kV+N-1: Flathead-Libby 230kV . -.
Page 43 of 89

System Assessment 2023-2024oPpQndix o
Contingency 24LSp
N-2:Albeni Falls-Sand Creek 115kV&Bronx-Sand
Creek 115kV+T-1: Hungry Horse#1 230/13.8kV • -•
N-2: Brownlee-Hells Canyon 230kV&Lolo-Oxbow
230kV+N-2: Flathead-Libby 230kV&Libby-
Noxon 230kV • -• • • • -• •
Table 8: Steady State Near-Term Unsolved Contingency Results in Near-Term Planning Horizon
There were no P1 — P7 contingency events in the near-term planning horizon that resulted in
an unsolved power flow solution. The restoration contingencies are shown above for reference.
For reference, the A6 contingency of the Albeni Falls — Sand Creek 115kV Transmission Line
open at Albeni Falls and Cabinet Gorge 230/115kV Transformer 1 led to an unsolved condition
applicable to Avista. The resulting power flow condition is shown in Figure 26. A localized
voltage collapse occurs in the Sandpoint area with the load being served only from Libby
Station, located roughly 90 miles away.
,ta
P M ow.
e M..
M. fie" stw.. ail�M.r
Itlw�
1 n ewl e. ueON"�
,w• � eerw
�=i . vovcan. siw
7
O.:Mr. 0.SMw
Im wu } I�Ieo�iM • fllwtel F 0.0 Mv► Ptw. ,
1• let I
:We. e.lo.t, .ems -e�e.—.l
•� oew. le�. leelsc
ee� eMr
7Mt
aeiw.
pyp{ il�wr
e00e W �
ilk pOyMeMF
LNeeeee 20�. ull�. IMNMW IeO MW`^�' eMYI MMW
Figure 26: Unsolved Condition for N-1: Albeni Falls - Sand Creek 115kV + T-1: Cabinet Gorge
230/115kV in 2026 Heavy Winter Scenario
5.1 .2.Extreme Events (R3.2)
The following sections describe the study results from the steady state contingency analysis
for contingencies categorized as extreme events in the near-term planning horizon.
5.1 .2.1 . Right-of-Way Outages
The transmission line right-of-way south of Westside Station contains the College & Walnut—
Westside and Sunset— Westside 115kV Transmission Lines. The Sunset— Westside 115kV
Transmission Line will become the Garden Springs —Westside 115kV Transmission Line
following completion of the Garden Springs Station Project. An outage of both transmission
lines in the right-of-way causes facilities to exceed their applicable facility ratings. Figure 27
shows the simulation result for the 2028 Heavy Summer scenario. Cascading was not
observed.
Page 44 of 89

System Assessment 2023-2024An dix D
I�.e r•rr —.___._. 1y�tlp[(11pp 4 N1�N-- WAyIK, W I ...�_ _.� — —.�_�.•. L INW
TAW
5]VENf 1#I{0 �Ns: I.OIIW rI ^l I 1 AAAI
�6000 wN1 '�^.•� >ar Nril.� T 1
® ,Qoarw•r L9IM "" G�11•W 1 }
�+wA1N5 ��/t/ S,�,w W11•W 1A N11 �[AppNN q'a MN 1 •
1 N U1�
Ir 001
1Ask—
�1rw IIAM�Wr•rW
NS NrrjMM"wr IN. 14S �rr `
n u," Y"�.IN.. noN.r,:A �.. i�1��'• �:�
lI
r, '. l�a'tN""r. *' � .. C.
Figure 27: College &Walnut - Westside 115kV and Garden Springs - Westside 115kV Right-Of-Way
Extreme Event In 2028 Heavy Summer with Projects Scenario
In the Heavy Spring, Heavy Summer, and High Transfer scenarios, the right-of-way outage
west of Lancaster Station causes the underlying 11 RV transmission system to exceed
applicable facility ratings. Generation located east of the area contributes to the overload
condition. Figure 28 shows the simulation result for the 2028 Heavy Spring scenario.
Cascading was not observed.
—A ,
I.al{. JISMw ,
- - - — — — — — — — — t-._.,..�. .-. �_.— - — - - _.. . � -
— M lam
a �IW� lu JiI�AR n1A�r. IDAI•D R0
t � 1 F--.•f 7 I-011 W INYOIN IND7.. (
'1"{Or• i .6A .9U.J MW r 9U,9NW
1 01 Mvar ]Near ]Mvar
OANINN. i)MW le.9 NW IAY [
1. yu OA Nvar 9J Mr9r
Ls M
f IlM
L9.0 MN 1.01]ptl L2 H—
TRINIW00
1.019 w '
0ns rosnls raAlal{ u.r„r,a,
MW ,.611W ANM BIC10l0AD
2 1.006 DO 1.009
Itvar l.J Ilrar 1'00 I.OM N 1 rF-I� 1
11` MNS[Y NALMA
)w ]].9 Nrar 9.0 •0.)FN
0111YY •1 ].1 MW F •I,J MW
J Mva. O�MVIr ]a Y IlA
LLIW{r
11I111VAN• p
4MMra;W.]N9MWAMW a..
Mv ]6.9MW
1 ar 0.{Mvar A—
Figure 28: Bell - Taft 500kV And Bell - Lancaster 230kV And Beacon - Rathdrum 230kV And Boulder-
Lancaster 230kV Right-of-Way Extreme Event in 2028 Heavy Spring with Project Scenario
5.1 .2.2. Station Outages
The entire loss of either the Bell or Beacon Station was the most severe extreme contingency
and the only extreme event whose impact was not completely mitigated by applying available
measures. Either event is considered to have an extremely low probability of occurrence. If
either event were to occur, it is likely to progress with intermediate steps allowing Operating
Procedures to minimize the impact to the transmission system.
Page 45 of 89
�j

System Assessment 2023-2024An dix D
5.1 .3.Voltage Stability
5.1 .3.1 . Maximum Power Transfer Analysis
A load ramp maximum power transfer analysis was conducted for five geographic areas in
Avista's electric system. The load in each area was increased until voltage collapse occurred.
All additional generation necessary to supply the increase in load came from a distribution of
all generation in WECC. The following sections provide the analysis results including
identification of critical buses to be further analyzed for adequate reactive power margin.
The limiting contingency in the Big Bend Area is a breaker failure on the Larson — Sand Dunes
— Warden 115kV Transmission Line at Grant County PUD's Larson Station with total area load
of 807MW. The critical bus for the area is the Odessa Station. Recently completed projects,
including projects associated with Saddle Mountain and Rattlesnake Flats, have improved the
system performance in the area.
9; —-
90
091
U92
06
0 006
\ �`
\084
oe 0 \
2
on
e16
u
-2
01 \
I" \
O 66
e e.
62
ue
wo aao eoo eoo 200 6uc soo ,o0o 11w :co Iwo wu
lot,6 NA A—b AIM6f.>n•AVA by 6—
-Mee t...OMSSA 11601462%I -M 06141OL-1I"..- .. , n..vv6m OMU-1401Ie266, -6l e81n2l.,.;^•.11.:--Sr—Me$A_I160iIN-W
N.I then•fta..Ilew MEW'.I6.OIM296,
Budd Date: Ass, 2923
Figure 29: Big Bend Area Maximum Power Transfer Analysis Results
The limiting contingency in the Coeur d'Alene Area is a tie breaker failure on the Rathdrum
Station 115kV buses with total area load of 619MW. The critical bus for the area is the Hayden
Station. Recently completed projects, including the Magic Corner and Coeur d'Alene 15t" St. —
Pine Creek 115kV Transmission Line Rebuild projects, have improved the system
performance in the area.
Page 46 of 89

System Assessment 2023-20244 dix D
Bs
00
oe
0 T6
i1
46
os6
a 0S
°.a
>s
.•3
Ole
02
0 1i
ut
ow
0
BGD ago 1.000 1200 1 a00 1600 I NO 2 000 2200 2.P:
aB NA P.r3YMea1 2 ea'!P C°aur D'4ane
9aNCNa MPVOF411601YIN1 -hlt gM°In facot l6BV MAVDBN 116 BrYIMr -BYPS"11aT3r.m FN1116 k'l Ceav a4ana lsm SillaMbin l41YJF11116°Iae1Ur
�P62a Ilat'r0rum Fast a Waal tta.V.11P131FN r 160141Nt
Build Date:May 12.2023
Figure 30: Coeur d'Alene Area Maximum Power Transfer Analysis Results
The limiting contingency in the Lewis-Clark Area is a breaker failure on the Clearwater— Lolo
115kV Transmission Line at Lolo Station with total area load of 319MW. The critical bus for the
area is the East Grangeville Station.
0 9• _
-
iB
0 B6
o Te
OT.
012
;T
160
0 ie
0 Sa
3(p .O0 600 a°B T00 No M I.000 I100 1100
LO.OVN.MraY 1Naj°n.PVa LMabnGa'a301
-b3e W.CGM111rW_1ta01N1Hi -eM3010-11a.V CGR%.'1T.o IIS.aBlr� DB�aa5�ai.1l'S.':L 'r'�1160{NiiBt v.t rlc C<.ce.Orolne lt6aV FGMI:TPP t1601aa11Br
Build Date:May 12.2023
Figure 31: Lewis-Clark Area Maximum Power Transfer Analysis Results
The limiting contingency in the Palouse Area is the loss of the Moscow 230 230/115kV
Transformer 1 with total area load of 458MW. The critical bus for the area is the Garfield
Station.
Page 47 of 89
�r

System Assessment 2023-2024An dix D
os ``�� -----. ----�`` - ---
r6
O6
066
0 16
?OD ]O0 A]0 SD] eC0 b0 e00 90C 1000 I1W 1]00 1]D] 1.t0D
sOMW Awfls Mss6rCons AYA hlous
-BusCuo OMF16D_II(]INI]]1 -RISSnoonso]]0 kJ GMFIELD-Ir6CiNlll -e(Ns6 Moscow-TonsVNw.lbstor l]4,16.VT�nflo.nr C.PIIFi9D_116 DIfell]'r T1 uastoNJ]O ilbll(fV Gyl 62D IIS D(tef 111
Build Dare:May 12.2023
Figure 32: Palouse Area Maximum Power Transfer Analysis Results
The limiting contingency in the Spokane Area is the is the tie breaker failure on the Beacon
Station 115kV buses with total area load of 1,135MW. The critical bus for the area is the
Cheney Station.
on
oe \
n
ore
o rr:. \ \
a ` \
ON 1 \
1000 I.m I." Im lean 2= 1.J00 2e 1.600 I.e00 3000
LwSIAW A.hh.W-;nFAVA 50NFns
-66f.Gw C11EN61 11601ww -BF R4271)* + -LSEVE MkV.CN04EY_I1601t0:16) -OF N006--W&( W 1161v CNEII�_116 DIt�161
BN.COJNFe6 —COWu-A'uh-2WV CHEWS 11601"M)
Bulk)Date:May 12, 2023
Figure 33: Spokane Area Maximum Power Transfer Analysis Results
5.1 .3.2. Reactive Power Injection (UV) Analysis
The reactive power and voltage relationship show the sensitivity and variation of bus voltages
with respect to reactive power injections or absorptions. A system is considered stable, with
respect to voltage, if QV sensitivity is positive for every bus. Positive reactive margin is an
indication of the transmission system's ability to maintain voltage stability. Low reactive margin
(below 200Mvar at any 230kV bus or any 230/115kV source on the low side) is considered
marginal and is indicative of potential system concerns with voltage instability.
The critical buses identified in the maximum power transfer analysis and 115kV buses of
230/115kV transformers were studied in a QV analysis. The QV analysis showed there is
adequate reactive margin for the 115kV source buses and critical buses for each of the areas
studied. All buses studied showed a positive reactive margin. The East Grangeville Station
was shown to have the lowest reactive margin in Avista transmission system with all lines in
Page 48 of 89

System Assessment 2023-2024�n dix D
service and under a contingency event. The 115kV bus at Shawnee Station was shown to
have 113Mvar of reactive margin under the P6 event of both the Shawnee 230/115kV
Transformer 1 and Moscow 230 230/115kV Transformer 1. The reactive margin is adequate
but should continue to be monitored in subsequent study efforts.
Table 9 through Table 13 provide tabulated results of the QV analysis. Buses highlighted in
indicate they were the critical buses identified from the maximum power transfer
analysis. Reactive margin results less than 200Mvar are highlighted in red.
BF: GB-1410 Larson BF:GB1412 Larson
115kV,Larson-Sand 115kV,Larson- FN 1- Larson-
Base Case Dunes-Warden Stratford Stratfo d 115kV
Odessa 115kV -99 -53 -54 154
Saddle Mountain 115kV 1 -841 -812 1 -816 1837
Table 9: Big Bend Area QV Analysis Results (Mvar)
CoeurEast 115kV,
Base Case Rathdrum East and West 11 5kV East115kV
Cabinet Gorge 115kV 1 -390 -387 -381 -385
Hayden 115kV -686 NA -152 -234
Pine Creek -628 -611 -538 -601
Rathdrum -1080 NA NA NA
Table 10: Coeur d'Alene Area QV Analysis Results (Mvar)
BF:A445 . .
Base Case Clearwater-Lolo#2 BUS:Orofino 115kV Orofino 115kV
Dry Creek 115kV -833 1 -717 -812 1 -817
East Gran eville 115kV -84 1 -62 -48 1 -84
Lolo 115kV -1047 NA -957 -965
North Lewiston 115kV -860 -702 -835 -841
Table 11: Lewis-Clark Area QV Analysis Results (Mvar)BF:A845 Moscow-
Terre View,Moscow
Base Case Transformer 230/115kV BUS: Shawnee 230kV
Benewah115kV -384 -384 -383 1 -370
Moscow 115kV 1 -652 -163 -219 1 -476
Garfield 115kV 1 -114 -70 -80 1 -106
Shawnee 115kV -554 -388 384 -200
Table 12: Palouse Area QV Analysis Results (Mvar)
.0i
North and South 230kV and Coulee- North and South
Base Case 115kV Westside i
Beacon 115kV -1417 NA -1118 1 -948
Boulder 115kV -1234 -1000 -1105 1 -987
Cheney 115kV -208 -181 -185 1 -196
Westside 115kV -1131 -771 -575 -977
Table 13: Spokane Area QV Analysis Results (Mvar)
5.1 .4.Known Outages (R2.1 .4, R2.4.4)
Avista incorporates a three-step process to identify known outages of generation or
Transmission Facilities that are planned in the Near-Term Planning Horizon that may result in
system issues and then assesses the impact of selected known outages on System
performance.
Page 49 of 89

System Assessment 1 2023-2024�,ppe-dix D
• Generate a current list of planned outages of generation and Transmission Facilities in
the Near-Term Planning Horizon from the RC West webSmartOMS identifying all
system outages beginning January 1, 2024, through December 31, 2028.
o This is consistent with the documented outage coordination procedure RC0630
detailing the Outage Coordination Process.
• Identify planned outages from the RC West outage list that may result in system issues
based on existing near-term planning contingency results.
o If a planned outage results in potential system issues, verify that the planned
outage is scheduled during shoulder month loading.
• Perform assessment for the PO and P1 categories identified with the System peak or
Off-Peak conditions that the System is expected to experience when the known
outage(s) are planned.
Planned outages of generation or Transmission Facilities are listed in Table 14.
CoordinatedKnown
Season and System Assessment
Outage
DWORSHAK PH: PCB XJ-7 WIN: 1 hour None Not required
MIDWAY-BENTON NO 1 115KV LINE WIN: 20 days None Not required
TUCANNON RIVER: 115KV CAP GROUP 1 and 2 SPR: 11 days None Not required
ITAFT-BELL NO 1 500KV LINE SPR: 1 day None Not required
HUNGRY HORSE-CONKELLEY NO 1 230KV LINE SUM:4 days None Not required
GARRISON: 500 230KV TRANSFORMER 1 SUM: 10 days None Not required
HUNGRY HORSE-COLUMBIA FALLS NO 1 230KV LINE SUM:4 days None Not required
LITTLE GOOSE PH-LITTLE GOOSE NO 1 500KV LINE SUM:4 days None Not required
DWORSHAK PH-DWORSHAK NO 1 500KV LINE I FAL: 3 days None Not required
MIDWAY-BENTON NO 2 230KV LINE I FAL: 5 days None Not required
Table 14: Near-Term Planned Outage System Issues and Results
Studies determined that no known outages of Generation or Transmission Facilities, planned
in the Near-Term Planning Horizon, resulted in system issues that requires those outages to
be included in this System Assessment.
5.1 .5.Spare Equipment (R2.1 .5)
Avista's spare equipment strategy for transmission facilities provides for spares of the following
equipment: 230/115kV transformers, GSU transformers, transmission UG cable, HV circuit
breakers, HV air switches, shunt reactors and shunt capacitors.
Steady state analysis was performed on the transmission system models representing the
near-term planning horizon to study the impact of possible unavailability of Avista's 230/115kV
transformers and select other transformers. Category PO, P1 and P2 planning events were
evaluated with the pre-existing condition of a transformer outage for the following:
• Beacon 1 and 2 • Lolo 1 and 2
• Bell 6 (BPA) • Moscow 230
• Benewah • North Lewiston
• Boulder 1 and 2 • Pine Creek 1 and 2
• Cabinet Gorge • Rathdrum 1 and 2
• Dry Creek • Saddle Mountain
• Dworshak (USACE) • Shawnee
• Hatwai (BPA) • Westside 1 and 2
• Libby (BPA)
Page 50 of 89

System Assessment 2023-2024Appendix D
The following sections describe the study results not previously addressed in the near-term
planning analysis.
5.1 .5.1 . Big Mend Area
A Saddle Mountain 230/115kV Transformer outage resulted in no system performance issues.
However, generation from Rattlesnake Flats and Lind Solar could be curtailed per SOP-21.
5.1 .5.2. Coeur d'Alene Area
In addition to Cabinet and Libby 230/115kV outages already identified, outages for either
transformer and subsequent outages involving Albeni Falls — Priest River or Albeni Falls —
Sand Creek 115kV Transmission Lines result in area voltage collapse. These issues also will
be addressed as part of the Sandpoint Reinforcement Project Corrective Action Plan.
5.1 .5.3. Spokane Area
Outages of either Beacon 230/115kV transformer and subsequent outage involving Bell 6
results in overload of the remaining Beacon unit. Outages of both Beacon units results in
overload of the Bell 6 unit as well as Francis and Cedar— Northwest and Northwest—
Westside 115kV Transmission Lines.
Outages of either Beacon 230/115kV transformer and subsequent outage of the Bell —
Westside 230kV Transmission Line results in overload of the remaining Beacon unit. These
overloads are mitigated with the completion of the Garden Springs Station Project.
Outages of either Beacon 230/115kV transformer and subsequent outages of a Bell 230kV bus
tie breaker results in overload of the remaining Beacon unit. The performance issues
associated with both Beacon and Bell stations will be addressed as part of the North Spokane
and Beacon Transmission Reinforcement Projects.
Outages of either Boulder 230/115kV transformer and a subsequent outage involving for the
Beacon 115kV bus tie breaker results in overloads of the College and Walnut—Westside
115kV and Francis and Cedar— Northwest 115kV Transmission Lines. Additionally, outages of
either transformer in addition to a subsequent outage involving the Beacon 230kV bus tie
breaker results in overloads on the Bell — Northeast 115kV Transmission Line. These
overloads are mitigated with the completion of the Garden Springs Station Project.
Outages of either Westside 230/115kV transformer and subsequent outages involving Beacon
230 or 115kV buses or Ninth & Central 115kV buses results in overloads of Ross Park — Third
& Hatch and Metro — Third & Hatch 115kV Transmission Lines. These overloads are mitigated
with the completion of the Garden Springs Station Project.
Outages of either Westside 230/115kV transformer and subsequent outage for the Beacon
230kV bus tie breaker results in overload of the Bell 230/115kV Transformer 6.
Outages of both Westside 230/115kV transformers results in overload of the Metro — Third &
Hatch 115kV Transmission Line and Bell 230/115kV Transformer 6. The Metro — Third & Hatch
115kV Transmission Line overload is mitigated with the completion of Garden Springs Station
Project.
Page 51 of 89

System Assessment I 2023-2024gppendix o
5.2. Transmission Steady State Long-Term Analysis (R2.2)
Steady state analysis was performed on the transmission system models representing the
long-term planning horizon which represented the Heavy Summer scenario. If the analysis
indicates an inability of the System to meet the performance requirements, the System
Assessment shall include Corrective Action Plans addressing how the performance
requirements will be met. (TPL-001-5, R2.7)
5.2.1 .Planning Events (R3.1 )
The steady-state analysis of system normal conditions, described as the PO event,
demonstrated all BES facilities in the Avista system are within the continuous thermal ratings
and all transmission facility voltages are within the specified limits. The following sections
describe the study results from the steady state contingency analysis for contingencies
categorized as P1 — P7. Many of the performance issues identified in the near-term planning
horizon still existing in the long-term planning horizon even with expected projects represented
in the models.
5.2.1 .1 . Bell 230/115kV Transformer 6 Outage
A contingency consisting of an outage of the Bell 230/115kV Transformer 6 results in system
overloads on the remaining 115kV transmission line between Beacon and Bell stations. This
overload is a result of the stronger source with the West Plains reinforcement at Garden
Springs.
uvrllrw . I
I !py
inn" 11 �
fSIII.CfSR � _-
d
w�Sc� y r�'� • ■
1i15/i r 1 tyyp
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..r xr LfIMr
_ T.
•..�it� �+F^��� j{ nii ua w i.ir r i lur..uw""'..
ia��nc
•i..""..� • it�,"" .....
ruaeHlu �T�.iin i .,{
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»� Figure 34: Bell 230/115kV Transformer 6 in 2033 Heavy Summer
Additionally, there are multiple N-1-1 (P6) 115kV outage combinations in the north Spokane
area that result in line overloads.
As discussed in the near-term planning section, a North Spokane System Reinforcement
Planning Initiative will be developed and proposed to address the performance concerns.
5.2.1 .2. Voltage Ride-Through (R3.3.1 .1 )
Voltage ride-through analysis includes evaluating the tripping of generators where simulations
show generator bus voltages or high side of the generation step up voltages are less than
known or assumed minimum generator steady state or ride-through voltage limitations. Voltage
Page 52 of 89
=III

System Assessment 2023-2024Appendix D
ride-through limits are monitored according to PRC-024 —Attachment 2 (TPL-001-5, R3.3.1.1).
Analysis shows no instances where generator bus voltages and generation step up voltages
exceed PRC-024 limits in the long-term planning horizon.
5.2.1 .3. Cascading
Relay Loadability Tripping (R3.3.1 .2)
The tripping of transmission elements where relay loadability limits are exceeded was studied
for P1 — P7 contingency events. No performance issues were identified beyond those
observed in the near-term planning horizon. The loading of transmission elements exceeding
115% of their maximum facility ratings is provided in Table 15. With mitigation alternatives
included between outages of the listed P6 contingency events there was no further tripping of
transmission elements to simulate.
ContingencyP2
BF: A624 Rathdrum East&West 115kV
Otis Orchard- Post Falls 115kV(Beck Road Tap-Post Falls) 771.2
Post Falls- Ramsey 115kV(Post Falls- Prairie) 711.8
P6
N-1: Beacon -Northeast 115kV+T-1: Bell#6 230/115kV
Beacon -Bell#1 115kV 984.0
Table 15: Loading of Transmission Elements Exceeding 115% of
Highest Rating in Long-Term Planning Horizon (Amps)
System Instability (WR4)
Cascading is identified when a post contingency analysis of category PO - P7 events result in
steady-state facility loading that is either more than a known BES facility trip setting or exceeds
125% of the highest seasonal facility rating for the BES facility studied and when subsequently
tripped causes additional facilities to exceed 125% of the highest seasonal facility rating. Table
16 provides the filtered results of the steady state long-term contingency analysis to show only
elements exceeding 125% of the monitored seasonal rating.
P2 Contingency
BF: A506 Rathdrum 115kV, Pine Street-Rathdrum
Ramsey-Rathdrum#1 115kV Huetter-Rathdrum 1 126.1
BF: A624 Rathdrum East&West 115kV
Otis Orchard -Post Falls 115kV(Beck Road Tap-Post Falls) 145.3
Otis Orchard -Post Falls 115kV(East Farms Tap- Beck Road Tap) 155.0
Otis Orchard -Post Falls 115kV East Farms Tap-Otis Orchard 1 166.0
Post Falls-Ramsey 115kV(Post Falls-Prairie) 149.9
BUS: Rathdrum East 115kV
Ramsey-Rathdrum#1 115kV Huetter-Rathdrum 125.9
P6
N-1: Appleway-Rathdrum 115kV+ N-1: Dalton -Rathdrum 115kV
Ramsey-Rathdrum#1 115kV Huetter-Rathdrum 125.9
N-1: Beacon-Bell#1 115kV+T-1: Bell#6 230/115kV
Beacon- Northeast 115kV 164.1
Bell -Northeast 115kV(Waikiki Tap-Northeast) 132.0
Table 16: Facility Loading Exceeding 125% of
Seasonal Rating in Long-Term Planning Horizon (%)
Page 53 of 89

System Assessment 2023-2024Appendix u
Additional contingencies related to the Rathdrum Station in the long-term planning horizon
show facility loading exceeding 125% of the highest seasonal facility rating. The tripping of the
identified facilities has the same results as the Rathdrum A-624 breaker failure discussed in
the near-term planning horizon section.
With mitigation alternatives included between outages of the listed P6 contingency events in
Table 16, there was no further tripping of transmission elements to simulate.
5.2.1 .4. Unsolvea
The P1 — P7 contingency events in the long-term planning horizon were monitored for
unsolved power flow solutions. The results are provided in Table 17.
Contingency
P6
N-1: Hurricane-Walla Walla 230kV+ N-1: North Lewiston -Tucannon River 115kV . -.
N-1: North Lewiston -Tucannon River 115kV+T-1: Hatwai 500/230kV • -.
A6
N-1:Albeni Falls-Sand Creek 115kV Open @ SCR+T-1: Cabinet Gorge 230/115kV • -•
A7
N-1: Brownlee- Hells Canyon 230kV+ N-2: Flathead-Libby 230kV&Libby-Noxon 230kV • -•
N-1: North Lewiston -Tucannon River 115kV Open @ NLW+ N-2: Brownlee- Hells Canyon 230kV&
Lolo-Oxbow 230kV • -•
N-2: Brownlee- Hells Canyon 230kV&Lolo-Oxbow 230kV+ N-2: Flathead -Libby 230kV& Libby-
Noxon 230kV . -.
A3
N-1: North Lewiston -Tucannon River 115kV Open @ NLW+ G-1: Ice Harbor-One of Units 1-6 • -•
Table 17: Steady State Near-Term Unsolved Contingency Results
in Long-Term Planning Horizon
No performance issues within Avista's Planning Coordinator area were identified in addition to
those observed in the near-term planning horizon. The unsolved contingencies in adjacent
Planning Coordinator areas are caused by power flow solution methods and the application of
remedial action schemes between outages of a multiple facility contingency.
5.2.2.Extreme Events (R3.2)
The following sections describe the study results from the steady state contingency analysis
for contingencies categorized as extreme events in the long-term planning horizon.
No performance issues were identified in addition to those observed in the near-term planning
horizon.
Page 54 of 89

System Assessment 2023-2024Appendix D
5.3. Transmission Short Circuit Analysis (R2.3)
A short circuit analysis study was conducted using the transmission system models and the
Fault Analysis tool in PowerWorld Simulator. The short circuit analysis is used to determine
whether fault interrupting devices on the Avista system have interrupting capability for
expected faults. The short circuit analysis is conducted on 1-, 5-, and 10-year scenarios
assuming projects have been completed. The duties provided are for three phase faults. High
voltage circuit breakers, circuit switchers, and high voltage fuses are evaluated.
The tables below are a filtered list of interrupting devices with adjusted fault currents exceeding
90% of their interrupt ratings. Equipment with fault currents exceeding 95% of the interrupt
rating require Corrective Action Plans. If the analysis indicates an inability of the system to
meet the performance requirement, the System Assessment shall include Corrective Action
Plans addressing how the performance requirements will be met. (TPL-001-5, R2.8)
5.3.1 .High Voltage Circuit Breakers
There are no breakers identified with potential fault duties exceeding their rating. Breakers with
fault duties approaching their rating are shown in Table 18. The Beacon 115kV fault duty is
approaching the 40kA rating of the breakers. Evaluation of a 50kA or higher rating or design
alternative is recommended.
Case Case Case
[SLtation Device MN- Description (A) %Duty_ (A) %Duty (A) I%Duty_
BEA-Transformer 1
Beacon A-608 OCB 121 40 115-13.8kV 37,897 95 38,636 97 39,438 99
BEA-Transformer 2
Beacon A-614 OCB 121 40 115-13.8kV 37,897 95 38,636 97 39,438 99
Beacon A-609 OCB 121 40 BEA—F&C 115kV 36,614 92 37,364 93 38,063 95
I Beacon A-604 OCB 121 140 BEA- BLD 1 115kV 35,622 89 36,267 I 91 37,071 93
IBeacon
Beacon A-6106 OCB 121 40 BEA—9CE 2 115kV 35,286 88 36,292 91 36,447 91
Beacon A-610 OCB 121 40 BEA- Bell 1 115kV -- <90 -- <90 36,126 1 90
Beacon A-612 OCB 121 140 BEA- BLD 2 115kV -- <90 -- <90 36,378 I 91
Table 18: High Voltage Circuit Breakers Exceeding 90% Of Rating
5.3.2.Circuit Switchers
South Othello, Barker Road, Francis & Cedar, Lakeview, Sweetwater, and Lolo Stations
presently have circuit switcher devices with potential fault duties greater than their ratings.
These devices are not elements of fault blocking or protection schemes that would provide an
exemption.
South Othello, Barker Road, Francis & Cedar, and Lakeview require circuit switcher
replacements with higher capacity devices or other design alternatives.
Sweetwater and Lolo were identified as part of the Lolo Transformer Replacement project and
are scheduled to be replaced in 2024.
Clearwater, Post Street and Airway Heights Stations have circuit switcher devices with
potential fault duties greater than their ratings even utilizing protection schemes reducing the
fault duty. All will require circuit switcher replacements with higher capacity devices or other
design alternatives.
Page 55 of 89

System Assessment I 2023-2024Appendix D
The list of circuit switchers is shown in Table 19. Items noted with an asterisk (*) are based on
the utilization of the protection scheme.
DescriptionCase Case 2033
Station kV IkA
South
Othello 121 6 SOT-Transformer 1 10,194 170 10,826 180 10,247 171
Barker Road 121 20 BKR-Transformer 1 23,413 117 24,024 120 24,142 121
Francis&
Cedar 121 20 F&C-Transformer 1 20,905 105 21,057 105 21,641 108
Francis&
Cedar 121 20 F&C-Transformer 2 20,905 105 I 21,057 105 21,641 108
Lakeview 242 8 LKV-Transformer 1 8,048 101 8,097 101 8,109 102
Sweetwater 121 7 SWT-Transformer 1 6,855 98 7,191 103 7,215 103
Lolo 121 20 LOL-Transformer 3 18,237 91 I 22,061 110 21,769 109
*Clearwater 121 7 CLW-Transformer 1 7,788 111 8,370 120 8,390 120
*Clearwater 121 7 CLW-Transformer 2 7,788 1 111 8,370 120 8,390 120
*Post Street 121 7 PST-Transformer 1 7,867 112 7,915 113 8,005 114
*Post Street 121 7 PST-Transformer 2 7,867 112 7,915 113 8,005 114
*Airway
Heights 121 7 AIR-Transformer 1 -- <90 6,304 90 9,361 134
*Airway
Heights 121 7 AIR-Transformer 2 -- <90 6,304 90 9,361 134
East Colfax 121 7 ECL-Transformer 1 6,618 95 6,614 95 6,687 96
Glenrose 121 20 GLN -Transformer 1 -- <90 -- <90 18,441 92
Spokane
Industrial
Park 121 25 SIP-Transformer 3 23,255 93 23,707 95 23,858 95
Greenwood 121 6 GRN -Transformer 1 5,570 93 5,507 93 5,517 93
Colville 121 6 CLV-Transformer 1 5,680 95 5,640 94 5,650 94
Table 19: High Voltage Circuit Switchers Exceeding 90% Of Rating
5.3.3.High Voltage Fuses
The fuses listed in Table 20 presently have fault duties exceeding their rating, except for North
Moscow, which is at its limit. All provide transformer protection. Replacement with higher
capacity fuses or other design alternatives is required.
0kV kA Description (A) .1/6 D u ty Case (A) %Duty Case (A) %Duty
"el121 1.2 GAR-Transformer 1 4,033 336 4,045 336 4,043 336
121 10 PRA-Transformer 2 12,652 127 13,414 134 13,438 134
Leon
Junction 121 10 LEO-Transformer 1 10,826 108 11,004 110 10,947 109
Long Lake
13kV 121 10 L13-Transformer 1 10,615 106 1 10,687 107 1 10,658 1 107
North
Moscow 121 10 NMO-Transformer 1 10,009 100 10,036 100 10079 100
Table 20: High Voltage Fuses Exceeding 90% of Rating
Page 56 of 89

System Assessment 2023-2024pppendix o
5.4. Transmission Stability Near-Term Analysis (R2.4)
Stability analysis was performed on the transmission system models representing the near-
term planning horizon which represented peak, off-peak, and sensitivity scenarios. If the
analysis indicated an inability of the system to meet the performance requirements, the System
Assessment shall include Corrective Action Plans addressing how the performance
requirements will be met. (TPL-001-5, R2.7)
5.4.1 .Planning Events (R4.1 )
The following sections describe the study results from the stability contingency analysis for
contingencies categorized as P1 — P7.
5.4.1 .1 . Heavy Summer Scenario (R2.4.1 )
Devil's Gap Islanding Conditions
During faults causing the clearing of the Devil's Gap East bus, an island is created with the
Little Falls generation units and load radially connected to the Devil's Gap West bus. The
ability for Little Falls generation to maintain acceptable voltage and frequency within the island
depends on the load present and generation levels. Further analysis is necessary to determine
existing generation protection schemes deployed and the capabilities of the existing and
proposed controls systems installed on the Little Falls generation.
The present configuration of Devil's Gap Station has both Little Falls 115kV Transmission
Lines connected to the West bus and both Long Lake 115kV Transmission Lines connected to
the East bus, as shown in Figure 35. The configuration was initially developed to meet
historical operational concepts associated with the West of Hatwai path.
t�-9
ONGLAKT 0.00 FM
1.016 pu 47.73% w
LI7TFALL
1.016 pu MW LONGLAKW
0.0 Mvar-. MW - 0.0 War 1.016 pu
I�{�! 21 MW
1 War DEVILGPW DEV LGPE -2 War
L)N') OMW 1.016 pu 1.0 6pu F {�) 0MW
0 War0 War
8 MW `1 21 MW
-0 War A— 1 �) -2 War
0MW 0 MW
U 0 War ° {d`� 0 War
0.00 MW 33.40 MW LONGLAKE
47.90% M a 1.016 pu
Figure 35: Devil's Gap Station Configuration
Following the redevelopment of the local area operation, a re-evaluation of the Devil's Gap
configuration did not occur. Conceptually, terminating the Little Falls and Long Lake dual
transmission lines to non-contiguous points in the Devil's Gap bus structure will increase the
reliability of the plants and eliminate the potential islanding condition for loss of the East bus.
The islanding condition occurs in all cases studied.
Page 57 of 89

Is System Assessment 2023-2024Appendix o
5.4.1 .2. Light Spring Scenario (R2.4.2)
Summer Falls Out of Step
The Summer Falls generators are marginally stable if a three-phase fault occurs on the Larson
— Stratford 115kV Transmission Line near Larson. This outage leaves the Stratford area
radially fed by a 75-mile 115kV system originating out of Wenatchee as shown in Figure 36.
The resulting weak system is least stable during light load conditions, which transfers the most
generation out of the area.
ROCRYRNI "ENIAY90 ^ )6R•ORETr 1 �•�- — �I — — - s—
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-�
o•E� ,
RO(RVRNI _- •I�N�n4�••OM�.. 1■ 0 C.OG M.� ///JI �• •1 �'
j
�'wT T 6.Off r.r .Ot9P 1y`
tMUOIAf DOYMAS I I',y�� //•IW WOIM I.O]O fAYLLCIY /R / r I M9Mr —. - - '• ]Nwr J'1
' e �m,rcNRRrrwn /f LRN%
u NMI llllmlat ImU1 f m;,/'/ � r•rrr )I•rfr / P fA]1 Hw
llI1COIRRod.
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l�—<— 6TRRTNI0 0
1 If fpIIMYA CII I�� //, � `—�o.o Nwr I.•Nw�
Figure 36: 115kV System After Larson —Stratford 115kV Trip
The protection scheme on the transmission line does not presently utilize a communication
aided tripping methodology. The time delay for a Zone 2 fault has been reduced to nine cycles
relative to the typical setting of 20 cycles. The study results are shown in Figure 37.
,] M
62
0) N
0 M
0 OS , 16 ] ]e ) )6 •s 6 66 a 66 ))
p—,'Cu.6rC•66M,cM rq)i p—vC•.M•I i••�r,ri�wOR���A* 0 06 16 ] 26 ) if . •6 f 6f f f6
P .. .... -"... P—°o.d�••eu)isu•.+n„6c, P—r.ra.wNr e.••eee6,c,mt.vr usoi P—ay„wRr.6,.wNisn..nne•••q
M
M
30 Jo
-•0 w0
A JO
40 410
IN ,00
0 06 I i6 ] 26 ) )6 f 46 6 66 6 66 T i5 . • a6 ) 6e 6 66
G -...:... .-..-.... ,_i p—Wn an•MT�UM9AN,O,W A �i) i...T...•M1t'.. -f.u. . ..•
,v am•MNINeKM'ORIL,)6)u p—un.Or•6M1�SWPrn' )EIs G , p .m r.•.a�w,.a.n,!ero.1 pe`9
u am•ffM,5U1.lMU Ullf• - p ... -
Figure 37: Summer Falls Generation Response: N-1 Larson-Stratford 115kV 3P at LAR
5.4.1 .3. Light Summer High Transfer Sensitivity (R2.4.3)
The Light Summer High Transfer sensitivity scenario brings both the West of Hatwai (Path 6)
and Montana to Northwest (Path 8) near their transfer limit and simulations identified no non-
extreme event violations. The three-phase fault on the Bell — Taft 500kV line near Bell remains
Page 58 of 89

III System Assessment 2023-2024Appendix D
the most impactful contingency with tripped load of 254MW and tripped generation of 840MW.
Results are shown in Figure 38.
200
160
110
.50
.too
i 2 - 6 6 8 - 10
T,me 1 s,
-
S 0
O 50
8 .100
,SO
-zoo
.2W
-
)Wj
0 3 6 6 7 8 9 10
Times)
��sTa N-1:Bell-Taft 500 kV 3P®BELL P:\System Assessm nt\2023\Stabdety Aoalysis\2028 Light Summer WOH
. �
June 22,2023 15:03:29
Figure 38: System Response to N-1: Bell - Taft 500kV 3P at Bell
5.4.2.Extreme Events (R4.2 t
Contingencies simulating three phase faults on transmission lines with breaker failures were
the most severe contingencies and the only extreme event whose impact was not mitigated.
These events are considered to have an extremely low probability of occurrence. If the event
were to occur, it could cause local generation to lose synchronism with the system. Generation
protection schemes were not included in the simulation but are an existing component that
would aid to minimize the impact to the transmission system. The stations where breaker
failures may cause generators to lose synchronism include Beacon, Bell, Boulder, Lancaster,
Rathdrum, Noxon, and Westside. Figure 39 is an example of extreme results for a breaker
failure on Beacon R-427 during Heavy Spring conditions. Cascading was not identified for any
of the simulated contingencies, though the high transfer case did not solve for this
contingency.
;.. ntrator U X
250
200
50
.10
----------------
-
- -
o - -
-60
0 1 7 6 6 7 e 9 10
Time Isl
300
2W
.0 -f
,50 -
1wfjw00 -
W
O 0
8 . 1 '"W'iI ,T,
.00
zoo
260
30D
0 6 8 9 ,0
T me is
SF:R427 Seaton South 230 kV 3P P:\System Assessment\2023\Stability Analyst\2028 Heavy Spring
tune 23,2027 07:19:59 -
Figure 39: Breaker Failure R-427 Beacon South 230kV
Page 59 of 89

System Assessment 2023-2024pppendix D
5.4.3.Spare Equipment (R2.4.5)
Avista's spare equipment strategy for transmission facilities provides for spares for the
following equipment: 230/115kV transformers, GSU transformers, transmission UG cable, HV
circuit breakers, HV air switches, shunt reactors and shunt capacitors.
Stability analysis was performed on the transmission system models representing the near-
term planning horizon to study the impact of possible unavailability of Avista's 230/115kV
transformers and select other transformers. Category P1 and P2 planning events were
evaluated with the pre-existing condition of a transformer outage for the following:
• Beacon 1 and 2
• Bell 6 (BPA)
• Benewah
• Boulder 1 and 2
• Cabinet Gorge
• Dry Creek
• Dworshak (USACE)
• Hatwai (BPA)
• Libby (BPA)
• Lolo 1 and 2
• Moscow 230
• North Lewiston
• Pine Creek 1 and 2
• Rathdrum 1 and 2
• Saddle Mountain
• Shawnee
• Westside 1 and 2
There were no other stability issues beyond those previously identified.
5.5. Transmission Stability Long-Term (R2.5)
The Long-Term Transmission Planning Horizon stability analysis assesses the impact of
proposed additions and changes of the system model within the specified timeframe. Stability
analysis was performed on the transmission system case models representing the long-term
planning horizon. The case models used were reflective of the near-term system model with
the addition of the Garden Springs Station. The long-term analysis results mirrored those of
the near-term stability results and support the Corrective Action Plans identified in the above
near-term section. The addition of Garden Springs Station contributed no adverse impacts to
system stability.
5.6. Transmission Single Point of Failure
Single point of failure analysis for Avista's protection systems was performed in accordance
with TPL-001-5 Transmission System Performance Requirements. This analysis incorporates
both steady state and stability studies to ensure system performance meets TPL-001-5 criteria
requirements. If the analysis indicates an inability of the System to meet the performance
requirements, the System Assessment shall include Corrective Action Plans addressing how
the performance requirements will be met. The study methodology and performance criteria
used in the analysis is provided in TP-SPP-01 — Transmission System Performance.
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System Assessment 2023-2024Appendix c
5.6.1 .Initial Analysis
Initial Analysis is the first step of the single point of failure analysis process. This step is
performed by System Planning using conservative assumptions for system analysis. Analysis
includes Steady State and Stability Analysis. Results which do not meet performance criteria
are identified during Initial Analysis and are packaged for further, more detailed individual
evaluation by Avista's Relay and Protection Design Department during Final Review.
5.6.1 .1 . Steady State Analysis
The protection system single point of failure steady state analysis was conducted using the
transmission system models with the Contingency Analysis tool in PowerWorld Simulator. The
steady state analysis was used to determine whether performance criteria can be met in the
event of a single point of failure within Avista's protection and associated control and
instrumentation systems. The steady state analysis is conducted on 1-, 5-, and 10-year
scenarios assuming planned projects have been completed.
Table 21 provides the results of the steady state contingency analysis. Overload magnitudes
on each line affected are indicated in relation to the instigating contingency condition.
Contingencies at Beacon Station and at Rathdrum Station demonstrated overloads on
remaining 115kV transmission lines in their respective areas. A protection system failure at
Westside Station causes the Bell 230/115kV Transformer 6to exceed its normal facility rating.
The single point of failure contingency issues observed are less severe than the issues already
identified in the Transmission Steady State Near-Term Analysis for Heavy Summer scenario
with P2 contingencies. For the three P5 contingencies listed, mitigation of single points of
failure in the protection systems would not address the more severe issues identified for P2
contingencies.
P5
PSF: Beacon 230/115kV
College and Walnut-Westside 115kV(Fort Wright-
Westside) 100.6 104.7 103.5 112.8 107.2
Francis and Cedar- Northwest 115kV 122.3 126.8 125.8 136.5 129.7 110.6 118.6
Northwest-Westside 115kV 115.7 1 119.7 118.8 128.8 1 122.3 107.0 1 114.7
PSF: Rathdrum 230/115kV
Otis Orchard- Post Falls 115kV(Beck Road Tap-Post
Falls) 103.5
Otis Orchard- Post Falls 115kV(East Farms Tap-Beck
Road Tap) 101.9 107.2
Otis Orchard- Post Falls 115kV(East Farms Tap-Otis
Orchard) 103.9 1 103.9 103.8 112.0 108.1 109.2 117.6
Post Falls- Ramsey 115kV Post Falls- Prairie 100.5 I 106.7
PSF: Westside 230/115kV
BELL S2 (40088)-> BELL BPA(40087)CKT 6 at BELL
BPA 1 103.3 103.7 100.3
Table 21: Protection System Failure Initial Steady State Results
5.6.1 .2. Stability Analysis
The protection system single point of failure stability analysis was conducted using the
transmission system models with the Transient Stability tool in PowerWorld Simulator. The
stability analysis is used to determine whether performance criteria can be met in the event of
a single point of failure within Avista's protection systems and associated control and
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System Assessment I 2023-2024AppendiX c
instrumentation systems. The stability analysis is conducted on 1-, 5-, and 10-year scenarios
assuming planned projects have been completed. The contingencies studied included both
single line-ground (P5) and three phase (Extreme Events) faults on each 115kV and 230kV
bus in Avista's Planning Coordinator area.
The stability analysis produced no criteria violations for P5 contingencies. Twelve contingency
events cause generator out-of-step instances because of generators being disconnected from
the system. Out-of-step generators, with the corresponding instigating contingency, are listed
below. Generation loss is an acceptable consequence of any event excluding P0.
Criteria Duration Criteria Duration Criteria Duration Criteria Duration I Criteria Duration Criteria Duration
Violation orTime Violation orTime Violation or Time Violation or Time Violation orTime Violation orTime
P5
PSF:Cabinet 115kV SLG
Out of Step Generator
CABGOR1213.8kV OOS 3.4 OOS 3.4 OOS 3.4 OOS 3.4 OOS 3.4 OOS 3.4
CABGOR3413.8kV OOS 3.4 OOS 3.4 OOS 3.4 OOS 3.4 OOS 3.4 OOS 3.4
PSF:Cabinet 230kV SLG
Out of Step Generator
CABGOR1213.8kV OOS 3.4 OOS 3.4 OOS 3.4 OOS 3.4 OOS 3.4
PSF:Clearwater 115kV SLG
Out of Step Generator
CWGEN412kV OOS 3.3 1 1 1 1 1 1 OOS 3.3 OOS 3.2
PSF:Devil's Gap 115kV SLG
Out of Step Generator
LITFAL12 4kV OOS 3.3 OOS 3.4 OOS 3.4 OOS 3.4 OOS 3.3 OOS 3.4
LITFAL34 4kV OOS 3.3 OOS 3.4 OOS 3.4 OOS 3.4 OOS 3.3 OOS 3.3
LONGLKG14kV OOS 3.3 OOS 3.3 OOS 3.3 OOS 3.3 OOS 3.3 OOS 3.3
LONGLKG2 4kV OOS 3.3 OOS 3.3 OOS 3.3 OOS 3.3 OOS 3.3 OOS 3.3
LONGLKG3 4kV OOS 3.3 OOS 3.3 OOS 3.3 OOS 3.3 OOS 3.3 OOS 3.3
LONGLKG4 4kV OOS 3.3 OOS 3.3
PSF:Irvin 115kV SLG
Out of Step Generator
IEP-A 13.8kV OOS 3.4 OOS 3.4 OOS 3.4 1 OOS 3.4
IEP-B 13.8kV OOS 3.4 OOS 3.4 OOS 3.4 1 OOS 3.4
WR1.1.4.Part 1
I.E.PAPR 115kV 52.4 999
PSF:Kettle Falls 115kV SLG
Out of Step Generator
KETTLEAV 13.8kV OOS 3.4 OOS 3.4 OOS 3.4 OOS 3.4
PSF:Little Falls 115kV SLG
Out of Step Generator
LITFAL124kV OOS 3.3 OOS 3.3 OOS 3.3 OOS 3.3 OOS 3.3 OOS 3.3
LITFAL34 4kV OOS 3.3 OOS 3.3 OOS 3.3 OOS 3.3 OOS 3.3 OOS 1 3.3-1
PSF:Long Lake 115kV SLG
-Out Step Generator
LONGLKG14kV OOS 3.3 OOS 3.3 OOS 3.3 OOS 3.3 OOS 3.3 OOS 3.3
LONGLKG2 4kV OOS 3.3 OOS 3.3 OOS 3.3 OOS 3.3 OOS 3.3 OOS 3.3
LONGLKG3 4kV OOS 3.3 OOS 3.3 OOS 3.3 OOS 3.3 OOS 3.3 OOS 3.3
LONGLKG4 4kV OOS 3.3 OOS 3.3
PSF:Nine Mile 115kV SLG
Out of Step Generator
NINEM11213.8kV OOS 3.2 OOS 3.2 OOS 3.2 OOS 3.2 OOS 3.2 OOS 3.2
NINEM13413.8kV OOS 3.3 1 OOS 3.3 OOS 3.2 _
PSF:Noxon 230kV SLG
Out of Step Generator
CABGOR1213.8kV OOS 3.1 OOS 3.1
CABGOR3413.8kV OOS 3.1 OOS 3.1
NOXON1214.4kV OOS 3.1 OOS 3.1 OOS 3.1 OOS 3.1 OOS 3.1 OOS 3.1
NOXON3414.4kV OOS 3.1 OOS 3.1 OOS 3.1 OOS 3.1 OOS 3.1 OOS 3.3
PSF:Post St 115kV SLG
Out of Step Generator
MONROEA 13.8kV OOS 3.2 OOS 3.3 OOS 3.3 OOS 3.3 OOS 3.2 OOS 3.2
PSF:Stratford 115kV SLG
Out of Step Generator
L MERFA1 13.8kV OOS 3.4 OOS 3.4 OOS 3.4 OOS 3.4 OOS 3.4
SUMERFA213.8kV OOS 3.4 OOS 3.4 OOS 3.4 OOS 3.4 OOS 3.4
Table 22: Protection System Failure Initial Stability Results
Extreme events were analyzed and evaluated for cascading. If Cascading is observed for
single point failure extreme events, an assessment of possible mitigations is conducted.
Cascading criteria used for evaluation is defined as unrestrained load or generation loss or
inadequate voltage recovery defined trigger points in TP-SPP-01 - Transmission System
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System Assessment I 2023-2024Appendix o
Performance Section 2.2. The table below identifies extreme events which resulted in
cascading conditions due to unrestrained generation loss. Each bus listed is required to have a
Final Review by the Relay and Protection Design Department to determine the actual expected
clearing times.
. • .
EES-2
PSF: Beacon 115kV 3PH 3440.0 960.8 960.8 910.8 3440.5 2588.5
PSF: Beacon 230kV 3PH 4780.5 3158.9 3158.8 3158.9 4781.0 3822.5
PSF: Boulder 230kV 3PH 3438.0 1316.4 1316.4 1323.4 3430.5 2618.5
PSF: Rathdrum 230kV 3PH 3294.0 1205.8 1205.8 1177.8 3294.5 1691.5
PSF: Westside 230kV 3PH 3440.0 1 855.8 855.8 855.8 3412.5 761.8
Table 23: Protection System Failure Initial Extreme Event Unrestrained Generation loss
5.6.2. Final Review
Relay and Protection Design evaluated Initial Analysis results provided by System Planning.
Actual expected clearing times were defined by Relay and Protection Design and used in Final
Review by System Planning to determine adequate system performance. Final Review results
are documented below.
5.6.2.1 . Single Point of Failure TPL-001-5 Results
Relay and Protection Design provided actual expected clearing times for contingencies with
unrestrained generation loss, highlighted in the table below. Provided clearing times were
added to PowerWorld stability analysis Extreme Events and the updated results identified
aborted contingencies. Aborted contingencies are provided below with the associated seconds
into the simulation was aborted.
. - .
Abort Time Abort Time
EES-2
PSF: Beacon 115kV 3PH I 14.367 16.175
PSF: Beacon 230kV 3PH I 18.910 14.517
PSF: Boulder 230kV 3PH F 15.125 14.258
PSF: Rathdrum 230kV 3PH 1 14.310
Table 24: Protection System Failure Extreme Event Aborted Contingencies
The stability analysis methodology used does not emulate specific generator relaying settings.
A generic out-of-step generator protection relay can be used in the simulations to represent
typical rotating machine protection schemes. A trip setting for a deviation of 120 degrees from
a generator's initial angle has been identified as a reasonable assumption in-line with actual
generator protection settings at local generation facilities. Using the generic relay settings in
the transient analysis resulted in the tripping of generators for out-of-step conditions during the
contingencies listed in Table 25. The contingencies that cleared out-of-step generators prior to
the point of system instability, represented by PowerWorld abort time, depicted stable
contingencies. All contingencies proved solved and stable.
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System Assessment I 2023-2024gppendix o
26LSpProj 26LSpProj
Gen Relay Contingency Gen Relay Contingency
Clear Time Solution Clear Time Solution
EES-2
PSF: Beacon 115kV 3PH Under 2.Os Solved/Stable Under 2.Os Solved/Stable
PSF: Beacon 230kV 3PH Under 2.Os Solved/Stable Under 2.Os Solved/Stable
PSF: Boulder 230kV 3PH Under 2.Os I Solved/Stable I Under 2.Os Solved/Stable I
PSF: Rathdrum 230kV 3PH Under 2.Os Solved/Stable
Table 25: Protection System Failure Extreme Event Incorporating Generator Relaying
Stable contingencies that do not result in cascading conditions due to unrestrained generation
loss (TP-SPP-01 2.2 trigger point 2850MW) meet the performance criteria. The table below
has been updated with generation losses resulting after updated relay clearing times provided
by Relay and Protection Design were applied.
.P
EES-2
PSF: Beacon 115kV 3PH 3411.0 3411.5
PSF: Beacon 230kV 3PH 3387.0 2072.3 2072.3 170.8 3387.5 1829.9
PSF: Boulder 230kV 3PH 2999.1 2999.6
PSF: Rathdrum 230kV 3PH 2999.1 2505.9 I
PSF: Westside 230kV 3PH 1648.1 1648.6
Table 26 Protection System Failure Extreme Event Unrestrained Generator Loss -
Stability analysis of Avista's system show seven instances of Cascading caused by the
occurrence of extreme events. An evaluation of possible actions designed to reduce the
likelihood or mitigate the consequences and adverse impacts of the events will be conducted.
Further evaluation of performance issues related to the Beacon Station identified in the steady-
state contingency analysis and short circuit analysis will also consider the elimination of single
points of failure at Beacon Station along with improved protection schemes with faster clearing
times.
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System Assessment 2023-2024Appendix D
5.7. Distribution Multi-Year Load-Flow Analysis
Distribution system capacity was evaluated based on recent performance and projected load
growth over the next 10 years. The stations discussed below have utilization rates forecasted
to be greater than 80% within the study period. The list excludes stations that have existing
designated projects.
The load forecasting method used was a multivariate regression. The regression used heating
degree days, cooling degree days, day of the week, holidays, month, season, and daily peak
five-minute demand at the feeder as independent variables. Where consistent data was
available, three to four years of history was used to forecast a future trend. The forecast does
not include any future block-load additions.
The map shown in Figure 40 provides a geographic view of feeders exceeding performance
criteria within the 10-year planning horizon. Load growth in the North Spokane, Spokane
Valley, Coeur d'Alene, Post Falls. Moscow, and Lewiston areas will cause additional
equipment loading issues if mitigation measures are not completed.
Page 65 of 89

System Assessment 2023-2024pppendix o
—>100%
(ss� gs >90%
>80%
�r <80%
-Ilk
Figure 40: Ten-year Feeder Loading Projection Map
Page 66 of 89

System Assessment 2023-2024Appendix D
5.7.1 .Summer Scenario
5.7.1 .1 . Airwav Heights Capacity
The AIR12F1 feeder exceeds the performance criteria starting in 2026 and approaches 100%
of its facility rating in the 10-year planning horizon based on the calculated growth rate. The
Airway Heights 115/13kV Transformer 2, which serves AIR12F1, also becomes heavily loaded.
AIRWYHGT.CB.12F1 74.9 77.1 79.3 81.5 83.9 86.3 88.7 91.3 93.9 96.6 99.3
AIRWYHGT.XFMR.2 1 66.4 1 68.1 69.9 1 71.6 1 73.4 1 75.3 77.2 79.2 1 81.2 1 83.3 1 85.4
Table 27: Airway Heights Summer Loading Beyond Performance Expectations
An Airway Heights Capacity Mitigation project will be developed and proposed to address the
performance concerns.
5.7.1 .2. Glenrose Capacity
The GLN12F1 and GLN12F2 feeders have exceeded the performance criteria in operational
conditions. Some feeder transfer capacity is available and is utilized as necessary during peak
summer conditions. It is expected GLN12F2 will approach 100% of its facility rating within the
five-year planning horizon based on the calculated growth rate. The Glenrose 115/13kV
Transformer 1 is also observed to be heavily loaded.
Im'iAL. girl
GLENROSE.CB.12F1 86.5 87.6 1 88.8 1 89.9 91.1 92.3 1 93.5 94.7 I 96.0 1 97.2 ;;5GLENROSE.CB.12F2 86.4 90.2 94.2 98.3GLENROSE.XFMR.1 85.5 86.3 87.1 87.9 88.8 89.6 90.4 91.3 92.2 93.0
Table 28: Glenrose Summer Loading Beyond Performance Expectations
A Glenrose Capacity Mitigation project will be developed and proposed to address the
performance concerns.
r- 7.1 .3. Sandpoint Capacit-
The Sandpoint 115/20kV Transformers 1 and 2 are shown to exceed the performance criteria
within the five-year planning horizon based on the calculated growth rate. The two
transformers are operated in parallel with each other therefore their loading should reasonably
be equivalent.
SANDPNT.XFMR.1 1 81.8 1 83.1 84.3 85.6 86.9 88.3 89.6 91.0 92.4 93.8 95.2
SANDPNT.XFMR.2 1 76.8 1 77.7 78.6 79.5 80.4 81.3 82.3 83.2 84.2 85.2 86.2
Table 29: Sandpoint Summer Loading Beyond Performance Expectations
The Bronx Station Rebuild project in the Sandpoint area has been budgeted to be completed
within the five-year horizon.
5.7.1 .4. Lewiston Capacit,.
Several feeders and transformers in the Lewiston, Idaho area are shown to exceed the
performance criteria within the five-year planning horizon based on the calculated growth rate.
Some equipment has exceeded the performance criteria in operational conditions. The
projected growth rate is driven by new housing developments in the area
10TH STW.CB.1254 1 86.6 1 90.6 1 94.7 1 99.0 1 103.5 1 108.2 1 113.1 1 118.3 1 123.7 129.3
25 10TH STW.CB.17 76.0 78.2 80.5 82.8 85.1 87.6 90.1 92.7 95.3 98.1
Page 67 of 89 Em�

System Assessment I 2023-2024gppendix D
10TH STW.XFMR.1 66.5 68.6 70.8 73.1 75.4 77.8 80.3 82.9 85.5 88.3 91.1
10TH STW.XFMR.2 83.9 86.0 88.2 90.4 92.6 95.0 97.3 99.8 102.3 104.8
LOLO.CB.1359 83.1 83.1 83.1 83.1 83.1 83.1 83.1 83.1 83.1 83.1 83.1
LOLO.XFMR.3 82.8 84.2 85.5 86.9 88.3 89.7 91.2 92.6 94.1 95.7 97.2
NLEWISTN.XFMR.115 13 1 64.2 65.6 67.1 68.6 70.1 71.7 73.3 74.9 76.6 78.3 80.0
SLEWISTN.CB.1358 59.5 61.7 63.9 66.1 68.5 71.0 73.5 76.1 78.8 81.6 84.6
SLEWISTN.XFMR.1 84.1 84.1 84.1 84.1 84.1 84.1 84.1 84.1 84.1 84.1 ` 84.1
Table 30: Lewiston Area Summer Loading Beyond Performance Expectations
A Lewiston Capacity Mitigation project will be developed and proposed to address the
performance concerns.
5.7.1 .5. Liberty L_aKe capacity
The LIB12F1 feeder exceeds the performance criteria starting in 2028 and approaches 100%
of its facility rating in the 10-year planning horizon based on the calculated growth rate. The
LIB12F3 and Liberty Lake 115/13kV Transformer 2, which serves LIB12F3 and LIB12F4, also
exceed the performance criteria. Little to no growth is expected on LIB12F3.
LIBRTYLK.CB.12F1 J 63.7 67.0 70.5 74.1 77.9 81.9 86.1 90.6 95.2 100.2
LIBRTYLK.CB.12F3 ,I 83.3 83.3 83.3 83.3 83.3 83.3 83.3 83.3 83.3 83.3 83.3
LIBRTYLK.XFMR.2 ` 66.0 68.4 70.9 73.5 76.2 79.0 81.9 1 85.0 1 88.1 1 91.3 94.7
Table 31: Liberty Lake Summer Loading Beyond Performance Expectations
A Liberty Lake Capacity Mitigation project will be developed and proposed to address the
performance concerns.
5.7.1 .6. Moscow uapaclLy
Moscow City Station is a 115kV to 13.8kV distribution station located in the south part of
Moscow, ID. Moscow City 115/13kV Transformer 1 is a 20MVA transformer with three feeders,
serving approximately 6900 service points. Moscow City 115/13kV Transformer 2 is a 20MVA
transformer with two feeders, serving approximately 4000 service points. The station is radially
fed by the Moscow City - South Pullman 115kV Transmission Line with an alternate feed from
the North Lewiston - Moscow City 115kV Transmission Line.
The Moscow area is projected to experience load growth over the next 10 years mostly with
new housing developments and new local manufacturing facilities. The Moscow City 115/13kV
Transformer 1 has exceeded the performance criteria in operational conditions. M15512 and
M15514 feeders are shown to exceed the performance criteria within the 10-year planning
horizon based on the calculated growth rate.
030
MOSCOW.CB.512 I 78.0 1 79.2 1 80.5 81.7 83.0 84.3 1 85.7 1 87.0 1 88.4 89.8 91.2
MOSCOW.CB.514 67.2 1 68.7 1 70.2 71.8 73.4 75.1 1 76.7 1 78.4 1 80.2 82.0 83.8
MOSCOW.XFMR.1 86.8 1 87.3 1 87.8 88.2 88.7 89.2 1 89.7 1 90.2 1 90.7 91.2 91.8
Table 32: Moscow City Summer Loading Beyond Performance Expectations
A Moscow Capacity Mitigation project will be developed and proposed to address the
performance concerns.
5.7.1 .7. North Spokane Capacity
Several feeders and transformers in the North Spokane area are shown to exceed the
performance criteria within the five-year planning horizon based on the calculated growth rate.
Page 68 of 89

System Assessment 2023-2024Appendix D
Some equipment has exceeded the performance criteria in operational conditions. The
projected growth rate is driven by new housing developments, apartment complexes, general
commercial, and light industrial expansion in the area.
BEACON.CB.12F2 77.2 78.7 80.1 81.6 83.1 84.6 86.2 87.8 89.4 91.1 92.8
COLBERT.CB.12F1 68.6 70.2 71.9 73.6 75.4 77.2 79.1 81.0 83.0 85.0 87.0
COLBERT.XFMR.BPAT_
COLBERT 84.8 85.8 86.9 88.0 89.1 90.2 91.4 92.5 93.6 94.8 96.0
FRAN CDR.CB.12F2 82.9 82.9 82.9 82.9 82.9 82.9 82.9 82.9 82.9 82.9 82.9
FRAN_CDR.CB.12F4 75.3 76.2 77.2 1 78.1 79.1 80.1 81.1 82.1 83.1 84.2 85.2
FRAN CDR.XFMR.2 I 79.1 80.0 81.0 I 82.1 83.1 84.1 1 85.2 86.2 87.3 88.4 1 89.5
INDIANTR.CB.12F1 78.6 79.5 I 80.3 81.2 82.0 82.9 I 83.8 84.7 85.6 86.5 87.4
INDIANTR.XFMR.1 73.8 74.9 75.9 77.0 78.0 79.1 I 80.2 81.3 82.5 83.6 84.8
LYON_STD.CB.12F2 73.2 74.9 76.6 78.3 80.0 81.8 83.7 85.6 87.5 89.5 91.5
LYON STD.CB.12F3 68.5 70.0 71.6 73.2 74.9 76.6 78.3 80.0 81.8 83.7 85.6
LYON_STD.CB.12F4 67.7 70.4 73.1 76.0 79.0 82.1 85.4 88.7 92.2 95.8 99.6
LYON STD.XFMR.1 I 74.5 76.1 77.9 I 79.6 81.4 83.2 85.1 87.0 89.0 91.0 93.0
MEAD.CB.12F1 64.9 66.6 68.3 1 70.1 71.9 73.7 75.6 77.6 79.6 81.7 83.8
NRTHEAST.CB.12F1 67.1 69.6 72.1 1 74.7 77.5 80.3 I 83.2 86.3 89.4 92.7 96.0
NRTHEAST.CB.12F2 71.5 73.0 74.6 76.2 77.8 79.5 81.2 82.9 84.7 86.5 88.3
NRTHEAST.CB.12F3 49.7 53.0 56.6 60.4 64.4 68.8 73.4 78.3 83.5 89.1 95.1
NRTHEAST.CB.12F4 69.1 73.0 77.0 81.2 85.7 90.4 95.4 100.7 106.2 112.1
WAIKIKI.CB.12F3 81.6 81.6 81.6 81.6 81.6 81.6 81.6 81.6 81.6 81.6 81.6
WAIKIKI.CB.12F4 75.4 76.5 77.7 78.9 80.1 81.3 82.5 83.8 85.0 86.3 87.6
WAIKIKI.XFMR.115 13_1 1 85.3 85.3 85.3 85.3 85.3 85.3 85.3 85.3 85.3 85.3 85.3
WAIKIKI.XFMR.115_13_2 1 84.5 84.5 1 84.5 84.5 84.5 84.5 84.5 84.5 84.5 84.5 84.5
Table 33: North Spokane Area Summer Loading Beyond Performance Expectations
A North Spokane Capacity Mitigation project has been developed to address the performance
concerns. The project includes several sub-projects, some of which have already been
budgeted, with the remainder to be proposed for prioritization.
5.7.1 .8. Rathdrum capacity
Rathdrum Station is a 115kV to 13.8kV distribution station located southeast of Rathdrum at
the intersection of North Meyer and Boekel Roads. It has two 20MVA transformers with two
Avista feeders and one Kootenai Electric feeder. The station serves approximately 4800 Avista
service points and is fed from the Rathdrum Station's 115kV East and West buses. The station
includes a 230kV source and five 115kV transmission lines with feeder ties to Huetter and
Idaho Road Stations.
The Rathdrum Prairie is projected to experience load growth over the next 10 to 20 years, with
the City of Post Falls anticipating a doubling of its population in that timeframe. The
undeveloped areas are often considered for commercial and industrial growth.
Present feeder loading is reasonable, but the loading is expected to increase significantly
through the next 10 years, with the expectation the RAT231 and RAT233 feeder will exceed
the performance criteria in 2027 and 2026 and reaches 100% of their facility ratings in the 10-
year planning horizon based on the calculated growth rate.
RATHDRUM.CB.231 1 69.0 1 71.8 74.6 1 77.6 1 80.6 83.8 87.2 90.6 94.2 98.0
RATHDRUM.CB.233 1 73.2 1 76.1 1 79.1 1 82.3 1 85.5 1 88.9 1 92.4 1 96.1 1 99.9
Table 34: Rathdrum Summer Loading Beyond Performance Expectations
A Rathdrum Capacity Mitigation project will be developed and proposed to address the
performance concerns.
Page 69 of 89

System Assessment 2023-2024Appendix D
5.7.2.Winter Scenario
5.7.2.1 . Orin Capacity
Orin Station is a 115kV to 13.8kV distribution station located a couple miles south of Colville on
Hwy 395. It has a single 10MVA transformers feeding three Avista feeders. The station serves
approximately 2200 Avista service points and is radially fed by a tap off the Addy-Kettle Falls
115kV Transmission Line.
The Orin area is projected to experience moderate load growth over the next 10 years. The
ORI 115/13kV Transformer 1 and OR112F3 have exceeded the performance criteria in
operational conditions.
ORIN.XFMR.1 107.9 111.0 114.7 118.4 122.3 126.5 130.7 134.6 139.6 143.6 149.0
ORIN.CB.12F3 107.8 110.7 114.4 118.3 122.2 126.3 130.6 134.2 139.4 143.1 148.6
Table 35: Orin Winter Loading Beyond Performance Expectations
An Orin Capacity Mitigation project will need to be developed to address the performance
concerns.
5.7.2.2. INIUSl:UVV %_,dpdUILy
Summer capacity concerns and project proposals were discussed above in Section 5.7.1.7
Moscow Capacity. This project will also address winter performance concerns.
MOSCOW.XFMR.1 1 92.6 1 93.4 1 94.6 I5.6 96.4 97.2 98.5 5
I
MOSCOW.CB.512 74.3 75.5 77.2 78.5 9 81.1 82.8 84.2 87.0 88.4
88.7 90.9 93.5 95.7MOSCOW.CB.514 74.5 76.3 78.1 Table 36: Moscow City Winter Loading Beyond Performance Expectations
5.7.2.3. Wilbur Cagacit'
Wilbur Station is a 115kV to 13.8kV distribution station located north of the city of Wilbur,
Washington. Wilbur 115/13kV Transformer 1 is a 7.51VIVA transformer with two feeders,
serving approximately 1300 service points. This station serves the cities of Wilbur, Creston,
and Almira. The station is radially fed by a tap off the BPA Bell-Creston 1 115kV Transmission
Line.
The Wilbur area is projected to experience load growth over the next 10 years, consisting
mostly of new housing developments and local manufacturing facilities. The Wilbur 115/13kV
Transformer 1 has exceeded the performance criteria in operational conditions and
approaches 100% of its facility rating in the 10-year planning horizon based on the calculated
growth rate.
WILBUR.XFMR.1 I 91.1 1 92.3 1 93.6 1 95.0 96.5 1 97.9 99.2 102.2 i_ 105.4
Table 37: Wilbur Winter Loading Beyond Performance Expectations
A Wilbur Capacity Mitigation project will need to be developed to address the performance
concerns.
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System Assessment 2023-2024Appendix D
5.7.2.4. Sandpoint Capacity
Sandpoint Station is a 115kV to 20kV distribution station located on the west side of
Sandpoint, ID at the intersection of Pine Street and Lincoln Avenue. It has three 12.5MVA
transformers with four Avista feeders. Sandpoint Transformer 1 and Transformer 2 are
paralleled and feed three of the four feeders. The station serves approximately 8000 service
points. The station is fed by the Bronx-Sand Creek 115kV Transmission Line.
The Sandpoint area is projected to experience load growth over the next 10 years mostly with
new housing developments. Sandpoint 115/13kV Transformer 1 and Transformer 2 have
exceeded the performance criteria in operational conditions and approach 100% of its facility
rating in the 10-year planning horizon based on the calculated growth rate. SPT4S21, which
serves the rural area west of Sandpoint is expected to have the most growth in the area and
exceeds performance criteria in operational conditions in the 10-year planning horizon.
SANDPNT.XFMR.1 90.0 92.3 94.6 97.2 99.7
SANDPNT.XFMR.2 90.0 92.3 94.6 97.2 99.7
SANDPNT.CB.4S21 47.5 1 50.3 1 53.0 1 56.1 1 59.3 1 62.2 1 65.6 1 69.4 1 73.4 1 77.5 81.9
Table 38: Sandpoint Winter Loading Beyond Performance Expectations
A Sandpoint Capacity Mitigation project is being developed to address the performance
concerns. The project tentatively includes the addition of a new station (Bronx Station) and two
feeders.
5.7.2.5. Valley Capacity
Valley Station is a 11 RV to 13.8kV distribution station located south of Valley, Washington.
Valley 115/13kV Transformer 1 is a 7.5MVA transformer with three feeders, serving
approximately 2400 service points. The station is fed by the Addy-Devil's Gap 11 RV
Transmission Line.
Valley 115/13kV Transformer and VAL12F1 feeder have exceeded the performance criteria in
operational conditions.
Valle XFMR
VAL12F 1 1 85.911 85.911 85.911 85.911 85.911 85.911 85.911 85.911 85.911 85.911 85.91
Table 39: Valley Winter Loading Beyond Performance Expectations
5.8. Distribution Contingency Analysis
The methodology to study distribution system performance during contingency events is under
development. Contingency events intended to be studied include outages of feeders and
station transformers.
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System Assessment 2023-2024Appendix D
5.9. Distribution Auto-Transfer Analysis
Analysis of feeder capacity during auto-transfer switching was performed based on peak
summer loading. AT switches were modeled to toggle to their alternate source for evaluation of
sufficient capacity on the adjacent feeder to pick up the load. Analysis results show `Normal'
and `Switched' configuration loading values per feeder and ATS in Table 40.
T_ Loading Loading
FeederID .
Switch N/C Switch Feeder Feeder Feeder Switch-N/C Switch ID- Switch Switch Switch -N/O Switch ID- Switch Switch Switch Switch Feeder Feeder Feeder
Feeder Feeder Case (M) (Amps) M Feeder Feeder (M) (A-ps) (%)
CDA124 ZC912AT-1 Normal 9,405 412.3 65.1 APW113 ZC912AT-2 6,507 333.6 65.1
CDA124 ZC912AT-1 Switched 8,708 381.4 60.6 APW113 ZC912AT-2 1 7,185 362.9 70.9
TEN1253 ZL1410E-2 Normal 8,608 407.7 70.7 TEN1255 ZL1410E-1 1 8,254 405.5 1 67.5 I
TEN1253 ZL1410E-2 Switched 6,796 324.4 53.2 TEN1255 ZL1410E-1 10,099 488.3 I 81.2
FWT12F3 Z554AT-1 Normal I 5,767 265.0 43.2 NW12F2 I Z554AT-2 6,115 275.0 53.7
FWT12F3 Z554AT-1 Switched I 2,396 111.3 27.1 NW12F2 I Z554AT-2 10,265 483.8 94.5
HOL1205 ZL1421E-1 Normal 3,292 157.5 1 36.5 SLW1316 ZL1421E-2 5,965 282.2 55.1
HOL1205 ZL1421E-1 Switched 2,567 121.7 28.2 SLW1316 ZL1421E-2 6,730 321.5 62.8
3HT12F7 Z614AT-1 Normal 9,521 429.4 64.6 3HT12F1 Z614AT-2 4,665 208.1 40.6 I
3HT12F7 Z614AT-1 Switched 4,684 221.7 62.7 3HT12F1 Z614AT-2 9,483 422.0 I 82.4
3HT12F1 Z1311AT-1 Normal I 4,665 208.1 33.7 3HT12F7 I Z1311AT-2 9,521 429.4 77.2
3HT12F1 Z1311AT-1 Switched I 3,771 167.3 31.0 3HT12F7 I Z1311AT-2 10,440 472.8 85.0
C&W12F4 Z365AT-1 Normal 6,279 314.4 63.7 3HT12F6 Z365AT-2 6,941 319.7 62.4
C&W12F4 Z365AT-1 Switched 3,408 180.7 35.0 3HT12F6 Z365AT-2 9,959 458.7 89.6
3HT12F5 688AT-3 Normal 8,363 376.1 59.1 3HT12F1 688AT-2 4,665 208.1 40.6 I
3HT12F5 688AT-3 Switched 8,111 365.5 58.4 3HT12F1 688AT-2 4,907 218.2 I 42.6
AIR12F3 Z669AT-1 Normal I 4,206 224.8 41.5 FLN12F4 I Z669AT-2 I 1,745 79.6 13.2
AIR12F3 Z669AT-1 Switched 2,086 120.0 19.8 FLN12F4 Z669AT-2 4,206 184.0 31.8
Table 40: Feeder Loading Under Normal and Switched ATS States
Analysis results show no feeders exceeding the 95% continuous loading performance criteria
defined in DP-SPP-02- Distribution System Performance V5. Evaluation of Pullman area
ATS's is under development.
5.10.Distribution Short Circuit Analysis
Evaluation of fault interrupting device's ability to detect and isolate faults was performed using
a short circuit analysis as described in DP-SPP-02- Distribution System Performance V5. Five
specific performance criteria were evaluated:
• Fault current shall be less than 95% of the interrupting equipment capability.
• Fault current shall be less than 7100A.
• Fault current shall be greater than two times the fuse rating.
• Fault current shall be greater than four times the maximum load.
• Fuse rating shall be greater than two times the maximum load.
Page 72 of 89

System Assessment 2023-2024Appendix D
5.10.1 .Interrupting Rating
Fault current was found to exceed the performance criteria for four distribution devices as
shown in Table 41. Each device listed has calculated expected fault current more than their
designed ratings. Faults downstream of the devices cannot be expected to be interrupted.
EquipmentEquipment .
Type Location Ability(Amps) Fault Fault
Recloser C909R
CDA121 Midline 2000 3086 2296 154%
SPI12F2 Recloser E170 Midline 1 2000 3259 3281 164%
SLW1358 Breaker Station 2000 6425 5560 328%
SLW1348 ` Breaker Station _`_ 2000 6425 6560 328%
Table 41: Distribution Interrupting Devices Exceeding 95% of Rating
The existing Safely Interrupting Faults project, previously developed to address transmission
system performance deficiencies, will be evaluated to expand scope such that the listed
distribution devices in Table 41 will be appropriately mitigated.
5.10.2.Maximum Available Fault Current
The feeders listed in Table 42 have maximum available fault current exceeding 7100A.
9CE12F4 7212 7291
9CE12F5 7213 7292
9CE12F6 7212 7291
F&C12F4 7005 7104
FLN12F4 7225 7307
LMR1530 7511 7631
LMR1531 7511 7632
LMR1532 7510 7629
PST12F2 5849 7678
SPU124 7092 8402
SUN12F4 7167 7244
SUN12F5 7168 7244
SUN12F6 7165 7239
Table 42: Feeder Maximum Available Fault Current
Corrective Action Plans will not be developed to mitigate the feeders listed in Table 42 from
exceeding the criteria. Further evaluation of the criteria and its intended application will be
performed. Establishing a maximum available fault current is typically done as a proxy for
evaluated protective device coordination. It is not anticipated to have protective device
coordination issues on the identified feeders.
5.10.3.Fuse to Fault Ratio
Calculated fault current was compared to fuse ratings for evaluation of correctly sized fuses to
adequately see downstream faults. Across all Avista's distribution system, 288 fuses were
identified to be sized too large. The typical location of the identified fuses is on feeders serving
rural areas where the fault current becomes relatively low.
The complete list of fuses not meeting the 2:1 ratio performance criterion will be provided to
Distribution Engineering for further evaluation. Evaluation may include confirming the actual
Page 73 of 89

System Assessment 2023-2024pppendix D
installed fuse sizes are correctly listed in Avista's databases and, if appropriate, determine if
the fuses can be replaced with smaller rated fuses.
5.10.4.Fuse to Load Ratio
Fuse ratings were compared to the maximum load for evaluation if a fuse could interrupt
service to customers during peak loading scenarios. Across Avista's distribution system, 418
fuses were identified to be sized too small for the load connected downstream.
The complete list of fuses not meeting the performance criterion will be provided to Distribution
Engineering for further evaluation. Evaluation may include confirming the actual installed fuse
sizes are correctly listed in Avista's databases, reviewing load allocation assumptions, and if
appropriate, determine if the fuses can be replaced with larger rated fuses.
5.10.5.Fault Current to Load Ratio
Calculated fault current was compared to the maximum load for evaluation if a fuse could be
properly selected to meet both the fault to fuse rating and the fuse to load ratio performance
criteria. The line segments with fuses listed in Table 43 are those with a fault to load ratio of
less than four. The listed fuses are therefore assumed to not have the ability to be properly
sized as either the fault current is too low, or the load is too high.
Summer Winter
Fault to Fault to
Min Max Load Min Max .. .
Fault Load Ratio Fault Load Ratio Existing Fuse Size
BLU321
389:1539652:0 380 126.4 3.0 1 380 185.9 2.0 S&C Positrol T Speed 80
389:4280629:0 I 237 76.4 3.1 237 113.4 2.1 S&C Positrol T Speed 65 I
389:3265172:2 163 50.7 3.2 163 74.0 2.2 S&C Positrol T Speed 50
394:3563517:1 I 212 64.1 3.3 212 94.2 2.2 I S&C Positrol T Speed 50 I
389:4770838:0 150 44.0 I 3.4 150 64.2 2.3 S&C Positrol T Speed 30
1 389:839578:0 179 51.2 I 3.5 179 74.7 2.4 S&C Positrol T Speed 40
389:4280630:0 164 52.4 3.1 S&C Positrol T Speed 40
r
394:2670165:0 151 44.8 3.4 S&C Positrol T Speed 30
401:68835:1 132 36.7 3.6 S&C Positrol T Speed 40I
3 9::1692631:12 I 265 I 77.9 I 3.4 265 124.4 2.1 I S&C Positrol T Speed 50 I
389:4415813:0 1 359 137.7 2.6 S&C Positrol T Speed 65
389:3411553:1 449 142.6 3.2 S&C Positrol T Speed 80
C 3 9::3447682:1 I 109 81.1 1.3 1 109 159.8 0.7 I S&C Positrol T Speed 65 I
389:741889:1 I 67 40.1 1.7 1 67 87.4 0.8 I S&C Positrol T Speed 50 I
389:2154437:15 57 30.2 1.9 1 57 67.5 0.8 S&C Positrol T Speed 40
389:1613574:5 212 89.0 I 2.4 1 212 211.1 1.0 S&C Positrol T Speed 80
389:2170054:0 67 37.3 1.8 67 57.3 1.2 S&C Positrol T Speed 50
389:955447:5 I 62 34.0 1.8 62 52.4 1.2 S&C Positrol T Speed 30 I
394:437664:1 297-T 135.1 2.2 297 1 249.6 1.2 S&C Positrol T Speed 100
394:445022:0 50 16.2 3.1 50 36.3 1.4 S&C Positrol T Speed 10
394:435536:1 I 51 15.9 I 3.2 51 36.3 1.4 S&C Positrol T Speed 15 I
389:742632:1 61 26.3 2.3 61 40.5 1.5 S&C Positrol T Speed 25
389:742901:0 63 22.3 2.8 63 34.7 1.8 S&C Positrol T Speed 20
389:742970:2 I 117 45.3 2.6 S&C Positrol T Speed 15 I
389:767601:29 169 1 61.9 2.7 S&C Positrol T Speed 20
394:582970:1 I I 158 56.8 2.8 S&C Positrol T Speed 25
389:741916:0 1 I 56 18.3 3.0 I S&C Positrol T Speed 15 I
389:955251:28 1 I 53 18.0 3.0 S&C Positrol T Speed 15
389:3083707:6 1 49 15.9 3.1 S&C Positrol T Speed 6
389:1257273:0 I 57 17.4 3.3 S&C Positrol T Speed 15
389:2993690:0 55 16.0 3.5 S&C Positrol T Speed 10
389:74201674 61 16.7 3.6 S&C Positrol T Speed 12
Page 74 of 89 Na

System Assessment I 2023-2024Appendix D
Summer Winter
Fault to Fault to
Min Max Load Min Max .. .
Fault Load Ratio Fault Load Ratio Existing Fuse Size
389:742549:1 1 239 65.2 3.7 S&C Positrol T Speed 40
389:955204:5 106 28.0 3.8 S&C Positrol T Speed 40
CHW12F4
389:742768:4 I 178 69.3 2.6 S&C Positrol T Speed 40 I
394:439931:0 136 50.6 2.7 S&C Positrol T Speed 25
394:438966:2 I 138 52.0 2.7 I
394:3570429:1 184 57.9 3.2 S&C Positrol T Speed 40
394:783424:1 159 43.1 3.7 S&C Positrol T Speed 30
394:2269238:0 I 311 80.5 3.9 S&C Positrol T Speed 50 I
389:742956:2 91 23.5 3.9 S&C Positrol T Speed 15
389:3390773:0 586 145.9 4.0 S&C Positrol T Speed 80
CKF711 I I
389:2669074:2 308 93.6 3.3 S&C Positrol T Speed 100
389:2633810:0 269 77.1 3.5 S&C Positrol T Speed 50
389:3097044:0 I 284 79.5 3.6 S&C Positrol T Speed 65 I
FOR12F1
389:4547122:0 255 I 67.5 1 3.8 255 119.3 2.1 S&C Positrol T Speed 100
389:2905939:2 I 1 84 27.9 3.0 S&C Positrol T Speed 25 I
389:3591044:0 1 158 47.4 3.3 S&C Positrol T Speed 50
FOR12F2
389:4774089:0 148 49.9 3.0 S&C Positrol T Speed 50
GAR461
389:533043:0 I 126 34.6 3.6 126 34.6 3.6 S&C Positrol T Speed 651
GIF12F1
389:889011:2 I 65 35.6 1.8 65 66.1 1.0 S&C Positrol T Speed 30 I
389:1038656:1 60 29.7 2.0 60 55.2 1.1 S&C Positrol T Speed 25
389:2932987:0 57 26.2 2.2 57 48.8 1.2 S&C Positrol T Speed 20
401:71712:0 I 108 32.5 3.3 108 62 1.7 S&C Positrol T Speed 30 I
394:2778985:1 328 89.6 3.7 328 170 1.9 S&C Positrol T Speed 100
389:888266:2 I I 52 22.4 2.3 S&C Positrol T Speed 15 I
394:529990:1 76 33 2.3 S&C Positrol T Speed 25
394:530667:1 73 28.7 2.6 S&C Positrol T Speed 20
389:2932985:0 57 19.6 2.9 S&C Positrol T Speed 20
389:888409:2 I 52 14 3.7 S&C Positrol T Speed 10 I
GIF34F1
394:632567:18 I 53 45.8 1.2 53 76.4 0.7 S&C Positrol T Speed 20 I
389:2147347:2 95 56.2 1.7 95 93.7 1.0 S&C Positrol T Speed 30
389:1020420:2 175 62.1 2.8 175 103.5 1.7 S&C Positrol T Speed 40
389:888592:1 272 85.5 3.2 272 142.5 1.9 S&C Positrol T Speed 50-1
389:1043441:0 I 200 64.2 3.1 1 S&C Positrol T Speed 80 I
389:3881567:0 252 69.3 3.6 S&C Positrol T Speed 40
389:1010495:5 I 167 42 4.0 S&C Positrol T Speed 40 I
GIF34F2
389:3215051:0 153 72.3 2.1 S&C Positrol T Speed 40
394:2884848:1 172 72.1 2.4 S&C Positrol T Speed 50 1
389:3130310:10 I 314 79.6 3.9 S&C Positrol T Speed 65 I
GRA12F2
389:1416365:0 i
313 88.1 3.6 313 93.2 3.4 S&C Positrol T Speed 50 I
KET12F2
389:1356506:0 1 146 40.8 3.6 146 46.6 3.1 S&C Positrol T Speed 65
LAT421
389:595357:3 I 448 178.8 2.5 S&C Positrol T S eed 100 I
389:3872787:1 310 79.5 3.9 S&C Positrol T Speed 80
MLN12F2
389:71182:0 I 625 164.9 3.8 S&C Positrol T Speed 100 I
OGA611
389:4044018:2 133 37.7 3.5 133 37.3 3.6 S&C Positrol T Speed 50
SAG741
389:2422312:32 I 336 103.0 3.3 336 119 1 2.8 S&C Positrol T Speed 65 I
389:1175353:0 I 257 80.4 3.2 257 92.7 2.8 1 S&C Positrol T S eed 50
389:869242:1 159 45.1 3.5 159 52.6 3.0 1 S&C Positrol T Speed 30
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System Assessment I 2023-2024Appendix D
Summer Winter
Fault to Fault to
Min Max Load Min Max .. .
Fault Load Ratio Fault Load Ratio Existing Fuse Size
394:3076647:0 153 38.0 4.0 153 44.4 3.5 S&C Positrol T Speed 25
SLK12F2
394:3413044:1 473 127.1 3.7 473 132.7 3.6 S&C Positrol T Speed 80
394:3413037:1 I 490 127.1 3.9 490 132.7 3.7 1 S&C Positrol T Speed 100 I
S 389:3729587:2 I 178 59.8 3.0 I S&C Positrol T Speed 65 I
SP112F2
389:945847:1 115 33.6 3.4 115 75.9 1.5 S&C Positrol T Speed 30
389:696602:5 I 72 19.8 3.6 72 45.1 1.6 S&C Positrol T Speed 25 I
389:1188115:0 193 79.5 2.4 S&C Positrol T Speed 40
394:2857330:1 I 298 101.9 2.9 S&C Positrol T Speed 50 I
STM633
394:2430344:1 90 22.4 1 4.0 1 90 23 3.9 S&C Positrol T Speed 25
SUN12F4
401:25646:0 I 433 119.7 1 3.6 1 433 126.3 3.4 S&C Positrol T Speed 140 I
SUN12F5
389:292836:5 I 630 184.3 3.4 S&C Positrol T Speed 100 I
WAL543 1
389:1072307:2 180 60.3 3.0 1 180 60.3 3.0 S&C Positrol T Speed 65
389:797745:21 127 38.1 3.3 127 38.1 3.3 S&C Positrol T Speed 50 1
389:4735971:6 54 13.3 4.0 54 13.3 4.0 S&C Positrol T Speed 20
COMM
389:2416481:2 I 487 1 175.6 2.8 1 S&C Positrol T Speed 140
Table 43: Fault Current to Load Ratio
Corrective Action Plans will not be developed to mitigate each fuse listed in Table 43. In some
instances, the results can be used to provide additional justification of existing projects such as
the Carlin Bay project. Further evaluation of the study methodology and assumptions will be
performed to determine the validity of the results.
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System Assessment 2023-2024Appendix c
5.11 .NERC Compliance Summary
5.11 .1 .Instability Corrective Action Plans (FAC-014-3, R7)
The following Corrective Action Plans have been developed to address system instability
identified through technical analysis in the Near-Term Planning Horizon.
. - of System
CAP Instability Criteria Contingency Condition
Otis Orchard -
Coeur d'Alene BF: A624 Rathdrum Post Falls 115kV
Transmission Steady state 125% of the highest East and West Heavy Summer Post Falls-
Reinforcement cascading seasonal facility rating 115kV Heavy Winter Ramsey 115kV
Table 44: Corrective Action Plans Mitigating Instability
5.11 .2.Facilities Contributing to Cascading, Instability, and Uncontrolled
Separation (FAC-014-3, R8)
The following list of facilities comprise of a planning event contingency that would cause
instability, Cascading, or uncontrolled separation that adversely impacts the reliability of the
BES as identified through technical analysis in the Near-Term Planning Horizon.
Planning Event Facility Reference
Rathdrum bus tie breaker A624
A624 Rathdrum East and West Rathdrum East 115kV bus
115kV Rathdrum West 115kV bus Section 5.1.1.6
Table 45: Facilities Contributing to Instability, Cascading, or Uncontrolled Separation
Page 77 of 89

System Assessment 2023-2024Appendix n
5.11 .3.WECC Path Elements
The following list of Avista owned facilities are elements within a WECC rated path.
A ista Facility location WECC Path
Coulee (BPA)to Westside 230kV transmission tine 6—West of Hatwai
Dry Creek to Talbot PacifiCor 230kV transmission line 6—West of Hatwai
Lolo to Oxbow (IPC) 230kV transmission line 14— Idaho-Northwest
Burke to Thompson Falls#1 NWECO) 11 RV transmission line 8— Montana-Northwest
Burke to Thompson Falls#2 (NWECO) 11 RV transmission line 8— Montana-Northwest
Devil's Gap to Stratford 11 RV transmission line 6—West of Hatwai
Lind to Warden 11 RV transmission line 6—West of Hatwai
North Lewiston to Tucannon River (BPA) 11 RV transmission line 6—West of Hatwai
A437 Circuit Breaker Burke Station 8— Montana-Northwest
A438 Circuit Breaker Burke Station 8— Montana-Northwest
A520 Circuit Breaker Devil's Gap Station 6—West of Hatwai
R617 Circuit Breaker Dry Creek Station 6—West of Hatwai
R517 Circuit Breaker Dry Creek Station 6—West of Hatwai
A36 Circuit Breaker Lind Station 6—West of Hatwai
R487 Circuit Breaker Lolo Station 14— Idaho-Northwest
R387 Circuit Breaker Lolo Station 14— Idaho-Northwest
A586 Circuit Breaker North Lewiston Station 6—West of Hatwai
A1014 Circuit Breaker Stratford Station 6—West of Hatwai
A253 Circuit Breaker Warden Station 6—West of Hatwai
R634 Circuit Breaker Westside Station 6—West of Hatwai
R534 Circuit Breaker Westside Station 6—West of Hatwai
Table 46: Avista Facility Elements within WECC Paths
Page 78 of 89

System Assessment I 2023-2024Appendix o
6. Appendix A — System and Company Description
6.1 . Overview
Avista is a publicly held energy company primarily involved in the production, transmission,
and distribution of energy (natural gas and electricity). Avista, formerly known as The
Washington Water Power Company, was founded on March 13, 1889, in Spokane,
Washington, by 10 enterprising men who saw the potential of one of the Northwest's most
abundant natural resources — moving water.
Avista's primary market area covers more than 30,000 square miles, with energy generation,
transmission, and distribution facilities in four Western states. The company serves more than
396,082 electric customers in eastern Washington and northern Idaho. Avista's electric power
generation and transmission assets range in age from modern 21st century equipment to
equipment that was patented and placed in service over 100 years ago.
The service territory served by the Avista electrical system is generally centered on the
Spokane, Washington and Coeur d'Alene, Idaho load centers. Avista also serves a smaller
southern load center located near Lewiston, Idaho and Clarkston, Washington. Figure 41
geographically displays the Avista service territory.
Kettle Falls•
Sandpoint
•Seattle •Noxon MONTANA
WASHINGTON Spokane• •Coeur d'Alene
`
Missoula
•Othello • Helene
Jackson Prairie Pullman• •Moscow •
Natural Gas Storage
L
evenson Clarkston• •Lewiston
Gol:ndale •Grangeville
Portland La Grande•
Sam
IDAHO
OREGON
•Boise
•Roseburg
Medford Electric :.
Natural Gas
•Klamath Falls Electric and Natural Gas ■
Figure 41: Avista Service Territory
6.2. Transmission System
6.2.1 .Transmission Infrastructure
Avista owns and operates a system of over 2,300 miles of electric transmission facilities which
include approximately 700 miles of 230kV and 1,600 miles of 115kV transmission lines. Figure
42 illustrates Avista's Transmission System on a regional map.
Page 79 of 89

System Assessment 2023-2024Appendix D
Kettle Falls
Colville
endpoint
• `` f RathdrumClark Fork
Chelan l 1 Noxon
Coeur d'Alene
pokan �
,Thompson Falls
-��
ellogg
� e
Othel o� ,Mo cow
Pullma
Clarkston Lewiston
11S W
Grangeville 230kv
Figure 42: Avista Transmission Line Map
Page 80 of 89

System Assessment I 2023-2024Appendix o
The Avista 230kV transmission lines are the backbone of Avista's Transmission System and
consist of two "rings" centered near the Spokane and Coeur d'Alene areas. The northern ring
connects generation in northwestern Montana to the larger load centers while the southern ring
serves the Moscow-Pullman and Lewiston-Clarkston areas. Figure 43 shows a station-level
drawing of Avista's 230kV transmission system including interconnections to neighboring
utilities. Avista's 230kV transmission system is interconnected to the BPA 500kV transmission
system at BPA's Bell, Hot Springs, and Hatwai Stations.
Bell
BPA
Lancaster Noxon Rapids
BPA AVA
Hot Springs
Grand Coulee - --- --- Bpp
BPA
Beason
Westside
AVA Cabinet Gorge
AVAA
Boulder AVA
AVA Rathdrum
AVA
Thornton Benewah
VA AVA Pine Creek
AVA
Shawnee Moscow
Wampum AVA AVA
GCPD
Hatwai
Q BPA
North Lewiston tC�-�I
Saddle Mountain AVA
AVA
Dry Creek Lolo Oxbow
Walla Walla Talbot AVA AVA
PAC PAC IPC
I f
Figure 43: Avista 230kV Transmission System
6.2.2.Transmission System Areas
Avista has separated its transmission system into the five geographical areas, namely
Spokane, Coeur d'Alene, Big Bend, Palouse, and Lewis-Clark. The areas are shown with their
approximate boundaries in Figure 44.
Page 81 of 89

System Assessment 2023-2024pppendix o
MONTANA
Gtbinet Gorge Dam
41
Big Bend Kettle Falls
Area ` NCVoron Rapids Dam
Post Falls
c ' •• ''•••••••- Spokane •
. • Coeur d'Alene
Spokant Rir� • .• Coeur d'Alene
Spokane Area
Area
S
WASHINTNI -o ".................•.
Palouse Area •.•
ti.;•: Pullman • •
• Moscow :
•� ••• T AH'IJ
Lewis-Clark �farlmt4n • • Lewiston
Area ••.•. ..
•., • Grangevil -
.
.......................
Figure 44: Avista Transmission System Regions
6.2.3.WECC Rated Paths
Avista owns transmission assets in the following WECC transfer paths:
• Path 6: West of Hatwai
• Path 8: Montana to Northwest
• Path 14: Idaho to Northwest
6.2.4.Points of Interconnection
Avista's BAA is directly interconnected to the BAAs operated by BPA, Public Utility District No.
2 of Grant County, Public Utility District No. 1 of Chelan County, Idaho Power Company,
PacifiCorp, NorthWestern Energy, and Seattle City Light.
Significant points of interconnection are associated with the BPA 500/230kV transformers
located at G.H. Bell Substation in Spokane, Washington, Hatwai Substation in Lewiston, Idaho,
and Hot Springs Substation in Hot Springs, Montana.
Within Avista's BAA, Avista's transmission and distribution system is interconnected with Pend
Oreille PUD's transmission system and several Load Serving Entities including Asotin County
PUD, Big Bend Electric Cooperative, City of Cheney, City of Chewelah, Clearwater Power
Company, Fairchild Air Force Base, Idaho County Light & Power Cooperative, Inland Power &
Light Company, Kootenai Electric Cooperative, Modern Electric Water Company, Northern
Lights, and City of Plummer. Avista-owned generation and distribution stations not connected
directly to Avista's transmission system are typically telemetered into Avista's BAA.
Page 82 of 89

System Assessment 2023-2024Appendix D
6.3. Generation Resources
Avista has a diverse mix of generation with most of its generation being hydropower with
various projects located on the Spokane and Clark Fork Rivers. Avista owns eight
hydroelectric generating plants as well as coal (partial ownership), natural gas, and wood-
waste combustion plants in five Eastern Washington, Northern Idaho, Eastern Oregon, and
Eastern Montana locations. Avista also utilizes power supply purchase and sale arrangements
of varying lengths to meet a portion of its load requirements.
For more information on Avista's generation, please refer to Avista's latest Integrated
Resource Plan (IRP).
6.4. Distribution System
Avista's distribution system consists of over 19,200 miles of distribution lines operated at
voltages ranging from 12.5kV to 34.5kV. Most of the distribution system is configured as radial
feeders with ties to adjacent feeders and stations for redundancy. The distribution system
serving the downtown Spokane area is an exception and is operated in a networked
configuration.
6.5. Cusiu,,icr Demand
Avista develops a biannual Electric IRP which is a thoroughly researched and data-driven
document to guide responsible resource planning for the company.
6.5.1 .Native Load
Avista historically experiences peak load in the winter months, between November and early
February. Air conditioning loads have created some pockets where summer peak load can
exceed the winter peak load. This phenomenon has transformed Avista into a dual peaking
utility.
As documented in the IRP, Avista's 20-year native peak load growth rate was 0.35 percent in
the winter and 0.42 percent in the summer.
6.5.2.Balancing Authority Area Load
The BAA load growth rate is expected to be consistent with the native load growth rate. The
forecast data for the loads which are not Avista's native loads are provided by BPA on behalf
of the Load Serving Entity of each load.
Avista's BAA load peaked at 2,514MW in the winter of 2022 and 2,380MW in the summer of
2021. Figure 45 and Figure 46 shows the BAA load historical winter and summer peaks from
2008-2020 and the forecasted monthly peaks for 2021-2030.
Page 83 of 89

System Assessment 2023-2024Appendix D
Winter Balancing Area Forecast
3600 _
�AtWsl WMtH
3000 ....2021 Fmccsst .—
2022 FoMM
3200 �2023 Ponta,[ .—
i000
2SM --
p26M
2400 �. ................ .............
2200
2000 Nj
180D
WM 2013 2023 Am 2038
Figure 45: Winter Balancing Authority Area load forecast
Summer Balancing Area Forecast
3600
Actual Summer
3400 2021 Forecast
2022 Forecast
3200
E 2023 Forecast
3000
3 2800
0 2600
2400 - -
2200
2000
1800
2008 2013 2018 2023 2028 2033 2038
Figure 46: Summer Balancing Authority Area load forecast
7. Appendix B — Transmission Models
7.1 . Planning Case Development
A set of transmission system models (Planning Cases) are developed biannually to model
Avista's Transmission Planner and Planning Coordinator areas as well as the regional
Transmission System. The Planning Case development process outlined in the internal
document TP-SPP-04 — Data Preparation for Steady State and Dynamic Studies outlines the
use of WECC-approved base cases and applying steady state and dynamic data modifications
as required representing desired scenarios. Additional details are provided in TP-SPP-01 —
Transmission System Performance and the Avista System Planning Assessment - 2023 Study
Plan.
The following scenarios are developed to represent various seasonal conditions over the near-
term and long-term transmission planning horizons (TPL-001-5, R2, R2.2):
Page 84 of 89

System Assessment 2023-2024pppendix D
• The Heavy Summer cases represent a typical summer peak scenario where the Avista
BAA is near peak load with local hydro generation at mid to late summer output. These
scenarios model moderate transfers on Path 8 and Path 14 across Avista's BAA and
heavy Path 8 transfers south into Idaho's BAA. These scenarios are limited by the
summer thermal limits on various elements of the Transmission System, which helps to
define where the system is near capacity.
o The first year is the latest Operations case projected out to the following year.
o The fifth and tenth year are based on the latest WECC approved cases.
• The Heavy Winter cases represent a typical winter peak scenario where the Avista BAA
is near peak load and the local hydro generation is at moderate levels. These scenarios
model significant transfers across Avista's BAA from regional thermal resources. The
lower ambient temperature increases the operating limits of the various elements of the
Transmission System and the reactive load is near unity power factor.
o The first year is the latest Operations case projected out to the following year.
o The fifth and tenth year are based on the latest WECC approved cases.
• The Light Spring cases represent typical April and May loading during early morning
minimum load conditions.
• Spring peak scenario with High West of Hatwai Flows (High Transfer case): during light
summer (nighttime loading) with high Western Montana Hydro and high Montana
thermal generation, the WECC rated path "West of Hatwai" (WECC Path 6) reaches its
heaviest loading. During this scenario, portions of the Transmission System are nearing
their stability limits. These limits define some of the operating constraints for the region
and establish some of the arming levels for Remedial Action Schemes. This scenario is
also limited by the summer thermal limits on various elements of the transmission
system, which helps to define where the system is near capacity.
Page 85 of 89

System Assessment 2023-2024Appendix c
7.2. Case Summary
Description
Scenario . . . .
Heavy Loads 1 in 20*, Generation per
Summer Generation Dis atch** X X X R2.1.1, R2.2.1, R2.4.1, and R2.5
Heavy Loads 1 in 20*, Generation per
Winter Generation Dispatch** X R2.1.1, R2.2.1, R2.4.1 and R2.5
Heavy Sensitivity to high load during the R2.1.3 and R2.4.3 sensitivity for R2.1.2 I
Spring spring _ X and R2.4.2
Light Loads 1 in 2*, Generation per
Spring Generation Dispatch** X R2.1.2 and R2.4.2
HS 5-Year Sensitivity to Proposed five-year R2.1.3 and R2.4.3 sensitivity for R2.1.1
Projects Projects during Heavy Summer*** _ X _ and R2.4.1
Sensitivity to light load, high
High E-W generation, and high system R2.1.3 and R2.4.3 sensitivity for R2.1.2
Transfer transfers X and R2.4.2
* All monthly historical peaks during indicated season used to calculate median monthly peak
value. For loading 1 in 20, during any given year, 5% of the time the seasonal peak will be
above indicated loads, and 95% of the time the seasonal peak will be below.
** Generation units are placed on or off using the Generation Dispatch sheet according to the
season indicated.
*** Scenario will assume planned projects are not constructed therefore representing the existing
transmissions stem facilities.
Table 47: System Assessment Evaluation Case Descriptions
Page 86 of 89

System Assessment 2023-20240,ppendix D
8. Appendix C — Investment Driver Definitions
8.1 . Customer Requested
Includes customer requests for new gas or electric service connections, line extensions, or
system reinforcements to serve a single large customer. We have often referred to new service
connections as "growth." Prompt and efficient response to customer requests for service is a
Commission requirement.
Example Projects and Programs:
1. Installing electric and natural gas distribution facilities in a new housing or commercial
development.
2. Adding street or area lights per request from the City/County or private individual,
respectively.
3. The costs associated with the first installation of electric and gas meters.
8.2. Customer Service Quality and Reliability
Investments required to maintain or improve service quality, to introduce new types of services
and options to meet customer needs and expectations, to meet customer service quality
requirements, and to achieve our electric system reliability objectives.
Example Projects and Programs:
1. Advanced Metering Infrastructure
2. Specific projects that are predominantly built to improve system reliability such as
distribution automation, worst feeder program, or outage management system
3. Adding new customer products and services such as community solar, building energy
management systems
4. Redeveloping our customer website — www.avistautilities.com
8.3. Mandatory and Compliance
Investments driven by compliance with laws, rules, and contractual obligations that are
external to the Company such as State and Federal statutes, settlement agreements, FERC,
NERC, and FCC rules, Commission Orders, among others.
Example Projects and Programs:
1. Investments to meet FERC hydro license conditions such as the mitigation of gas
super-saturation, or environmental permit requirements including clean air and water.
2. Spending required to meet contract requirements, such as the owner/operator
agreement for Colstrip, or tribal settlement agreements.
3. Transmission additions to meet NERC/WECC planning requirements.
4. To comply with regulatory requirements such as identifying and remediating gas
overbuilds, natural gas cathodic protection, or hydro safety requirements.
5. Costs for relocating natural gas or electric facilities associated with road development
projects,
6. To comply with franchise agreements or right-of-way permits including state, county,
city franchise and tribal permits.
7. Investments required under regulatory settlements such as isolated steel pipe removal.
Page 87 of 89

System Assessment 2023-2024pppendix D
8.4. Performance and Capacity
Includes a range of system reinforcement projects to meet defined performance standards,
typically developed by the Company, or to enhance the performance level of assets based on
a demonstrated need or financial analysis.
Example Projects and Programs:
1. Upgrades to transmission, station, and distribution assets to relieve grid congestion or
to mitigate thermal overloads.
2. Gas pipeline capacity needed to meet the Company's "design day" standard of-25F°.
3. Investments in hydro and thermal generation to maintain a level of unit availability or to
achieve efficiency output objectives.
4. New employee training facilities to accommodate greater numbers of craft apprentices
entering the workforce.
5. Ergonomic office equipment to reduce the incidence of employee health issues.
6. New engineering building at the Clark Fork River projects.
7. Purchase or expand office facilities to accommodate additional employees or special
projects, including Project Atlas and Project Everest as examples.
8. New computer software and hardware to achieve work process and business continuity
objectives.
8.5. Asset Condition
Investments to replace assets based on industry accepted, asset management principles and
strategies. Asset management strategies are designed to optimize the overall lifecycle value
for customers. Examples of common asset strategies include:
1. Run to failure (streetlights)
2. Inspection-based replacement (gas leak survey, pole test and treat)
3. Monitor-based replacement (power transformer gas monitoring)
4. Calendar-based replacement (PC refresh, cell phones)
5. Condition-based replacement (fleet replacement based on age, vehicle mileage, and
operating expense)
Example Projects and Programs:
1. Personal computer (3-year) and cell phone (2-year) refresh cycles
2. Wood pole inspection and replacement (20-year)
3. HVAC replacement (condition based)
4. Aldyl-A pipe program
5. New replacement office furniture
6. Project Compass
7. New roof for office building
8. New microwave communications system (driven by FCC)
9. Replacement of fleet vehicles and equipment
10.Natural gas meter ERTs
11.Gantry crane replacement program
12.Spokane hydro redevelopment
13.Thermal plant "run-time" capital maintenance program
14.Distribution transformer change-out program (TCOP)
Page 88 of 89

System Assessment 2023-2024pppendix D
15.Station inspection and equipment replacement program (circuit breakers, voltage
regulators, insulators, cables, and control systems)
8.6. Failed Plant and Operations
Requirements to replace failed equipment such as failed transformers, switches, poles, wires,
cables, gas pipes, and meter sets. Also includes inspection-based replacements of natural gas
and electric infrastructure identified by Operations.
Example Projects and Programs:
1. Cable, equipment, vaults, and manholes located in Avista's electric secondary district
(Spokane business district)
2. Electric distribution minor blanket (capital maintenance and repairs of existing overhead
and underground systems)
3. Electric and gas meter blanket (replacement of failed units)
4. Transmission blanket (storm response)
5. Electric distribution storm damage
6. Natural gas minor blanket (capital maintenance and repairs of existing gas plant)
Page 89 of 89

Appendix D
This Page is Intentionally Left Blank

Appendix E
2025 Electric Integrated
Resource Plan
Appendix E — Transmission
Generation Integration Study
°,VV 1sra

Appendix E
11
IRP Generation Integration Study
2024
South o_f_Boundary- - - -- -}J
881 MW l T
1 b'
MW 1 112 W Bell N'3
---- ---1-- ;___ ___ BPA 9'f I
Q 1 o I Lancaster Noxon Rapids '
JC�-11 1 �' BPA AVA '
1 6 MW s4 w ; Inl MW Hot Springs
Grand Coulee 1 ------- - -------------'--- -- --------
1 ---- Q--- �- Ilww—
AVA BPA I
BPA
1
' Beacon _AVA 76 , Cabinet Gorge Boulder1 AVA92 MW
3 Mw AVARathdrum ----- I1- -
AVA
Westside AVAThornton Benewah 8AVA AVA Pine Creekzz Iw Z,;
109 w 177 W 3'f
Shawnee Moscow
q,
Wanapum 'if AVA AVA
GCPD
Hatwai
`o -I W BPA
Saddle Mountain 3 North Lewiston
AVA ; AVA 3 451 lt,, -- Idaho-Northwest(Path 14) -J
-2544 MW 1
8 Walla Walla Talbot 1 Dry Creek LOIo Oxbow
PAC PAC 1 AVA AVA I IPC
1 MW
1 153 65 MW _ '
i - -- - --- ----- - -- - -- --- =
Avista's 230kV Transmission System
Transmission System Planning
Avista Utilities
PO Box 3727, MSC-16
Spokane, WA 99220
[e-mail]
Prepared by: Dean Spratt
Version Date DescriptionAuthor
A 3/26/24 Initial draft for scope & 1st order cost estimates Spratt Gross/Gall
B 7/26/24 Updates based on 2024 Cluster Study results Spratt Gross

IRP Generation Integration Study 2024ppendix E
Table of Contents
1. Executive Summary................................................................................................. 3
1.1. Results Summary............................................................................................... 3
2. Scope of Study.........................................................................................................4
2.1. Large Generation Interconnection Requests ..................................................... 5
2.2. Typical LGIR Integration Discussion..................................................................6
3. New Generation Integration Sites ............................................................................ 7
3.1. Big Bend Area near Lind (Tokio)........................................................................ 7
3.2. Big Bend Area near Odessa .............................................................................. 9
3.3. Big Bend Area near Othello ............................................................................. 11
3.4. Big Bend Area near Reardan........................................................................... 15
3.5. Lewiston/Clarkston Area.................................................................................. 18
3.6. Lower Granite Area.......................................................................................... 20
3.7. Palouse area near Benewah (Tekoa) .............................................................. 22
3.8. Rathdrum Prairie.............................................................................................. 24
3.9. Sandpoint Area ................................................................................................ 26
3.10. West Plains Area ............................................................................................. 29
4. Existing Generation Integration Sites..................................................................... 31
4.1. Kettle Falls Station........................................................................................... 31
4.2. Northeast Station ............................................................................................. 33
4.3. Palouse Wind................................................................................................... 36
4.4. Rathdrum Station............................................................................................. 38
Page 2 of 40

IRP Generation Integration Study I 2024ppendix E
Generation Integration Study Request
Fall of 2023, Avista System Planning received a study request from Avista's Power
Supply Department to refresh the 2021 study request, which identified system impacts
from integrating additional generation for Native Load retail customers at the following
interconnection points:
• New generation sites
o Big Bend area near Lind 100MW
o Big Bend area near Odessa 100, 200 and 30OMW
o Big Bend area near Othello 100, 200 and 30OMW
o Big Bend area near Reardan 50 and 10OMW
o Lewiston/Clarkston area 100, 200 and 30OMW
o Lower Granite area 100 and 30OMW
o Palouse area, near Benewah 100 and 20OMW
o Palouse area, near Tekoa 100 and 20OMW
o Rathdrum Prairie, near Greensferry Rd 100, 200, 300 and 40OMW
o Sandpoint area 50, 100 and 150MW
o Tokio area, northeast of Ritzville 100 and 20OMW
o West Plains area, north of Airway Heights 100, 200 and 30OMW
• Existing generation sites (increase capacity or add generation to existing POI)
o Kettle Falls 50 and 10OMW
o Northeast CTs 50, 100 and 20OMW
o Palouse Wind (IPP) 100 and 20OMW
o Rathdrum CTs 25, 50, 100 and 20OMW
o Rattlesnake Flat Wind (IPP) 140MW
The scope of integration points did not need to be expanded or changed, so the
following study mainly reflects increased integration costs due to recent increases in
equipment costs and siting. The list was expanded to explore new generation in the
Sandpoint area and a Battery Energy Energy Storage (BESS) at Northeast Station.
Results Summary
This study presents interconnection impacts and cost estimates associated with the
integration of the above resources as Network Resource Interconnection Services
(NRIS). During the study process, Avista's System Planning department conducts
steady state power flow analysis to determine transmission system reinforcements
necessary to integrate each project. Following is a summary of the study results:
Page 3 of 40

IRP Generation Integration Study I 2024ppendixE
-•
Cost
• -
(MW) Voltage
Big Bend area near Lind (Tokio) 100/200 230kV 127.8
Big Bend area near Odessa 100/200/300 230kV 170.5
Big Bend area near Othello 100/200 230kV 216.8
Big Bend area near Othello 300 230kV 258.7
Big Bend area near Reardan 50 115kV 9.7
Big Bend area near Reardan 100 115kV 12.8
Lewiston/Clarkston area 100/200/300 230kV 1.9
Lower Granite area 100/200/300 230kV 2.9
Palouse area, near Benewah (Tekoa) 100/200 230kV 2.4
Rathdrum Prairie, north Greensferry Rd 100 230kV 34.0
Rathdrum Prairie, north Greensferry Rd 200/300/400 230kV 53.9
Sandpoint Area 50 115kV 1.6
Sandpoint Area 100/150 115kV 48.2
West Plains area north of Airway Heights 100/200/300 230kV 2.4
Table 1: New generation integration sites and estimate summary
-IF -Emir
Cost
POI Stationor Area Requested Pol Estimate
• .•-
Kettle Falls Station 50 115kV 1.6•
Kettle Falls Station 100 115kV 19.0
Northeast Station 50 115kV 1.6
Northeast Station 100 115kV 7.7
Northeast Station 200 230kV 25.9
Palouse Wind, at Thornton Station 100/200 230kV 1.4
Rathdrum Station 25/50 115kV 11.1
Rathdrum Station 100 230kV 15.9
Rathdrum Station 200 230kV 48.4
Table 2: Existing generation integration sites and estimate summary
The Point of Interconnection (POI) estimates for integration onto Avista's existing
transmission system, listed in Table 1, are based on previous IRP Generation
Integration Studies and Large Generation Interconnection Request study results. The
POI designations conform to Avista's SP-SPP-02— Facility Interconnection
Requirements.
Scope of Study
This study evaluates the impacts of the proposed interconnections on the reliability of
the transmission system. Results are based on steady state continency analysis,
operational knowledge of the system, and results from previous generation integration
studies. The study considers existing generating facilities, pending senior queued serial
process interconnection requests, and interconnection requests currently in Avista's
Page 4 of 40

IRP Generation Integration Study 2024ppendix E
generation interconnection process. This study is for Avista's Power Supply Department
to evaluate bundled retail service for native load customers only and does not replace
tariffed generation interconnection process requirements for any future projects.
This interconnection study report includes the following information:
• Full contingency analysis identifying facility thermal and voltage violations
resulting from the interconnection at the requested facility output Ievel(s).
• Description and non-binding, good faith cost estimate of facilities required to
interconnect the project to the Avista Transmission System and maintain reliable
performance.
The transmission additions simulated in the study cases are based on the best
information available at the time the study was initiated. The findings included in this
study do not assure that the proposed Generation Project will be allowed to operate at
full or reduced capacity under any or all operating conditions. Avista cannot guarantee
future analysis (i.e. Transmission Service Requests or Operational Studies) will not
identify additional problems or system constraints that require mitigation or reduced
operation. It is possible that the actual plan of service will differ from the plan of service
studied, and System Planning reserves the right to restudy this request if necessary.
This study utilizes the annual Cluster Study base cases. Refer to Avista's 2024
Generator Interconnection Cluster Study Plant for additional information regarding the
study cases used, assumptions, and methodology. Results will reflect only the most
limiting scenario and will assume only one proposed generation interconnection point is
on-line at a time to determine feasibility and the potential reinforcements required to
integrate the new generation.
Large Generation Interconnection Request Summary
Prospective generation developers may request interconnection studies to understand
the cost and timelines for integrating new generation projects. These requests follow an
interconnection process outlined in Avista's Open Access Transmission Tariff (GATT)
that has been accepted by FERC. After this process is complete, a contract offer to
integrate the project may occur and negotiations can begin to enter into an
interconnection agreement. Table 2 lists information associated with potential third-party
resource additions currently in Avista's interconnection queue.2
ModelCluster (MW) I yFV County State Point of Interconnection
Number
Q59 60 Solar/Storage Adams WA Roxboro 115kV Station No
Q60 150 Solar/Storage Asotin WA Dry Creek 230kV Station Yes
Q63 26 Hydro Kootenai ID Post Falls 115kV Station Yes
Q66 71 Wood Waste Stevens WA Kettle Falls 115kV Station Yes
Q97 100 Solar/Storage Nez Perce I ID Lolo 230kV Station Yes
TCS-03 80 Solar/Storage Adams WA Warden 115kV Station Yes
TCS-14 375 Wind/Storage Garfield WA Dry Creek 230kV Station Yes
CS23-06 256 Wind Whitman WA Shawnee-Thornton 230kV Line No
CS23-12 199 Storage Franklin WA AVAHub-04 230kV Station No
Generator Interconnection Cluster Study Plan 2023 - V2.pdf (oati.com)
2 Bookl (oati.com)
Page 5 of 40

IRP Generation Integration Study 2024ppendix E
ModelSerial or Output
Cluster (MW) Type County State Point of Interconnection
Number
CS23-13 40 Solar Lincoln WA Davenport 115kV Station No
CS23-14 40 Solar Spokane WA North Fairchild 115kV Line Tap No
CS24-01 1.1 Solar Adams WA South Othello 13kV feeder No
CS24-02 0.5 Storage Spokane WA Third&Hatch 13kV feeder No
CS24-03 150 Storage Adams WA Saddle Mountain 115kV Station No
CS24-04 100 Storage Spokane WA Benewah 230kV Station No
CS24-05 203 Natural Gas CT Kootenai ID Rathdrum 230/115kV Station No
CS24-06 120 Natural Gas CT Bonner ID Bronx 115kV Station No
CS24-07 2 Solar Adams WA Othello 13kV feeder No
CS24-08 199 Solar/Storage Franklin WA AVAHub-04 230kV Station No
CS24-09 9.5 Solar Adams WA Othello 13kV feeder No
CS24-10 80 Solar/Storage Spokane WA Spangle 115kV Station No
CS24-11 70 Solar Whitman WA Thornton 230kV Station No
CS24-12 40 Solar Whitman WA Shawnee-Sunset 115kV Line No
CS24-13 95 Solar Whitman WA Benewah-Thornton 230kV Line No
CS24-14 40 Solar Spokane WA South Fairchild 115kV Line Tap No
CS24-15 300 Wind/Storage Lincoln WA Bluebird 230kV Station No
Table 3: Existing Large Generation Interconnection Requests
Typical LGIR Intearation Discussion
Large Generation Interconnection Requests (LGIR) are typically integrated onto Avista's
transmission system at 115kV or 230kV. The backbone of the Avista transmission
system is operated at 230kV. A station-level drawing of Avista's 230kV Transmission
System including interconnections to neighboring utilities is shown below.
11-1h of Eirun<I.iry
M`J T
I '
6IMW I 117 Bell 13
____�___,___, ___ __ BPA '_
1 '
Q I , �1 I„ancas0ar Noxon Rapids '
BPA AVA '
I 6"W s+ ;' ml Hot Springs
Grand Coulee I ----------- -----------�- -------`_--- -�---- BPA ,
OS MW
BPA ,
, I %65 MW 163 9MW
I
' Beacon OI MW I
I '
AVA » w , Cabinet Gorge I
I Boulder
1 AVA 92 MW ,
I 3Mw AVA
, fiathdrum
1
AVA '
Westside
I AVA m
Ll Thornton Benewish 8 I AVA �z nw AVA Pine Creek
' AVA �13
1
1oe��w vz wIn w 3'a
I I Shawnee Moscow g'
Wampum6PD, AVA AVA c'
GCPD
7 Hatwai
lsz w BPA
S
AVA addle Mountain 3 North Lewiston
; AVA 3 451 MW __ Idaho-NorthwLw (Patt1 SAI)_-�
-2544 MW
8 Walla Walbot ' Dry Creek
Lo to ,Oxbow
alla T
PAC PAC AVA AVA IPC
I 3zs Mw
762J.1W , 153 W
I
1 _
Figure 1: Avista 230kV transmission system, heavy summer 2029
Page 6 of 40

IRP Generation Integration Study I 2024ppendix E
Avista's 230kV Transmission System is interconnected to the Bonneville Power
Administration's (BPA) 500kV transmission system at the Bell, Grand Coulee, Hatwai,
and Hot Springs Stations.
The following sections describe the proposed generating facilities that have requested
integration onto Avista's Transmission System. Assumptions, alternatives, and system
performance are detailed for each individual Point of Interconnection (POI).
3. New Generation Integration Sites
3.1 . Big Bend Area near Lind (Tokio)
3.1 .1 . Project description and one-line diagram
The following evaluates the impacts of integrating 100 to 20OMW of new generation
onto Avista's transmission system in the Lind area. The 115kV system in the Big Bend
area, specifically the Lind area, is at capacity with local renewable generation using
most of the existing transmission capacity. Local generation is currently curtailed under
N-1 conditions. Adding generation only exacerbates the known issues. Previous studies
have shown that new generation in this area will require an expansion of the 230kV
network into the area.
This study will assume that the 1 st phase of the 230kV expansion would add a 230kV
hub approximately 15 miles east of Lind then build a 46-mile radial 230kV transmission
line connecting the new hub station into Avista's primary load center with a termination
at the Thornton Station. This request was modeled as a new 230kV system expansion
as shown below.
These results are similar for the request at Tokio, given this location is withing 20 miles
of 230kV network expansion.
uro aaow
a.s9s w
�*2E M
rxorw
aim aNSral! NMENW EWM ItI�IwND ,
�Y .aoow r.aoow i.am�•,.
^^ OVA Yi OAS 0�.0 '.9 aaMwr WN�iW AIIN* 1-LJ l
OA Mar
�IELSOM
I.000w , IIIII 19 w
OA N.rr OA ,,
. Yl 30 NW
lJ I Nwr
HEIr
�-- ��Iw�0.5111Y
E'QO Mar
w SIII"EE
MW
�.
rCI'IFRO ]].ISHRWNEE
Figure 2: New generation at 230kV near Lind flowing into Thornton, heavy summer 2029
System performance in this area is dominated by several factors:
• This 230kV expansion transfers the proposed generation into the Palouse area.
• System flows are typically north to south.
• Existing local generation (104MW) at Palouse Wind.
Page 7 of 40

IRP Generation Integration Study I 2024ppendix E
In general, new generation in this area will sink into local load. As the local load service
is met the additional power will flow south into the Lewiston/Clarkston load center.
3.1 .2. Contingency Analysis
The worst system performance was during heavy summer conditions with high north to
south ID-NW transfers. The issues identified below can be mitigated by adjustments to
ID-NW flows. The spring and winter scenarios did not identify any issues.
FRowOOF20OMW
T-1:Bell#6 230/115kV
Beacon-Bell#1 115 kV 103.1 103.7 104.4
Beacon-Northeast 115 kV 95.1
BF:BEA A600,Beacon North&South Bus Tie
Francis and Cedar-Northwest 115 kV 102.5 101.9 101.2
Northwest-Westside 115 kV I 101.1 100.6 100.1
BF:BEA R427,Beacon Bus Tie
Boulder-Irvin#1 115 kV(Boulder-Spokane Industrial Park) 95.3
BF:BELL A370,Bell S1 &S2 230kV
Beacon-Bell#1 115 kV I 100.4 101.1 101.8
BF:BELL A388,Bell S2&S3 230kV
Beacon-Bell#1 115 kV 96.3 1 97.1 98.1
BF:BLD A713,Boulder-Otis Orchards#1
Boulder-Irvin#2115 kV 98.1
BUS:Bell S2 DOW
Beacon-Bell#1 115 kV 101.2 101.8 102.E
BUS:Boulder West 11 RV
Boulder-Irvin#2115 kV 96.2 99.4
Table 4: Contingency results, heavy summer 2029
The worst performing contingency is a loss of both the Benewah -Thornton 230kV and
North Lewiston - Shawnee 230kV Transmission Lines (N-1-1) forcing all the 230kV
connected generation through the underlying 115k system as shown below.
Bf ENS�I y�p�p I' 0.947p1(MM�
-, 1�b8W
1.7 MW 1.2 MW
T M-
U
TFtV NMO�COW 13 Mval 1.1 Mrar
1. 1. 1.01 pu
SH1.�IAINEE OW
5 28. 9.5 MW 3.5 Mvar pU Mo1QW
9.5 Mvx 2.7 Mvx PO -Y
(' -7 1COMl li lu 2 W
2.1 MW
SHAWNE 121.E MW 0.5 Mvx
1.0 pu AA + SPULLM
P F 34.7 Mrar
2.8 MW
Q�� 0.7 Mvx
0.7 26.2 MW 1.013 p11 4.9 MW
0.2 Hvar 8.5 Mvx ' 13 Mvar
�M1ofcrrY 'Y.'oiS;T
28.7 MW 2.IM 6.2MW
9.5 Mvar 0.] W Mvar 1.]Mvar
Figure 3: Worst performing contingency, heavy summer 2029
Page 8 of 40

IRP Generation Integration Study 2024ppendix E
Generation would have to be curtailed during an outage of either of these 230kV
transmission lines.
3.1 .3. Weak System Analysis
A three-phase short circuit fault at this new radially fed 230kV hub is approximately
1,0001VIVA, therefore new generation would be limited to about 30OMW to maintain grid
stability. Generation additions beyond this limit, would require a second 230kV line into
the Lind area to correct the weak grid issue.
3.1 .4. Integration cost
The Thornton Station has a 230kV ring bus arrangement with space for a one new
230kV line.
r IF W Cost
P01 Station or Area Estimate
Point of Interconnection Station 1 million)
New AVAHubLind Station—property, termination, comms and metering 18.8
Projects necessary to mitigate news stem violations at 100/20OMW
New 46 mile AVAHubLind-Thornton 230kV SCT transmission line 107.6
New 230kV line position at Thornton Station 1.4
total 127.8
Table 5: Generation integration estimate
Estimates assume that the Interconnection Customer will be responsible for the lead
line up to the change of ownership, which is a dead-end tower at the POI Station.
3.2. Big Bend Area near Odessa
3.2.1 . Oroject description and one-line diagram
The following evaluates the impacts of integrating 100 to 30OMW of new generation
onto Avista's transmission system in the Odessa area. The 115kV system in the
Odessa area is near capacity and existing generation at Devils Gap and Stratford is
already being curtailed for multiple N-1 operational issues. Previous studies have shown
that new generation in this area will require an expansion of the 230kV network.
This study assumes that the first phase of that expansion would add a 230kV hub near
Odessa Station, then build a (64) mile radial 230kV transmission line to connect the new
hub station into Avista's primary load center with a termination at the planned Bluebird
Station. This request was modeled as a new 230kV system expansion as shown below.
Page 9 of 40

IRP Generation Integration Study 2024ppendix E
1
Loot.6w 1 Q" Le
'17� aNw 1 p Iw
f 0 90P
f
wvwN.boes. /
I.ow w / N�Fhw
goo Hw
�>OFSSA NM11NfiTM DAVEMPIIi I
1 939 p� 0.99T w
��.� _ / I W111t IVl li
27 Mq w2 Hva. OJ M.nr f 36/MW
• o.o Mv. O.6
1" / EAST PLAINS 0.5-
I.lBW
Figure 4: New generation at 230kV near Odessa flowing into Bluebird, heavy summer 2029
System performance in this area is dominated by several factors:
• 230kV expansion transfers the proposed generation into the West Plains area.
• System flows are typically east to west in the spring and west to east during
heavy summer.
• There is no existing local generation.
In general, new generation in this area will sink into local load. As the local load service
is met the additional power will flow east into the greater Spokane area.
3.2.2. Contingency Analysis
The worst system performance was during heavy summer conditions. The issues
identified below result from moving power from the West Plains into the downtown
Spokane load center. The spring and winter scenarios did not identify any issues.
T-1:Bell#6 2301115kV
Beacon-Bell#1 115 kV I 103.1 104 104.9 I 105.9
Beacon-Northeast 115 kV 95.6 96.4
BF:BEA A600,Beacon North&South Bus Tie
Francis and Cedar-Northwest 115 kV 102.5 100.8 99.3 97.9
Northwest-Westside 115 kV 101.1 99.7 98.6 97.5
BF:BELL A370,Bell S1 &S2 230kV
Beacon-Bell#1 115 kV 100.4 101.5 102.7 I 103.8
BF:BELL A388,Bell S2&S3 230kV
Beacon-Bell#1 115 kV 96.3 97.4 98.7 99.9
BUS:Bell S2 230kV
Beacon-Bell#1 115 kV 101.2 102.3 103.4 104.6
Beacon-Northeast 115 kV 95.3
Table 6: Contingency Results, heavy summer 2029
Page 10 of 40

IRP Generation Integration Study 2024ppendix E
The worst performing contingency is a loss of both the Bell — Bluebird 230kV and
Bluebird - Coulee 230kV Transmission Lines (N-1-1) forcing all the 230kV connected
generation through the underlying 115k system as shown below.
- - ,a "T.-
° twfluml
°
® _ . K. MR-
r
ITS
Figure 5: Worst performing contingency, heavy summer 2029
The area load and recent 115kV system reinforcements help to reliably transfer the new
generation into the Spokane load center.
3 2.3. Weak System Analysis
A three-phase short circuit fault at this new radially fed 230kV hub is approximately
9401VIVA, therefore new generation would be limited to about 30OMW to maintain grid
stability. Generation additions beyond this limit, would require a second 230kV line into
the Odessa area to correct the weak grid issue.
~itearation costs
The planned Bluebird Station has a 230kV double breaker double bus arrangement with
space for a new line position.
Cost
P01 Station or Area Estimate
million)Point of Interconnection Station
New AVAHubOdessa Station—property, termination, comms and metering 18.8
Projects necessary to mitigate news stem violations at 100/200/30OMW
New 64 mile AVAHubOdessa-Bluebird 230kV SCT transmission line 149.8
New 230kV line position at Bluebird Station 1.9
total 170.5
Table 7: Generation integration estimate
Estimates assume that the Interconnection Customer will be responsible for the lead
line up to the change of ownership, which is a dead-end tower at the POI Station.
3.3. Big Bend Area near Othello
3.3.1 . Oroject description and one-line diagram
The following evaluates the impacts of integrating 100 to 30OMW of new generation
onto Avista's transmission system in the Othello area. The 115kV system in the Big
Page 11 of 40

IRP Generation Integration Study 2024ppendix E
Bend area is at capacity. Local generation is currently curtailed under N-1 conditions.
Adding generation only exacerbates the known issues. Previous studies have shown
that new generation in this area will require an expansion of the 230kV network into the
area.
This study assumes that the second phase of a 230kV expansion would add another
230kV hub approximately 6 miles east of Othello, then Avista would build a (30+46) mile
radial 230kV transmission line connecting the new hub station into Avista's primary load
center with a termination at the Thornton station. This request was modeled as a new
230kV system expansion as shown below.
�m w:
@,bn
A
.I' [-UNN... �_ d K�a1K ,aNPa
y~K jk v�i rlTlw
UZ
I
Figure 6: New generation at 230kV near Othello flowing into Thornton, heavy summer 2029
System performance in this area is dominated by several factors:
• 230kV expansion transfers the proposed generation into the Palouse area.
• System flows are typically north to south.
• Existing local generation (104 MW) from Palouse Wind.
In general, new generation in this area will sink into local load. As the local load service
is met the additional power will flow south into the Lewiston/Clarkston load center.
Additionally, this long of a radial 230kV line will only support about 150MW due to weak
grid issues. To meet the 30OMW generation requested, the above 230kV expansion
would also need to be networked. This will require an additional 17 miles of new 230kV
transmission line and a new 230kV line termination into the existing Saddle Mountain
Station as shown below.
6A MYar
1 Alliilll i9l
LZ
rolNoffc +FF- 1 •�,
1.011 W 1 Il
OTMELOBS 1 1
l SEEP IK 1 1.010W 1 ■ NfIfSON
1pu 101'W A OlNELLO LLEMEwI 1'�P'
_ _ IAoa PP I.00 w 1
1 117MW
3.i Mvx OJ Mof 11.8 MW ].S MW 1 _ i
1.1 Mvar aA Mvar 1 v ]OMvar
F11.i Mv> 1a.3 MW ]J MW NT
aJ Mvar I.a Mvar AVMNrUO[IMb 1 �UE WASIIIyyIIN
I.OaO PI WIW -1.009.)M
1 1111
SOT EEOT ELLO 313 MW 1 0 5 M 0
I.olaw IN, -13M var
1
se
1-~.• �i.1 Mnr
SAOOLEMTN2]0
ux w
SADOIENTNII�
1.013 W 1.002 II
1.ao1 w
114 i1W
M H.
0.99yv 0.9SB pu W , I 1.006 W
Figure 7: New generation at 230kV networked into Saddle Mountain, heavy summer 2029
Page 12 of 40

IRP Generation Integration Study 2024ppendixE
Completing the 230kV network to Saddle Mountain shifts the bulk of power transfers to
the west and moves the generation to the west side of the West of Hatwai (Path 6) cut
plain.
3.3.2. Contingency Analysis
The worst system performance was during heavy summer conditions with high north to
south ID-NW transfers. The issues identified below can be mitigated by adjustments to
ID-NW flows. The spring and winter scenarios did not identify any issues.
Row 0O
N-1:Sand Dunes-Warden 115kV
WARDEN A 48455 ->WARDEN T 46117 CKT 1 at WARDEN A I 97.7 103.7
T-1:Bell#6 2301115kV
Beacon-Bell#1 115 kV 102.9 104.4 103.2 103.4
Beacon-Northeast 115 kV 95.1
BF:BEA A600,Beacon North&South Bus Tie
Francis and Cedar-Northwest 115 kV 102.5 101.8 102.8 102.6
Northwest -Westside 115 kV 101.1 100.6 101.4 101.2
BF:BELL A370,Bell S1&S2 DOW
Beacon-Bell#1 115 kV 100.3 101.8 100.6 100.8
BF:BELL A388,Bell S2&S3 DOW
Beacon-Bell#1 115 kV I 96.1 97.8 96.3 96.6
BF:BLD A713,Boulder-Otis Orchards#1
Boulder-Irvin#2115 kV I 96.2
BUS:Bell S2 230kV
Beacon-Bell#1 115 kV 101.1 102.5 101.4 101.6
BUS:Boulder West 115kV
Boulder-Irvin#2115 kV 97.6
BUS:Sand Dunes 115kV
WARDEN A 48455)->WARDEN T(46117)CKT 1 at WARDEN T 95.7 101.2
Table 8: Contingency results, heavy summer 2029
The worst performing contingency is a loss of both the Saddle Mountain - Wanapum
230kV and Saddle Mountain - Walla Walla 230kV Transmission Lines (N-1-1) forcing all
the 230kV connected generation through the underlying 115k system as shown below.
Page 13 of 40

IRP Generation Integration Study 2024ppendix E
1AQ_3�-~_ , LEND
y1A10 pu^ i N6SONRD ^ J M.ar ; LOD1 w LIND 1 w
A�Q_�"Cmap
■ -'�'1 �. ....... s17� FG 17W DN°mD 1 oirMi
10 MW '._. _._._. _._._._. 1 ' .
WIM
.O Mwr �A®�-i _._._.__ x16 M.v 1.002W U�
3.1 MW AVAftbl
MM:T IOMVNr
MOLlG i L017W .,
� 1
1
��- NfIL50N
®w 1.OU7 W 1�MEL W
O.B MW
19 M a
0.3 Mvar L 111Y
l]2S INv &7 MW 3 MVAi
�MNr UMNr •YNINbOtlMbDEIIGMT WASH
LOWN '""' Loon
1 _
9011DDf 3.0 MW1 0
1.007 8D7181D M-7 MW O.5 varr
1.009
uMNW
W
4 MW�.9 Mv9r RADAR_NILL* RAOAR_>GM95080D011lY 5MAN0
r I 1„-.11 Io.9 '��C ! I. J.
I,.
Figure 8: Worst performing contingency, heavy summer 2029
The bottleneck at Warden into GCPD's system is a known issue and is a LGIR
contingent facility that may be corrected.
3.3.3. Weak SVstPm Analysis
A three-phase short circuit fault at the new longer radially fed 230kV hub is
approximately 690MVA, therefore new generation would be limited to about 20OMW to
maintain grid stability. Generation additions beyond this limit, would require a second
230kV line into the area to correct the weak grid issue.
3.3.4. Integration cosi.
The Thornton Station has a 230kV ring bus arrangement with space for a one new
230kV line. The Saddle Mountain Station additionally has space to terminate a new line
position.
Page 14 of 40

IRP Generation Integration Study 202O,ppendix E
Cost
POI Station or Area Estimate
million)Point of Interconnection Station
New AVAHubOthello station—property, termination, comms and metering 18.8
Pro'ects necessary,to mitigate news stem violations at 100/200MW
New AVAHubLind station—property, termination, comms and metering 18.8
New 46 mile AVAHubLind-Thornton 230kV transmission line 107.6
New 30 mile AVAHubLind-AVAHubOthello 230kV transmission line 70.2
New 230kV line position at Thornton Station 1.4
total radial 216.8
New AVAHubLind Station—property, termination, comms and metering 18.8
New 46 mile AVAHub05-Shawnee 230kV SCT transmission line 107.6
New 30 mile AVAHub05-AVAHub06 230kV SCT transmission line 70.2
New 230kV line position and xfmr breaker at Shawnee Station 1.4
New 17 mile AVAHub06-SaddleMtn 230kV SCT transmission line 39.8
New 230kV line position at Saddle Mountain Station 2.1
total networked 258.7
Table 9: Generation integration estimate
Estimates assume that the Interconnection Customer will be responsible for the lead
line up to the change of ownership, which is a dead-end tower at the POI Station.
3.4. Big Bend Area near Reardan
3.4.1 . Project description and one-line diagram
The following evaluates the impacts of integrating 50 to 100MW of new generation onto
Avista's transmission system in the Big Bend area near Reardan. The Devils Gap — Lind
115 kV line is normally operated open at Ritzville, therefore any additional generation
will flow north into Devils Gap, where the local hydro generation is using most of the
existing transmission capacity. Local generation is currently curtailed under N-1
conditions. Adding generation only exacerbates the known issues as shown below.
IONOIAKT
1.005 W 3.2 _
LI)JSLq.L GOl19T�
0.9 Mw l0-iIALMI
1.9MW O.O My r t-0Oi pu
o.o M,.ar NILIE +5
BMW 1 1v 31«a 1.003 pu
(y/O,MIWr1� . W� SMva �+ JMwr 'I t
y1 BMW 31 MW
O Mvar W 7..
5i°o wWr T 1"lJ 7MM„Wa q OM p�Q -•--•
LOMGAIR ��OiA vao1r
0.11 wr
1
— <------ —'--<A— ./*--�'I—L--•--<— —a---E--a--<--•--
�r A Y
EGYPT* L4�- l 1
m9� 1.OIS W i
;I'W 2Nw l311w
1 + r !Mw �3.OIlaOe 1
1
ION
Sfll61f
°Li�O's oD
J O.O Mwr L300'MWr OIIW � .
Figure 9: New generation at Reardan flowing into Devils Gap, light spring 2029
Page 15 of 40

IRP Generation Integration Study 2024ppendix E
Given the existing 115kV system into Devils Gap is near capacity, this request was
modeled as a new 115kV switching station in the West Plains load center near
Espanola on the Airway Heights — Melville 115kV line as shown below.
0 Mar FLIRT RD 21.1 MW
1.014 Du 1.1
� g5 g5��RR
M �1A15Du
1MW
0 Mvar 10.1 MW �
A�I AU 0.3 MVW KW 4 THIR7 p C
Ou 9MW 11 MW 1.17 Du
�p�(���� 1 MVW 0 N—
�' 2.1MW 10.7 MW 3013 Du
O.O Mvar 0.0 Mvar 0.3 Mrar
L/�-2 MW EE77RR 2.8 Mtil
AER 11J-2 Mvar M1.O15p u a� 1.8 Mvx
0 6 GMDBLSV E
F 1(gILD 1.038 0.3 MW 47.3 MW
3.5 MW 0.2 Mvx
0.0 Mvar
FLOES Du 0 0 GARDENSP SUF�S�� 0' MVW
ESWn9Ia 1.014 Du 1.015 Du JL
1.017 Du
4.9 MW 21.9M,T22.9 MVW
0.1 MV 1."VW-15 M $i VRL S.tVRLAK 3�014 pEA,'74—.-4—
FDu .16 DuH "rr 1611 puOf0 9.9 MW
i 6.9 M :6 MW 1.0 Mar.1 Mnvar * 3 MW 0.2 MVW „•..,,Y-11
omm
5MW 1 FOURLBPA W
�711W t.Otl Du &2 MW
0.1 Mar 0.2 MVW
Figure 10: New generation flowing into the West Plains, light spring 2029
System performance in this area is dominated by several factors:
• 115kV expansion transfers the proposed generation into the West Plains area.
• West Plains area load ranges between 77MW and 160MW.
• Existing local generation (18MW) at Waste to Energy.
In general, new generation in this area will sink into local load. As the local load service
is met the additional power will east into the downtown Spokane load center.
3.4.2. Contingency Analysis
Worst system performance was during light spring conditions with high east to west
transfers and during heavy summer conditions. Outages on the 230kV system results in
overloads on the underlying 115kV system, as shown below. The winter scenarios did
not identify any issues.
The worst system performance was during light spring conditions with high north to
south ID-NW transfers. The issues identified below can be mitigated by adjustments to
ID-NW flows. The spring and winter scenarios did not identify any issues.
rSouth
Heights-Garden Springs 115kV
child Tap 115kV(SLK Tap-H&W) 77-7-
N-1:Airway Heights-Silver Lake 115kV
South Fairchild Tap 115kV(SLK Tap-H&W) .
BF:AIR A180,Airway Heights-Devils Gap
South Fairchild Tap 115kV(SLK Tap-H&W) 102.7
BF:AIR A182,Airway Heights-Garden Springs 11RV
South Fairchild Tap 115kV(SLK Tap-H&W) 102.7
BF:GDN A1303,Airway Heights-Garden Springs 115kV,Garden Springs-Westside 115kV
South Fairchild Tap 115kV(SLK Tap-H&W) 119.2
Page 16 of 40

IRP Generation Integration Study 2024ppendixE
BUS:Airway Heights 115kV
South Fairchild Tap 115kV SLK Ta -H&W 102.7
N-1:Airway Heights-Garden Springs 115kV Open @ AIR
South Fairchild Tap 115kV(SLK Tap-H&W) 117.3
N-1:Airway Heights-Garden Springs 115kV Open @ GDN
South Fairchild Tap 115kV(SLK Tap-H&W) 116.2
N-1:Airway Heights-Silver Lake 115kV Open @ AIR
South Fairchild Tap 115kV(SLK Tap-H&W) 102.8
N-1:Garden Springs-Silver Lake 115kV Open @ AIR
South Fairchild Tap 115kV(SLK Tap-H&W) 102.8
N-1:Lind-Warden 115kV Open @ LIN
Table 10: Contingency results, light spring 2029
The worst performing N-1 contingency is shown below.
FUNTRD -' POSTSTRT
-�, E.---pu
1.014 pu
�LMvvar
-_ 10.1 MW TH�ffACH
0.3 Mvar
ri9MW 1. 1 pu
RWAYHT 1 1 Mvar
1.01 pu O Mvar WMTUE
T 2.111,11W 10.714W 16 MW 26.6MW
F•XtMCHLDA Mvar OA MW 0.3 Mrx 1 -2 Mrx M1.014 Pu M .0 Mva
1. W 1.037 83 MW 47.2 Mvar
V3.5 MW 0.2 Mvar
Mvar
ti
7.6 MW
FAIR S O O ENSP T 0.1 Mvar
1.o1s pu r'1. T GLENROSE
Espanola 1. pu 1. 1 W +1.012 pu
PU 4.9 MW 21.9 MW T 22.8 Mvar
A 0.1 Mvar 1.2 Mvar $p�J _
Tf
Mvar $I V Fo 1.012 W ....
ft16 W 1 H u 1Yao4 p�u
6.9 MW �yr 8.6 MW y-Mvar
0:1 Mvar T 3 MW 0.2 Mvar HANGMAN
0.var 1.011 pu
5 Mva
O M FO�I�LBPA
var
4.7 MW 8.2 MW
0.1 Mvar 0.2 Mvar
Figure 11: Worst performing contingency, light spring 2029
3.4.3. Integration costs
Integration will require a new Avista 115kV POI station on the west edge of the West
Plains 115kV system.
Cost
POI Station or Area -
million)Point of Interconnection Station
New 115kV Espanola Station-property, termination, comms and metering 9.1
Loop-in Airwa Heights-Silverlake 115kV into POI Station 0.6
PrMffcts MeRNWto mitigate violation t 50M
None 0
total 9.7
Projects necessary to mitigate news stem violations at 100MW
Rebuild Hallet&White-Silverlake 115kV fix 3.4mi 4/Oacsr 3.1
total 12.8
Table 11: Generation integration estimate
Estimates assume that the Interconnection Customer will be responsible for the lead
line up to the change of ownership, which is a dead-end tower at the POI Station.
Page 17 of 40

IRP Generation Integration Study I 2024ppendix E
3.5. Lewiston/Clarkston Area
3.5.1 . Project description and one-line diagram
The following evaluates the impacts of integrating 100 to 30OMW of new generation
onto Avista's transmission system in the Lewiston/Clarkston area. This request was
modeled as a new 230kV line position at the Lolo Station as shown below.
IP- - ATW
N1.038 w
1
AQ2214_MTI A92214_ESI 1 T
�190NW oNw 1 ` w NIEWISr Lewiston Clarkston Area
13 MMr Il Mwr 1 1 1.012p
AQ2214_W72 AQ2214_ES2 1 _
13 1 MW L�l ONW 6].]MW
13 13 Mvx 1
1 EIFARMAi M E]FARWATER-E
Y♦ f1AR167M 1 MI1 Nwr _ 1.000 pu 1 000 W
1.013gr 1 1 Mwr '
MW 54 MW 2Z714— CLEARWATER
rr M -l6IIVA/ 1.03,.
4.6 1
1.5 NvM'ar 1--'A IA0 1122� f0 MIN —0 25 M.W,
ORYGULCH 60 MW/_^l]MVWar
OArIw/QR RdEROTR 1 1.021 W 1.010 M `.•�,
4.IMW 35MW 1 ■I 009p R CRAMMNT
. 1L0 X
IA MWr 0.0 Mvar I 9MW IEWNRLROAD SVILLDW
0.2 Mrs 1 L4 1MW 1.008 SMW� l.7 01
' L2 52 2AMW IMgr OR..S
®]NsooMw
' Q1997 w
0R9OIEEK 1.010"IX +,y 100NW
I.M.1042 L010 W S1.W LpR O Mvs
901NIDLNE 1.006 ou 1.010 W LOLO
1 •.. 1 1.00]uu.. ���ppym N I.Olbw /1Q19970MW 007T
24 MW 69Mar MMW ~ 3. 0.999 q;
3WMW1 75A 111N - RMver 1]Mver
I Mrarl 06 MW — N NM 1
01N 9N N
1 AQ1N00_RV S1.i MM
b Mn, 1 ]I Mvai �—311.ar14
1 Mvar
Figure 12: New generation at Lolo 230kV, heavy summer 2029
System performance in this area is dominated by several factors:
• High ID-NW transfers south in late spring and early summer. Idaho Power
manages ID-NW flows and will insert line reactors or redispatch generation to
mitigate overloads on the Lolo-Oxbow 230kV line.
• Large wind penetration to the west around the Walla Walla and Wallula load
centers.
• Existing local generation (behind the meter 48MW) from Potlatch Forest
Industries.
• New renewable generation at Dry Creek (375MW Wind/BESS on-line in 2026).
• The Longhorn - Hemingway 500kV modeled in-service in 2026.
In general, new generation in this area will sink into local load. As the local load service
is met the additional power will flow south into Idaho, west into southeast Washington or
up onto BPA's 500kV system at Hatwai.
3.5.2. Contingency Analysis
The worst system performance was during heavy summer conditions with high north to
south ID-NW transfers. The issues identified below can be mitigated by adjustments to
ID-NW flows. The spring and winter scenarios did not identify any issues.
I 1 1 I
HS
damb Base IDOMWii 0
Page 18 of 40

IRP Generation Integration Study 202O,ppendix E
N-1:Brownlee-Hells Canyon 230kV
Lolo-Oxbow 230 kV(Lola-Imnaha) I 95.7 I 97.4
N-1:Hemingway-Longhorn HOW
Lolo-Oxbow 230 kV(Lola-Imnaha) I I 96.1 I 97.8 I 99.5
T-1:Bell#6 230/115kV
Beacon-Bell#1115 kV I 103.2 I 103.6 103.9 I 194.3
Beacon-Northeast 115 kV I I F95.1
OF:BEA A60D,Beacon North 5 South Bus Tie
Francis and Cedar-Northwest 115 kV I 102.8 102.5 102.3 I 102
Northwest -WEstside 115 kV 101.3 101.1 100.9 I 100.7
OF:BELL A370,Bell S19 S2 230kV
Beacon-Bell#1115 kV 100.6 101 101.3 101.7
OF:BELL A388,Bell S2 6 S3 230kV
Beacon-Bell#1115 kV 96.4 96.8 97.3 97.8
OF:OLD A713,Boulder-Otis Orchards#1
Boulder-Irvin#2115 kV I 95
BUS:Bell S2 230kV
Beacon-Bell#1115 kV I 101.4 191.7 102.1 102.5
BUS:Boulder West 115kV
Boulder-Irvin#2115 kV I 95.3 96.5
N-2:Brownlee-Hells Canyon 230kV 5 Brownlee-Oxbow#123UkV
Lolo-Oxbow 230 kV(Lola-Imnaha) I I 95.5
Table 12: Contingency results, heavy summer 2029
The worst performing contingency is the loss of both the Long Horn - Hemingway
500kV Transmission Line (N-1) shown below.
1
IA38 PU
1oil
1
la_WFI AQ2211 ESI 1 N1mp5T
13 3"W 1 "012PU Lewiston Clarkston Area
219_WT2 AQ2219_ES2 1 I.Ol2 w
190 MW 1-"�OMW 1 69.7 MW
13 Mvar 13 Mvx
1 MI MnL OLEMOW IN
CIFARW�TER_E
CIARKSIN 1
1.013 i S MIN
22J NW7 A.CIEARW
OA NvaE -15 Mv9f 1.031 w
ab NW
IS NWa' 1 NOIBROOK _028MW
1.012 pu 961h ��'J 25 W W
1 ORYC#RCN ORLON 9 MW 22�
YTNPPL POMEROVP 1 IA21 pu IA1Ow 3MVY
INS
i.a Mvar o.e M 1 3A MW 6 MW 1.009
w
43 MW 1 3 LEWNILLROAD SPALDIN:
0.2M dr OA 1.00]w 1.008 p0 3MW
1 01 I Mw
1 12.2 MW 2.8IINI 2NW
3.5 0.7 I NYRE
2B5.10 MW 1 '�
AQ1997_w
1 ID VC2REEK pu IORVCREEK *7 SIEWIST LOlOiM-var
1-n10Om.
OMW
1 PWNOME I006W TENTKSIW 1.010 AQ1997_ES
t_006N 1N w - 2SNW19 MW ,�lNVY]19 MW 2aMW 6NPa139 MW33 NVW l 2 MW >ZCRCHrEID0.6 Mvar 1A1O w50MW3M�a1 1O
Figure 13: Worst performing contingency, heavy summer 2029
3.5.3. Integration costs
The Lolo Station has a 230kV double breaker double bus arrangement with space for a
new line position.
Page 19 of 40

IRP Generation Integration Study 2024ppendix E
P01 Stationor `
•Point of Interconnection Station _
New 230kV position at Lolo Station 1.9
Projects necessary to mitigate new system violations at 100/200/30OMW
None 0
total 1.9
Table 13: Generation integration estimate
Estimates assume that the Interconnection Customer will be responsible for the lead
line up to the change of ownership, which is a dead-end tower at the POI Station.
3.6. Lower Granite Area
3.6.1 . Project description and one-line diagram
The following evaluates the impacts of integrating 100 to 30OMW of new generation,
north of Lower Granite Dam, onto Avista's transmission system in the Palouse area.
This request was modeled as a new 230kV line position at Shawnee Station as shown
below.
111,1E_WSU 7EA�VIEW N M�W
YMI�MPp RSTP SMAWNEE , IL
MOSCOW
1 1.036 pu •• .-... 12A MW 1.009 Pu MOSCOW
_ 289 MW F. MW 35 Mvar Moscow
pu
1 CH
, �',� '.� 9.5 Mwr 2.7 M1
M."1 Pub 132.2NW �
1.5 MW , SMAWNEE ��+ 18.6 MW
OS MWr 1.015 011
-, 1.11 pu 1. pu . F 34.1 M-1
I nil MW
2A MW
_ _ - - - - - - - 1MO�M 0.7 Mvx
AVAHubGranite 1 o.7 MW 76.2 MIN 4.9 MW
1.090pu 1 n-1 Mv.0 &5"M 1.3MM
LOW GRAN 33 MW 1 1
1 OAO pu 11 i
1 2"MW
_ 93 N--
1
Figure 14: New generation near Lower Granite flowing into Shawnee, heavy summer 2029
System performance in this area is dominated by several factors:
• System flows are typically north to south.
• Existing local generation (104 MW) from Palouse Wind.
In general, new generation in this area will sink into local load. As the local load service
is met the additional power will flow south into the Lewiston/Clarkston load center.
3.6.2. Contingency Analvsis
The worst system performance was during heavy summer conditions with high north to
south ID-NW transfers. The issues identified below can be mitigated by adjustments to
ID-NW flows. The spring and winter scenarios did not identify any issues.
�I� I U1M
WE Brownlee-Hells Canyon 230kV
Lola-Oxbow 230 kV(Lola-Imnaha) I 95.8 I 96.7
Page 20 of 40

IRP Generation Integration Study 202O,ppendixE
N-1:Hemingway-Longhorn HOW I F-]
Lolo-Oxbow 230 kV(Lola-Imnaha) I 95.4 96.3 97.3 I 98.2
T-1:Bell#6 230/115kV
Beacon-Bell#1115 kV I 103.1 103.7 104.2 I 104.E
Beacon-Northeast 115 kV I 95 95.5
OF:BEA A600,Beacon North 6 South Bus Tie
Francis and Cedar-Northwest 115 kV 102.9 102.4 101.9 101.4
Northwest -Westside 115 kV 101.4 101 100.6 i 100.2
OF:BELL A370,Bell S16 S2 230kV
Beacon-Bell#1115 kV 100.5 101.1 101.E I 102.3
OF:BELL AM,Bell S2 6 S3 230kV i
Beacon-Bell#1115 kV I 96.2 97 97.7 9B.5
OF:OLD A713,Boulder-Otis Orchards#1
Boulder-Irvin#2115 kV 95.8 98.1
BUS:Bell S2 230kV
Beacon-Bell#1115 kV 101.3 101.8 102.4 I 103
BUS:Boulder West 115kV
Boulder-Irvin#2115 kV 97.2 I 99.5
N-2:Brownlee-Hells Canyon 230kV 6 Lob-Oxbow 230kV
MCNRY SI(41351)->ROUNDUP(40905)CKT I at ROUNDUP 96.5 96.5 96.5 96.7
Table 14: Contingency results, heavy summer 2029
The worst performing contingency is a loss of both the Benewah - Thornton 230kV and
North Lewiston - Shawnee 230kV Transmission Lines (N-1-1) forcing all the 230kV
connected generation through the underlying 115k system as shown below.
TURN U TFF;RV��"' NMOSCOW
0.996
R1.002 p,
k
iAor10 pu�� TURN
1.031 w
12.o M 1.009 p0
25. 9. 3.3
1 Moscow
9.5 H- 2.7 My r 1.012 pu
AMBERS1.010 pu SH WNEE 17orA za.a Mwar 1.011 pu ARMS + SPULLh
1.0 .99d 34.1r
9 FIW
OSCITYI 0.7 NIN
004 p o.7 M.ar
AVAHub(i,,tel 0.7 "26.2 1.9IIw
1.090 pu 0.2 r 1- 8.5 r-1- 13 Near
LOW GRAN 300I W 1.00J pu Y
1 O30 p� 36 M-1
1
29.7 NW
Figure 15: Worst performing contingency, heavy summer 2029
Generation would have to be curtailed during an outage of either of these 230kV
transmission lines.
5.6.3. Integration costs
The Shawnee Station has a 230kV main/aux arrangement with space for a new line
position and will also require a new 230kV auxiliary circuit breaker for reliability.
Page 21 of 40

IRP Generation Integration Study 2020,ppendix E
Cost
P01 Stationor Area Estimate
Point of Interconnection Station million)
New 230kV line position and aux breaker at Shawnee Station 2.9
Projects necessary to mitigate new system violations at 100/200/30OMW
None 0
total 2.9
Table 15: Generation integration estimate
Estimates assume that the Interconnection Customer will be responsible for the lead
line up to the change of ownership, which is a dead-end tower at the POI Station.
3.7. Palouse area near Benewah (Tekoa)
3.7.1 . Project description and one-line diagram
The following evaluates the impacts of integrating 100 to 20OMW of new generation
onto Avista's transmission system in the northern Palouse area, west of Plummer,
Idaho. This request was modeled as a new 230kV line position at Benewah Station as
shown below.
These results are similar for the request at Tekoa, given this location is withing 10 miles
of Benewah Station.
ROCKFORD SETTERS
_ HOPKINS# r.111 n 1.002 pu 1.000 pu
� 0.999 u pu 9.0 MW
. - : ].8 Mvar
2 MW 1.4 MW
1 Mvar 1.0 Mvar 1.6 MGI
0.�MW
10.0 Mvar
LATAH NENE p
P.
1.011 1.040 pu
f * � p
L214W N 200 MW
0.6 Mwr n -18 Mvar
0 BENEWAH
TH00.NTON 1.014 pu
1.038 pu
',..104 MW010 pu
1 War
2.1 MW
0.5 Mv.0
Figure 16: New generation at Benewah, heavy summer 2029
System performance in this area is dominated by several factors:
• System flows are typically north to south.
• Existing local generation (104 MW) from Palouse Wind.
In general, new generation in this area will sink into local load. As the local load service
is met the additional power will flow south into the Lewiston/Clarkston load center.
3.7.2. Contingency Analysis
The worst system performance was during heavy summer conditions with high north to
south ID-NW transfers. The issues identified below can be mitigated by adjustments to
ID-NW flows. The spring and winter scenarios did not identify any issues.
r r 29HS
Page 22 of 40

IRP Generation Integration Study 2020,ppendix E
N-1:Hemingway-Longhorn HOW
Lolo-Oxbow 230 kV(Lola-Imnaha) I 95.4 95.9 96.5
T-1:Bell#6 230/115kV
Beacon-Bell#1115 kV I 103.1 104 105
Beacon-Northeast 115 kV I 95.6
OF:BEA A600,Beacon North 6 South Bus Tie
Francis and Cedar-Northwest 115 kV I 102.9 102 101.1
Northwest -Westside 115 kV I 101.4 I 100.7 100
OF:BEA R427,Beacon Bus Tie
Boulder-Irvin#1115 kV(Boulder-Spokane Industrial Park) 95.9
OF:BELL A370,Bell S16 S2 230kV
Beacon-Bell#1115 kV 100.5 101.4 102.4
OF:BELL AM,Bell S2 6 S3 230kV
Beacon-Bell#1115 kV 96.2 97.4 98.7
OF:OLD A712,Boulder-Irvin#1
Boulder-Irvin#2115 kV 96.4
OF:OLD A713,Boulder-Otis Orchards#1
Boulder-Irvin#2115 kV 95.5 99.8
BUS:Bell S2 230kV
Beacon-Bell#1115 kV 101.3 102.2 103.2
BUS:Boulder West 115kV
Boulder-Irvin#2115 kV 97 101.3
Table 16: Contingency results, heavy summer 2029
The worst performing contingency is shown below. This is a N-1-1 loss of the 230kV
lines going south from Benewah and Thornton forcing all generation north without issue,
showing the system would be capable of absorbing the full output of the proposed
generation.
q MICA ROCORD 1. pu
pu ea�u P� SFJETERS
as Mw
W2.6 Mvar
2MW .S.o MW
1!Ivor 1 1.4 Mvar FOA:
b.4 M.
.._ 0.0 Mvar
p BEMEWAH
1.O1l�pu 1.040 pu
2.2 MW r1 200 MW
0.6 Mvar n -13 War0
N
THORNTON .M14wpuAH
104 MW UOOA.
I-Vl-1 Mvar J1�
2.1-
0.5 Mvar
Figure 17: Worst performing contingency, heavy summer 2029
3.7.3. Integration costs
The Benewah Station has a 230kV double breaker double bus arrangement with space
to terminate a new line position.
Page 23 of 40

IRP Generation Integration Study 2020,ppendix E
Cost
P01 Stationor Area Estimate
Point of Interconnection Station million)
New 230kV line position at Benewah Station 2.4
Projects necessary to mitigate new system violations at 100/20OMW
None 0
total 2.4
Table 17: Generation integration estimate
Estimates assume that the Interconnection Customer will be responsible for the lead
line up to the change of ownership, which is a dead-end tower at the POI Station.
3.8. Rathdrum Prairie
3.8.1 . Project description and one-line diagram
The following evaluates the impacts of integrating 100 to 40OMW of new generation
onto Avista's transmission system in the Coeur d'Alene area east of Rathdrum, Idaho.
This request was modeled as a new station approximately 0.5 miles south of Lancaster
Station on the Boulder - Lancaster 230kV Transmission Line as shown below.
�100 MW 5gRCELO 0.3
1 M12r
1-4 43 Mvar 1.013 pU
yl 70 MW
79 MVar LAncAm
1.040 V 11A MW
ow Mvar
-K
- - � - << - < - - �- - •- <
'- Ph o Hd RATHORUM
6�Y 1.040 pU
gpuL 0MW W
1.ffi ER q oMvar l.ow
D M ar OMW o W.
9
CJ OM ar 0"M 40 RATHDRMW •1 1 RATHURME
1.015 P.
B 9 q o M ar
���� OMW TttO 5.3 MW 3AMW 2.9 MW
RW 2 2 a 0 War 0 MW 2 0.1 NVar 0A MVar Q0
q OMW PLEASANT 0 Q 7514W 75 MW
4 MW 0 War ��'MOM PPPVVV 1.015 Pu IDAHO_RD c 4 MVar 4 Mvar
0 ^V S 1.016 pu
MUETTER
2.0 MW SA MW 011 MW 1.017 pu
OA MVar 0.1 Mvar 0.1 Mvar HAYDEN
1.015 pu
Q OA MVOT 0.1 Mvar AVONDALE
BA�61r!z A 0.7 Mvar 1.016 PV
6.2 MW
0.1 MVar
0.1 MVa
Figure 18: New generation at 230kV near Lancaster, light spring 2029
System performance in this area is dominated by several factors:
• High transfers from the east on the Cabinet — Rathdrum and Lancaster— Noxon
230kV transmission lines during spring runoff.
• Typical outflows to the west on the Beacon — Rathdrum, Bell — Lancaster, and
Boulder— Lancaster 230kV transmission lines.
• Load in the Coeur d' Alene area primarily served from the Rathdrum station.
• Existing local generation (440MW) from Boulder, Lancaster, Post Falls, and
Rathdrum stations.
In general, new generation in this area will sink into local load. As the local load is met
the additional power will typically flow west into the Spokane load center or further west
on BPA's 230kV system and up onto BPA's 500kV system at Bell.
Page 24 of 40

IRP Generation Integration Study 2024ppendix E
3.8.2. Contingency Analysis
Worst system performance was during light spring conditions with high east to west
transfers and during heavy summer conditions. Outages on the 230kV system results in
overloads on the underlying 115kV system, as shown below. The winter scenarios did
not identify any issues.
Many of the summer overload conditions are present with or without the added
generation, due to isolation from P2 outages at Rathdrum. Mitigation for these issues is
not included in the Network Upgrades and are shown here for reference only.
S
N-1:Boulder-Greenfry 230kV
Boulder-Rathdrum 115kV(Pleasant-Idaho Rd) I 98.9
BF:BEA R427,Beacon Bus Tie
Boulder-Irvin#1115 kV(Boulder-Spokane Industrial Park) 101.1 1013.6 1 112.1 117.5 I 123
BF:BLD R454,Boulder-Greenfry,Boulder#2 230/115
Boulder-Rathdrum 115kV(Pleasant-Idaho Rd) 95.1 100.5
OF:BLD R554,Boulder-Greenfry,Boulder#1230/115
Boulder-Rathdrum 115kV(Pleasant-Idaho Rd) 95.1 100.5
BUS:Beacon South 230kV
Boulder-Irvin#1115 kV(Boulder-Spokane Industrial Park) 96.8
N-2:Beacon-Boulder 230kV 6 Beacon-Rathdrum HOW
Boulder-Irvin#1115 kV(Boulder-Spokane Industrial Park) 96.6 102.E 108.E 114.7 120.7
N-2:Beacon-Boulder 230kV 6 Boulder-Irvin#2115kV
Boulder-Irvin#1115 kV(Boulder-Spokane Industrial Park) 102.5 108.2 I 113.9 119.6 125.4
N-2:Beacon-Rathdrum 230kV 6 Boulder-Greenfry 230kV
Boulder-Rathdrum 115kV(Moab-Pleasant) 100.5 109.2 I 118 126.7 135.5
Boulder-Rathdrum 115kV(Boulder-Moab) 98 106.7 115.4 124.2 132.9
Boulder-Rathdrum 115kV(Pleasant-Idaho Rd) 106.8 115.E INN 133.1 141.9
Post Falls-Ramsey 115kV(Post Falls-Prairie) 95.7 1 103.4 111 118.7
Boulder-Rathdrum 115kV(Idaho Rd-Rathdrum) 100.E 107.3 114.1
Post Falls-Ramsey 115kV(Prairie-Ramsey) I 99.6 105.5
Otis Orchard-Post Falls 115 kV(Beck Road Tap-Post Falls) I I I 9G 102.E 109.3
LANCASTR(40624)->BELL SS(40090)CKT 1 at LANCASTR 96.8 106 115.2
N-2:Beacon-Rathdrum 230kV 6 Lancaster-Rathdrum 230kV
Boulder-Rathdrum 115kV(Moab-Pleasant) 103 191.9 190.8 99.7 98.6
Boulder-Rathdrum 115kV(Boulder-Moab) 100.5 99.4 98.3 97.2 96.1
Boulder-Rathdrum 115kV(Pleasant-Idaho Rd) 109.3 108.2 107.2 106.1 105
Table 18: Contingency results, light spring 2029
The worst performing contingency is shown below. This shows the underlying 115kV
system overloaded for the double-circuit outage.
Page 25 of 40

IRP Generation Integration Study I 2024ppendixE
"s OMvar � RATHDRMW 1 1
0 Mvar
'..fA Ev r
DEHW -6 -6 .LDERE �+ 0 T' 5.3 MW 3.8 MW 2.9 MWp00 f 0 MW E 0.1 Mvaf OA Mvaf OA Mva0 PLEASANT 0 Mvaf , o
4NWMvar MOAB 1.015 pu IDAHO_RD c
O Mvar 1. I S 1.017 pu
HUETTER
2. 5.0 6.7 MW 1.018 P.
0.0 0.1 My 0.1 Mvaf HAYDOI
1.9 MW 6A MW 1.Ol7 pu
0:0 Mvaf 0.1 Mvar
BARKER *00.71
MW
L 101
6.6 'W
I WOD -0.1 Mvar
pu
ly oils
p0 EA$�E M BECgLOAD POS 5 WS PRAI7R�E 44 M.
AY IPA: J.
0.0 Mvar p W 5.3 _ 8.5 1
0.1 Mvar 0.1 Mva 0.2 My
Figure 19: Worst performing contingency, light spring 2029
These overloads can be mitigated by rebuilding the underlying 115kV or by building a
new 230kV transmission line. The 115kV mitigation was explored in the 2021 IRP
analysis, which mitigated the issues, but resulted in little margin. The 230kV mitigation
resulted in larger contingency margin and reduced the total rebuild scope.
3.8.3. Integration cost!
BPA's Lancaster Station is a 230kV ring-bus arrangement and is not designed to be
expanded. Integration will require a new Avista 230kV POI station west of BPA's
Lancaster station.
Cost
POI Station or Area
•Point of Interconnection Sti taon
New 230kV 3 position Greensferry Station 18.8
Loop-in Beacon-Rathdrum 230kV into POI Station 1.4
Projects necessary to mitigate new facility violations at 100MW
Rebuild Boulder-Irvin#1 115kV BLD-SIP, fix 1.2mi 556aac 1.1
Rebuild Boulder-Rathdrum 115kV fix 11.2mi 250cu, 337acsr&556aac * 10.1
Rebuild PostFalls-Ramsey115kV PF-PRA,fix 2.9mi 250cu * 2.6
total 34.0
0/4
Rebuild Boulder-Irvin#1 115kV BLD-SIP, fix 1.2mi 556aac 1.1
Build new Boulder-Greensfer 230kV SCT new 13.3mi ROW&structures 31.0
New 230kV position at Boulder Station 1.6
total 53.9
Table 19: Generation integration estimate
Estimates assume that the Interconnection Customer will be responsible for the lead
line up to the change of ownership, which is a dead-end tower at the POI Station.
3.9. Sandpoint Area
3.9.1 . project description and one-line diagram
The following evaluates the impacts of integrating 50 to 150MW of new generation onto
Avista's transmission system in the Sandpoint area. This request was modeled as a
new 115kV line position at the Bronx Station as shown below.
Page 26 of 40

IRP Generation Integration Study I 2024ppendix E
7.1 MW 5.B MW
2.3 Mvar 1.9 M 2.4
SAMUELS+ 0.81
SEEEE• 1.018 Du
t.ate pp
DR�ST RVR
008 J CRK DRIESTAVA= DONDERAY+1.016 Du 7MWvar
2 M 12.]1MW �12.3 Mvar
0.1 Mvar 12.3
AL IF - PRIEST AV"T DRIEST RVRO Mvar
1.011 Du 1 1.009 pu LACLEDE+
1.010 Du SANDDOOrt
79MW 0.0 Mvdr
2.5 Mvar
I 14 MW
q 1 Mar DOPER Nll
14 MW1.OlSpu SANDDTA BROII% ODEN
I Mvar
^ 3A MW
O
.q M
OMW
1.1 Mvx
r "^
1 0.6 5.4 MW t4.0 MW
SAGLF Flvar 0.0 My
MW
' 12 MVY DIROORN
54 MW 1.007 DD
0:1 Mvar
34 NW,
0:0 MWr
y DUFORT
1.014 pu CABOORO
1.004 Du 1.033 W
M RO 1. MW
100000 0.0 Mv 'CAN ORO, 4y 65
MMIW
11.010 W 3.010 Du 1.0 55lY
-7 2.1 MW 3.0 M41r 1.3 M .r, 6 MVar
0.0 MVM 0.0 Mvar 0.0 M 34 MW 1 M 6"MW
Figure 20: New generation at Bronx, light spring 2029
System performance in this area is dominated by several factors:
• East to west 115kV flows during spring runoff.
• Sandpoint area load ranges between 62MW and 225MW.
• Existing local generation (36MW) from Smith Creek Hydro.
In general, small levels of generation in this area will sink into local load. As the local
load service is met the additional power will flow south into the greater Coeur d'Alene
area. Larger generation integration impacts the total Western Montana Hydro Complex
output, which is limited by a West of Lancaster constraint.
3.9.2. Contingency Analysis
The worst system performance was during light spring conditions with high South of
Boundary transfers.
Row Labels Base 50MW 0O
N-1:Bell-Sacheen 230kV
Addy-Pine Street 115 kV Newport-Pine Street 101
N-1:Bronx-Cabinet 115kV
SANDPOINT(40931)->LACLEDE+(40617)CKT 1 at SANDPOINT 98.2
N-1:Cabinet-Rathdrum DOW
SANDPOINT 40931 ->LACLEDE+ 40617 CKT 1 at SANDPOINT 95.7
N-1:Sand Dunes-Warden 115kV
WARDEN A 48455 ->WARDEN T 46117 CKT 1 at WARDEN A 96.6 96.7 96.7 96.8
W
BF:CGS A219,Bronx-Cabinet
SANDPOINT(40931)->LACLEDE+(40617)CKT 1 at SANDPOINT I I 98.2
BF:RAT R403,Cabinet-Rathdrum,Rathdrum#2 230/115
SANDPOINT 40931 ->LACLEDE+ 40617 CKT 1 at SANDPOINT 96
BF:RAT R503,Cabinet-Rathdrum,Rathdrum#1 230/115
Page 27 of 40

IRP Generation Integration Study 2024ppendixE
SANDPOINT 40931 ->LACLEDE+ 40617 CKT 1 at SANDPOINT I I 95.9
N-1:Bell-Sacheen 230kV Open @ BELL
Addy-Pine Street 115 kV(Newport-Pine Street) I I 99.5
N-1:Cabinet-Rathdrum 230kV Open @ CAB
SANDPOINT(40931)->LACLEDE+(40617)CKT 1 at SANDPOINT I I 95.7
N-1:Cabinet-Rathdrum 230kV Open @ RAT
SANDPOINT 40931 ->LACLEDE+ 40617 CKT 1 at SANDPOINT 95.6
Table 20: Contingency results, light spring 2029
The worst performing contingency is shown below.
PRIESI_RVR t1.02
CRK
1.012 pu pu
VRFSf AIT PO11DERAVt
1.0 pu 1 7MW 12.4 ANar
�}�2 MM
S.B MW / .• 12A r4var
0.1"M �F/
null ST IEWPORT11 VO 1p F �AVM MOE4f_RNII 0.0 War
'...trip OMOR
Olt pu 1.014 pV I 1.013 pu 1AOLEDpEyt
2. 2A �
1\ SAM
0.4 0.8 Mwr 7.9 IIYr 0.0 Mvx
2.9 Mwr 1
OIOTOV M • -L:J 0MVW DOVEILRII
I.Ol2 pu 1 14 NW �1.01 pu F A BRdOf2.0MW <- OMvar p;,0.0 Mvar 1 3.4 MW _2.8 MW �.�1 O MW 1.1 Mwr 0.0 MvaF 1 LJJ 0Mvar .4 FIW
6 Flvar
1 1.018 pu �
-15 M var
0.1 MW
/'\0. M
(`�'1 DIIFORT
1.018 pu
Figure 21: Worst performing contingency, light spring 2029
3.9.3. Integration costs
The Bronx Station has a 115kV single bus arrangement but is planned to be rebuilt. The
rebuild will have space for a new line position.
Cost
POI Station or Area Estimate
Point of Interconnection Station million)
New 115kV line position at Bronx Station w/ metering &termination str 1.6
P MW
Assumes overloaded line section will be rebuilt as planned 0.0
total 1.6
PrUJMIS MWERRYTIo mitigate TMWmJ7stem violatio 100/15OMW
Build new Boulder-Rathdrum 230kV SCT new 17.8mi ROW&structures 41.5
New 230kV position at Boulder Station and Rathdrum Station 3.2
total 48.2
Table 21: Generation integration estimate
Estimates assume that the Interconnection Customer will be responsible for the lead
line up to the change of ownership, which is a dead-end tower at the POI Station.
Page 28 of 40

IRP Generation Integration Study 2024ppendix E
3.10. West Plains Area
3.10.1 . Project description and one-line diagram
The following evaluates the impacts of integrating 100 to 30OMW of new generation
onto Avista's transmission system in the West Plains area. This request was modeled
as a new 230kV line position at planned Bluebird Station as shown below.
y PBWNRIVER 12.51
r BLUEBIRD �1.007 pu
1.EBI D
2.5 MW
i 0.5 War
300 M W
r -65 War
D&DALN
E�T3 13&7 MW p 5T
4 M r FLINT RD 1To0)pu
1.012 W
T 7
.. 21.6 MW lr�� V
f 6.8 Mvar L J l J
f5YJAYHT 3 MW 5 MW
uta Du 1 Mary KWASTE 1 War 1 Mva
1.01 pu
T 2.4 MW 21.4 MW 16 MW �METROp��L 34.4 Mvar 0.7 Mvar 6.7 Mvar 1 -2 Mvar F.612CH LD - GAR"'NSP3312:1 Mvar4. var
•� 1 o � o
F.spanob FAIR
1�W o o GA.E SP SDlM W
9.9 MW 1 685 Mvar
Figure 22: New generation at Bluebird, heavy summer 2029
System performance in this area is dominated by several factors:
• 230kV integration primary flows into the West Plains area.
• West Plains area load ranges between 77MW and 160MW.
• Existing local generation (18MW) at Waste to Energy.
In general, new generation in this area will sink into local load. As the local load service
is met the additional power will flow east into the greater Spokane area.
3.10.2. Contingency Analysis
The worst system performance was during heavy summer conditions. The issues
identified below result from moving power from the West Plains into the downtown
Spokane load center. The spring and winter scenarios did not identify any issues.
;.se 1iiMW 20OMW 30OMW
N-1:Sand Dunes-Warden 115kV
WARDEN A(48455)->WARDEN T(48117)CKT I at WARDEN A 96.9 9G.9 9G.9 9fi.9
OF:BEA R427,Beacon Bus Tie
Boulder-Irvin#1115 kV(Boulder-Spokane Industrial Park) 101.1 99.2 97.3 95.3
N-2:Beacon-Boulder 230kV G Beacon-Rathdrum 230kV
Boulder-Irvin#1115 kV(Boulder-Spokane Industrial Park) 96.6
N-2:Beacon-Boulder 230kV G Boulder-Irvin#2115kV
Boulder-Irvin#1115 kV(Boulder-Spokane Industrial Park) I 102.5 100.5 90.6 I 9G.G
N-2:Beacon-Rathdrum 230kV G Boulder-Greenfry 230kV
Boulder-Rathdrum 115kV(Moab-Pleasant) 100.5 99.0 99.1 98.4
Page 29 of 40

IRP Generation Integration Study 202O,ppendix E
Boulder-Rathdrum 115kV(Boulder-Moab) I 98 97.3 96.6 I 95.9
Boulder-Rathdrum 115kV(Pleasant-Idaho Rd) I 10B.8 I 106.2 I 105.5 I 104.8
N-2:Beacon-Rethdrum 230kV 9 Lancaster-Rethdrum HOW
Boulder-Rathdrum 115kV(Moab-Pleasant) I 103 102 101.1 I 100.2
Boulder-Rathdrum 115kV(Boulder-Moab) I 100.5 99.5 98.7 I 97.7
Boulder-Rathdrum 115kV(Pleasant-Idaho Rd) 109.3 108.4 107.5 I 106.5
Table 22: Contingency results, heavy summer 2029
The worst performing contingency is a loss of both the Bell - Bluebird 230kV and
Bluebird - Coulee 230kV Transmission Lines (N-1-1) forcing all the 230kV connected
generation through the underlying 115k system as shown below.
D� �IPRIVERBLUESUM
IRD
'
76.1 MW
7 300 MW 8.5 Mwr
-4 Mvar CO&hWALN
1. Du
d WEST PWNS 38.7 MW
1.015 pu 13.8 M_
4 MW -- PO'.
OST RT
.-�4 Mvar FLDrt RD 1 T
1.013 Du (yT�,)
.�, 61. MW `/
_ wiR�y� 6.a Mvar
b T:OISpuHT i SPKWASTE i IMMW�r i MIA
1.011 Du
T' 2A MW 71A MW 16 MW
2 Mvar 34.5 Mvar0.7 Mvar 6.7 Mvar ML009 W
Fly, HLD GARDENSP
1. 1 Du 1.033
16 MW
W
7. MW 4.9 Mvar
2.1 Nvar
- Q
FAIR 5 0 0 GARDENSP" SUNaSET
0IR :�i
5'a"Ola � 1.011 Du 1. 11 Pu
� Du
L 9.9 MW 35.3 MW T 68.6 Mvar
Figure 23: Worst performing contingency, heavy summer 2029
The area load and recent 115kV system reinforcements help to reliably transfer the new
generation into the Spokane load center.
3.10.3. Integration costs
The planned Bluebird Station has a 230kV double breaker double bus arrangement with
space for a new line position.
Cost
POI Station or Area
New 230kV line position at Bluebird Station 2.4
Projects necessary to mitigate new system violations at 100/200/30OMW
None 0
total 2.4
Table 23: Generation integration estimate
Estimates assume that the Interconnection Customer will be responsible for the lead
line up to the change of ownership, which is a dead-end tower at the POI Station.
Page 30 of 40

IRP Generation Integration Study I 2024ppendix E
4. Existing Generation Integration Sites
4.1 . Kettle Falls Station
1'.1 .1 . Project description and one-line diagram
The following evaluates the impacts of adding 50 to 100MW of new generation to the
existing Kettle Falls generation site. This request was modeled as a new 115kV line
position at the Kettle Falls Station as shown below.
REPUUH: COOK NM* KETUEA
1.000 Pu 1.00£Pu
G-o/viHe Area
11.B MW O.S MW A
3.9 Mvar 0.2 Mvar • SPIRIT
m—1 1.027 pu
• yi
?4EI. KETTLEIIV 1•y M1V W 1.017 pu 1.028 pu 0.0 Nvar
q
d 5.1 Mw 7.0 MWr�)63MW
1 MvaryT
0.1 Mvar 0.1 Mvar1MW0Mw 0 Mvar '1 Mvar 1$.8 War 13.8 War
0 MvaK)War 13.8 War
I
COLV AVA
1.013 Pu
GRIN
A,14.6 MW 1.013 Pu
` o.s Mvar • t <— — E'• — —<'- - - -<' -
4.4 MW ARDEN
04,
.1 Mvtj 1.013 pu
3804W ADOY_S
0:0 Mvar 1.038 pu
I . — . — . — . — _ _ _ — - _
METCHIP ADDY_H
i 1.032 pu
— t
G •.. T 0.0 Mvar
We PuS.1 NW W N
0.1 Mvar ADDY Pu
1.015
Figure 24: New generation at Kettle Falls, light spring 2029
System performance in this area is dominated by several factors:
• North to south flows on BPA's 230kV system and limited by the South of
Boundary cut plane.
• Integration primarily flows into the Colville and West Plains areas.
• Kettle Falls area load ranges between 46MW and 62MW.
• Existing local generation (74MW) from Kettle Falls and Meyer Falls.
In general, new generation in this area will sink into local load. As the local load service
is met the additional power will flow south into the greater Colville area.
4.1 .2. Contingency Analysis
The worst system performance was during light spring conditions with high South of
Boundary transfers.
1 2EILSp 29LSp
1 .1AMA"
5amw loomw
N-1:Addy-Colville BPA 115kV
Addy-Kettle Falls 115 kV(Colville-Greenwood) 95.9
Addy-Kettle Falls 115 kV(Greenwood-Kettle Falls) 112.E
N-1:Addy-Kettle Falls 115kV
Page 31 of 40

IRP Generation Integration Study 2024ppendixE
Colville-Kettle Falls 115 kV(Kettle Falls-Republic Tap) I 116.8
N-1:Kettle Falls Tap 115kV
Addy-Kettle Falls 115 kV(Arden Tap-Metchip) I I I 97.2
Addy-Kettle Falls 115 kV(Arden Tap-Orin) I I I 99.9
Addy-Kettle Falls 115 kV(Colville-Greenwood) I I I 113.3
Addy-Kettle Falls 115 kV(Colville-Orin) I I I 103
Addy-Kettle Falls 115 kV(Greenwood-Kettle Falls) I I I 132.4
Addy-Kettle Falls 115 kV(Addy-Metchip) I I I 97.1
I I
I OF:ADDY 01135,Addy-Bell 115kV
Colville-Kettle Falls 115 kV(Kettle Falls-Republic Tap) I I I 97.6
OF:ADDY 01137,Addy-Devils Gap 115kV
Colville-Kettle Falls 115 kV(Kettle Falls-Republic Tap) I I I 97.7
BF:ADDY 01145,Addy-Kettle Falls 115kV
Colville-Kettle Falls 115 kV(Kettle Falls-Republic Tap) I I I 115.9
OF:COLV WE,Boundary-Box Canyon-Colville BPA 115kV
Addy-Kettle Falls 115 kV(Colville-Greenwood) I I I 103.9
Addy-Kettle Falls 115 kV(Greenwood-Kettle Falls) I I I 121.7
OF:COLV B1768,Colville BPA-Kettle Falls 115kV
Addy-Kettle Falls 115 kV(Arden Tap-Metchip) I I I 96.3
Addy-Kettle Falls 115 kV(Arden Tap-Orin) I I I 99.1
Addy-Kettle Falls 115 kV(Colville-Greenwood) I I I 112.8
Addy-Kettle Falls 115 kV(Colville-Orin) I I I 102.2
Addy-Kettle Falls 115 kV(Greenwood-Kettle Falls) I I I 131.8
Addy-Kettle Falls 115 kV(Addy-Metchip) I I I 96.2
BUS:Addy 115kV
Colville-Kettle Falls 115 kV(Kettle Falls-Republic Tap) I I I 97.7
I -BUS-.Colville 115kV I I I
Addy-Kettle Falls 115 kV(Colville-Greenwood) I I I 103.9
Addy-Kettle Falls 115 kV(Greenwood-Kettle Falls) I I 121.7
N-I:Addy-Kettle Falls 115kV Open 9 ADD
Colville-Kettle Falls 115 kV(Kettle Falls-Republic Tap) 90.1
N-1:Addy-Kettle Falls 115kV Open 10 KET
Colville-Kettle Falls 115 kV(Kettle Falls-Republic Tap) I I I 116.7
N-1:Kettle Falls Tap 115kV Open IN COLV
Addy-Kettle Falls 115 kV(Colville-Greenwood) 104.5
Addy-Kettle Falls 115 kV(Greenwood-Kettle Falls) 122.4
N-I:Kettle Falls Top 115kV Open R KET
Addy-Kettle Falls 115 kV(Arden Tap-Metchip) 97.2
Addy-Kettle Falls 115 kV(Arden Tap-Orin) I I I 99.9
Addy-Kettle Falls 115 kV(Colville-Greenwood) I I I 113.4
Addy-Kettle Falls 115 kV(Colville-Orin) 103
Addy-Kettle Falls 115 kV(Greenwood-Kettle Falls) 132.5
Addy-Kettle Falls 115 kV(Addy-Metchip) 97.1
Table 24: Contingency results, light spring 2029
The worst performing contingency is shown below.
Page 32 of 40

IRP Generation Integration Study 2024ppendix E
REPUBLIC COOK MTN* KETTLE#
1.011 Du 1 O1Spu Colville._._.-F.�-._<-. Area
;413'98 *4
-MWr
War0.2 Mvar I SPIRIT
I 1.028 pu
KE 1. 1 Pu COLD 1.9 MW •\ .
1.017 pu � 1.031 pu 0:0 Mvar
pMW 7.0KW Mvar o.1 Twar ,}, o MW 10oMw0 OMvar 13Mvar 0.9 MO r 0 Mvar
LV AVA i W
1.013 pu b
i
146
GRIN
1.014
1.014
I r
1. AARD E N 7
-p u0 381.01
.;
i ADD Y_S
I"vMr 1.038 pu
_ _
_ — - — _ — - — _
ADDY-N
1.017 pu
GIFFORD 0.0 Ma1018 pu
50.1 ArD+DY
Figure 25: Worst performing contingency, light spring 2029
1.1 .3. Integration cost
The Kettle Falls Station has a 115kV single bus arrangement with space for a new line
position. Assumes communications and protection updates are completed at Kettle
Falls Station increasing the Colville — Kettle Falls 115kV Transmission Line to the
556ACSR rating.
Cost
P01 Station or Area Estimate
million)Point of Interconnection Station
New 115kV line position at Kettle Falls w/metering &termination str 1.6
Projects necessary to mitigate news stem violations at 50MW
Protection upgrades at the Kettle Falls A621 Tap position is complete 0.0
total 1.6
Projects necessary to mitigate news stem violations at 100MW
Protection upgrades at the Kettle Falls A621 Tap position is complete 0.0
Rebuild Add -KettleFalls 115kV Arden to KettleFalls,fix 19.3mi 556AAC 17.4
total 19.0
Table 25: Generation integration estimate
Estimates assume that the Interconnection Customer will be responsible for the lead
line up to the change of ownership, which is a dead-end tower at the POI station.
4.2. Northeast Station
4.2.1 . 'project description and one-line diagram
The following evaluates the impacts of adding 50, 100 and 20OMW of new generation to
the existing Northeast generation site. The 50 and 100MW requests were modeled as a
new 115kV line position at Northeast Station as shown below. The 20OMW request was
modeled as a new 230kV station sourced by a loop-in of the Beacon — Bell #5 230kV
Transmission Line.
Page 33 of 40

IRP Generation Integration Study I 2024ppendix E
BELL BVA
_ 1.018 pu
BEL --'^'---'� ----'->
SEW AP yy�1(1 L P.
1.008 P.
M 6
lO.b 3 017 pub
.0
3 Di3 pu
1 13 A
10.311W
Near 11
0 0
q 303
100 MW0.2 Mve
6W_ N
1.12 pu
p 1. 2 3 MWBEACON N
�� . I.007 pub 7.0 Mvar
f.07I pu
4" 'LYMS'MD 40
27.6 17.6 Mww 2
9.1 Mqr 35.904W 131 MW .,
RIVER 12.5
I.DiO pules 1.011 p
26.1 MW 2 p-25 NMI
6.5 H- Ill MW 6N-
42.711�p
1S.6 N- 21.5 MW BEACONS -25 MW
Figure 26: New generation at Northeast, heavy summer 2029
System performance in this area is dominated by several factors:
• Site is between the two primary sources for the Spokane area, which are Bell
and Beacon Stations.
• North to south flows during heavy summer.
• Loading on the 115kV line ranges between 24MW and 59MW
• Existing local generation (55MW) from Northeast CT's.
• Equipment at Beacon Station is approaching rating limits based on fault duty,
therefore large generation additions in this area may require a station rebuild.
In general, new generation in this area will sink into local load. As the local load service
is met the additional power will flow south into the greater Spokane area.
4.2.2. Contingency Analysis
The worst system performance was during heavy summer conditions with high north to
south flows.
I
HS
Row Labels Base 5OMWii2DOMW
N-1:Beacon-Northeast 115kV
Bell-Northeast 115 kV(Waikiki Tap-Northeast) 101.5
N-1:Bell-Northeast 115kV
Beacon-Northeast 115 kV 102.3
N-1:Hemingway-Longhorn 500kV
Lola-Oxbow 230 kV(Colo-Imnaha) I 95.5 I 95.6 95.7 95.8
T-1:Bell#6 230/115kV
Beacon-Northeast 115 kV 96.3
Bell-Northeast 115 kV(Waikiki Tap-Northeast) 104.1 120.2
Beacon-Bell#1115 kV 105.8
BE BEA A600,Beacon North 6 South Bus Tie
Francis and Cedar-Northwest 115 kV I 103 I 103 103 102.5
Northwest -Westside 115 kV 101.5 101.5 101.5 101.1
Bell-Northeast 115 kV(Waikiki Tap.-Northeast) 102.6
Page 34 of 40

IRP Generation Integration Study 2024ppendix E
BF:BELL AND,Bell Sl 6 S2 230kV I I 7-7
Bell-Northeast 115 kV(Waikiki Top.-Northeast) I I 104.5 119.7
Beacon-Bell#1115 kV I I I 102.8
BF:BELL A368,Bell S2 6 S3 230kV
Bell-Northeast 115 kV(Waikiki Tap-Northeast) I I 102.2 117.1
Beacon-Bell#1115 kV I I 99.4
OF:BELL 8356,Bell-Northeast 115kV
Beacon-Northeast 115 kV I I 102.2
BUS:Beacon North 115kV
Bell-Northeast 115 kV(Waikiki Tap.-Northeast) I I 101.8
BUS:Bell S2 230kV
Bell-Northeast 115 kV(Waikiki Tap-Northeast) I 104.5 119.9
Beacon-Bell#1115 kV I 103.6
N-1:Bell-Northeast 115kV Open R NE
Beacon-Northeast 115 kV l 102.4 I1
Table 26: Contingency results, heavy summer 2029
The worst performing contingency is shown below.
EVA
RevENrwv .1 w
-'---Y'-'-' - -'-'� ---'--Y
Marr
lAlOA w.OlO pu � 1.011 pu
Ms w
S 313 Mw
10.6 N— EAS E
l.O1J W 30.5
1�00 MMO.l Nw
1.1 pu
RE111.ON N
fZDR 1 O H— 1-7N�wr ,
46.0 Mw -LY( STND
9.1 Mv6r 163 MW�
9MW
ppyyN RIVER It s
MMW wJo �''�6 Nvar
11
11.5 MW BEACON 5 -15 MW
Figure 27: Worst performing contingency, heavy summer 2029
4.2.3. Integration costs
The Northeast Station has a 115kV single bus arrangement with space for a new line
position.
Page 35 of 40

IRP Generation Integration Study 2024ppendixE
Cost
P01 Stationor Area Estimate
Point of Interconnection Station at 115k million)
New 115kV line position at Northeast Station w/metering &termination structure 1.6
New 230kV 3 position Hanson Station 18.8
Loop-in Beacon-Bell#5 230kV into POI Station 1.4
Projects n iti iolations at 50MW
None North Spokane Reinforcement Project corrects overloads 0
total 1.6
Projects necessaryto mitigate news stem violations at OOMW
Rebuild Beacon-Northeast 115kV fix 5.25mi 556acsr 4.7
Rebuild Bell-Northeast 115kV fix 1.53mi 556acsr 1.4
total 7.7
Projects necessary to mitigate news stem violations at 20OMW
Rebuild Beacon-Bell 115kV fix 6.86mi 250cu &556aac 5.7
total 25.9
Table 27: Generation integration estimate
Estimates assume that the Interconnection Customer will be responsible for the lead
line up to the change of ownership, which is a dead-end tower at the POI Station.
4.3. Palouse Wind
4.3.1 . Project description and one-line diagram
The following evaluates the impacts of adding 100 to 20OMW of new generation to the
existing Palouse Wind generation site. This request was modeled as a new 230kV line
position at the Thornton Station as shown below.
ROCKFORD SETTERS -
HOSB' MICA 1 3.00
gICIN Du 1.001 Du
1.OUR� 1.000 Du .21 MW.8 Mrar
2 MW 5A MIN
1 Mvar 1.4 Mqr 1.6 HW
0.4 Mwr
y
0.0 Ma
BENEWAN
- �?�j►p /� 1.041 Du
2.2 NW OMW
104 MW i; 0.6 Mvar �47
n0My-2 M— BENEWAH
nKWJ1EON 1.015 Du
1.041 Du
TEl�lai lDu
200 MW 2A NI•
0 M_ OS
Figure 28: New generation at Thornton, heavy summer 2029
System performance in this area is dominated by several factors:
• System flows are typically north to South.
• Existing local generation (104MW) from Palouse Wind.
In general, new generation in this area will sink into local load. As the local load service
is met the additional power will flow south into the Lewiston/Clarkston load center.
Page 36 of 40

IRP Generation Integration Study 2024ppendix E
4.3.2. Contingency Analysis
The worst system performance was during heavy summer conditions with high north to
south ID-NW transfers. The issues identified below can be mitigated by adjustments to
ID-NW flows. The spring and winter scenarios did not identify any issues.
Row Labels0O20OMW
T-1:Bell#6 2301115kV
Beacon-Bell#1 115 kV 103.1 103.7 104.4
Beacon-Northeast 115 kV 95.1
BF:BEA A600,Beacon North&South Bus Tie
Francis and Cedar-Northwest 115 kV 102.5 101.9 101.2
Northwest-Westside 115 kV 101.1 100.6 100.1
BF:BEA R427,Beacon Bus Tie
Boulder-Irvin#1 115 kV Boulder-Spokane Industrial Park 95.3
BF:BELL A370,Bell S1 &S2 230kV
Beacon-Bell#1 115 kV 100.4 101.1 101.8
BF:BELL A388,Bell S2&S3 230kV
Beacon-Bell#1 115 kV 96.3 97.1 98.1
BF:BLD A713,Boulder-Otis Orchards#1
Boulder-Irvin#2115 kV 98.1
BUS:Bell S2 230kV
Beacon-Bell#1 115 kV 101.2 101.8 102.6
BUS:Boulder West 115kV
Boulder-Irvin#2115 kV 96.2 99.4
Table 28: Contingency results, heavy summer 2029
The worst performing contingency is a loss of both the Benewah - Thornton 230kV and
North Lewiston - Shawnee 230kV Transmission Lines (N-1-1) forcing all the 230kV
connected generation through the underlying 115k system as shown below.
B PEs
3A MW pp��p
OLA 0.9 Mrar 1.. PU
1.008 pu
1.7 MW 1.2 MW
N
u1 Frt�t Sao 1.3 H- 1.1 M-
Fe, i SU i 063 l a1a W W
.SH�WNEE ( _ MgSCOW
J1 12.0 MW 4••• l.bl�pu---
■ 1 5 9.5 M_ 2.7 M- 3s Mw 1 w Ep
1.0111
2.1 MW
SHAWNE 121A MW n.5 M.W
lAll pu -man
1. F 34.7 MW
2A MW
Q7 MWr
0.7 26.2 MW 1 W 4.9 MW
0.2"M 8.5 M- ' 1.3 MWr
��"Pa aTM JY.M ;T
28.7 MW 2.7MW 6.2 MW
9.5 M-r 0.7"- 1.7 MVW
Figure 29: Worst performing contingency, heavy summer 2029
Generation would have to be curtailed during an outage of either of these 230kV
transmission lines.
Page 37 of 40

IRP Generation Integration Study I 2024ppendix E
4.3.3. Integration costs
The Thornton Station has a 230kV ring bus arrangement with space for a one new
230kV line.
Cost
Pol Stationor
million)Point of Interconnection Station
New 230kV line position at Thornton Station 1.4
Projects necessary to mitigate news stem violations at 100/20OMW
None 0
total 1.4
Table 29: Generation integration estimate
Estimates assume that the Interconnection Customer will be responsible for the lead
line up to the change of ownership, which is a dead-end tower at the POI Station.
4.4. Rathdrum Station
4.4.1 . Project description and one-line diaaram
The following evaluates the impacts of adding 25, 50, 100 and 20OMW of new
generation to the existing Rathdrum generation site. The 25 and 50MW requests were
modeled as a new 115kV line position at Rathdrum Station. The 100 and 20OMW
requests were modeled as a new 230kV line position at Rathdrum Station.
The existing Rathdrum CT's use 140 MW of the available integration capacity on the
115kV portion of the Rathdrum Station, leaving only 60MW available per Avista's
interconnection standard. Both integration points are shown below.
100 MW
45 Mn LO 0.3 hrvm
1.013 pu
70 MW + '�'
30 Mrar IANCASTR 11.0 MW
1.040 0.4 MW
Ph—.t - RATHDRUM
ORW1.040 pu
OMvar 61.OW W
1.D E War
0MW i�•f 200 Mw
0 ar O, © 13 My A R
0 Mvar 0 Mvar 0 Mvar RATHDRUW ^•1 •1 RATHDRME
I.Ol6 pu
OM ar
-7 _] RE O
0 Mvar 0 MW �1 0.1 MVOr 0.0 MVar 0.0 MYa ( (l•Jl
W 0 MW PLEASANT 0 My 4 75 MW 75 MW
4 MW 0 Mvm Mg�e 1.016 pu 1DAN0_RD c 3 Mvar 3 Mver
Oi Yi 1. W 1hi .016 pu
METTER
7 01..90 Mw
HAYDEN0. W 0. Wr 1018p
0 Mvar MW 015W 6A M 1. PuWar
0.1 Mvar AVONDALE
BA ER DA NN1 1.017 pu
1. Pv 0.7 Mvar
/ 6.7 MW
6.6 MW l 0.1 Mvar
O.1 Mva
Figure 30: New generation at Rathdrum, light spring 2029
System performance in this area is dominated by several factors-
• High transfers from the east on the Cabinet — Rathdrum and Lancaster— Noxon
230kV transmission lines during spring runoff.
• Typical outflows to the west on the Beacon — Rathdrum, Bell — Lancaster, and
Boulder— Lancaster 230kV transmission lines.
Page 38 of 40

IRP Generation Integration Study I 2024ppendix E
• Load in the Coeur d' Alene area primarily served from the Rathdrum station.
• Existing local generation (440MW) from Boulder, Lancaster, Post Falls, and
Rathdrum stations.
In general, new generation in this area will sink into local load. As the local load is met
the additional power will typically flow west into the Spokane load center or further west
on BPA's 230kV system and up onto BPA's 500kV system at Bell.
4.4.2. Contingency Analysis
Worst system performance was during light spring conditions with high east to west
transfers. Outages on the 230kV system results in overloads on the underlying 115kV
system, as shown below. The summer and winter scenarios did not identify any issues.
Raw labels Base 25MW 5OMW IODMWDO
BF:BEA R427,Beacon Bus Tie
Boulder-Irvin#1115 kV(Boulder-Spokane Industrial Park) 101.1 102.7 104.2 106.6 112.1
N-2:Beacon-Boulder 230kV 6 Beacon-Rathdrum 230kV
Boulder-Irvin#1115 kV(Boulder-Spokane Industrial Park) 96.6 98.3 100 102.6 108.6
N-2:Beacon-Boulder 230kV 6 Boulder-Irvin#2115kV
Boulder-Irvin#1115 kV(Boulder-Spokane Industrial Park) 102.5 104.2 105.9 107.6 112.7
N-2:Beacon-Rathdrum HOW 6 Boulder-Greenfry HOW
Boulder-Rathdrum 115kV(Moab-Pleasant) 100.5 104.3 108.2 110.5 120.5
Boulder-Rathdrum 115kV(Boulder-Moab) 98 101.9 105.7 107.9 I 117.9
Boulder-Rathdrum 115kV(Pleasant-Idaho Rd) 106.8 110.7 114.6 116.9 I 126.9
Post Falls-Ramsey 115kV(Post Falls-Prairie) 96.8 I 105.5
Boulder-Rathdrum 115kV(Idaho Rd-Rathdrum) I 102.5
Post Falls-Ramsey 115kV(Prairie-Ramsey) 95.3
Otis Orchard-Post Falls 115 kV(Beck Road Tap-Post Falls) I 97.9
LANCASTR MEN->BELL S3(40090)CKT I at LANCASTR I I 95.4
N-2:Beacon-Rathdrum 230kV 6 Lancaster-Rathdrum 230kV
Boulder-Rathdrum 115kV(Moab-Pleasant) 103 109.8 116 125.9 148.3
Boulder-Rathdrum 115kV(Boulder-Moab) 100.5 107.3 113.6 123.4 I 145.0
Boulder-Rathdrum 115kV(Pleasant-Idaho Rd) 109.3 116.1 122.4 132.2 I 154.7
Post Falls-Ramsey I&V(Post Falls-Prairie) I 95.7 101.1 109.0 I 129.2
Boulder-Rathdrum 115kV(Idaho Rd-Rathdrum) I 99 106.6 I 123.9
Post Falls-Ramsey 115kV(Prairie-Ramsey) I 98.5 I 113.5
Otis Orchard-Post Falls 115 kV(Beck Road Tap-Post Falls) I 101.7 I 118.7
Otis Orchard-Post Falls 115 kV(East Farms Tap-Beck Road Tap) I 100.2
Otis Orchard-Post Falls 115 kV(East Farms Tap-Otis Orchard) I 95.6
Table 30: Contingency results, light spring 2029
The worst performing contingency is shown below. This shows the underlying 115kV
system overloaded for the double-circuit outage.
Page 39 of 40

IRP Generation Integration Study 2024ppendixE
LANCALST 11.8 M W
1.040 DU - 0.4 Mvar
Plra t HDRUM
MW Gree 0P 1.040 pu
p �a 0Mvar 1AwW
f.026pU 011 �' 0M ar UMW A� �`••�� �.• w
C'J U r 0 Mvar O n, RATMDRMW RATHDRME
1.017 pu
RE a OMW TEpS 53 MW 0.0 MW 0.0 MW
0 Mvar 0 M W 2 0.1 Mvx OA Mvar OA
W O MW PLEASANT O M o 75 MW 75 MW
4 MW Mvx 1.015 PU 1DAN0_RD c 2 N-2 Naar
O I.0 pu
HUETTER
1.018 PU
0.1 HAYDEN
1.9 MW 6.8 MW 1.016 pu
1AR.KER OA Mvar 0.1 Mvar 9.0 MW AlO1E
7 p�1 0.2 M- PU
.6.6 MW 0.1 NOW
OD 0.1 Mva
OTTES W F �F BECgtiAft"f .OADpu rLS tou W 1PR.oA117RWE8 %7 Muir
T RAMSEY DALTON A
0.0 Mqr 53 0.5 1.018 p0 1.016 PU
0.1 Mr 0.1 Mvar i 12 M_.2 MW
Figure 31: Worst performing contingency, light spring 2029
4.4.3. Intearation costs
The Rathdrum Station has a 230kV double breaker double bus arrangement with space
to terminate a new line position.
Cost
P01 Station or Area ir (Estimate
Point of Interconnection Statio million)
New 115kV line position at Rathdrum Station w/metering &termination str 1.7
New 230kV line position at Rathdrum Station w/metering &termination str 2.1
AWnects necessary to mitigate new facility violation 5/
Rebuild Boulder-Irvin#1 115kV BLD-SIP, fix 1.2mi 556/795aac 1.1
Rebuild Boulder-Rathdrum 115kV BLD-IDR, fix 9.2mi 250cu &337acsr 8.3
total 11.1
Projects necessary to mitigate new facility violations at 10OMW at 230kV
Rebuild Boulder-Irvin#1 115kV BLD-SIP, fix 1.2mi 556aac 1.1
Rebuild Boulder-Rathdrum 115kV fix 11.2mi 250cu, 337acsr&556aac 10.1
Rebuild PostFalls-Ramsey115kV PF-PRA,fix 2.9mi 250cu 2.6
total 15.9
Projects necessary to mitigate new facility violations at 20OMW at 230kV
Rebuild Boulder-Irvin#1 115kV BLD-SIP, fix 1.2mi 556aac 1.1
Build new Boulder-Lancaster 230kV SCT new 13.3mi ROW&structures 31.0
Build new Lancaster-Rathdrum 230kV SCT new 6.1 mi ROW&structures 14.2
total 48.4
Table 31: Generation integration estimate
Estimates assume that the Interconnection Customer will be responsible for the lead
line up to the change of ownership, which is a dead-end tower at the POI Station.
Page 40 of 40

Appendix E
This Page is Intentionally Left Blank

Appendix F
2025 Electric Integrated
Resource Plan
Appendix F — Distributed Energy
Resources Study
°,VV 1sra

Appendix F
AEG
Distributed Energy Resources
Potential Study
Final Report
Prepared For: Avista Utilities
By: Applied Energy Group, Inc.,
Cadeo Group, and Verdant Associates
•: codeo
VERDANT
Date: June 17, 2024
AEG Key Contact: Eli Morris

Appendix F
This work was performed by
Applied Energy Group, Inc.
2300 Clayton Rd., Suite 1370
Concord, CA 94520
Project Director: E. Morris
Project Manager: Dr. C. Arzbaecher
AEG would also like to acknowledge the valuable contributions of
Cadeo Group
3506 N Vancouver Ave
Portland, OR 97227
Project Team: F. Schaefer
Verdant Associates
1972 Los Angeles Ave
Berkeley, CA 95618
Project Team: W. Marin
Dr.J. Shelton
C. Elliott

Appendix F
EXECUTIVE SUMMARY
Study Background
In late 2022, Avista Corporation (Avista) selected Applied Energy Group (AEG), Cadeo, and Verdant
Associates (collectively the AEG Team) to perform a Distributed Energy Resource (DER) Potential
Study. The primary objectives of this study are to develop reasonable estimates for new customer
generation, battery energy storage, and electric vehicles on a localized basis within Avista's
Washington electric service territory and investigate the effects of such DERs in highly impacted or
vulnerable areas. The AEG Team worked closely with Avista staff to ensure the DER Potential study
met these objectives while satisfying the Washington Utilities and Transportation Commission's
condition 14 in approving Avista's Clean Energy Implementation Plan.'AEG will separately estimate
localized energy efficiency(EE) and demand response (DR)to complete the DER analysis.z
Approach
The team used AdopDER, a Python software application, to forecast the adoption and load impacts
of DERs annually in Avista's Washington service territory from 2023 through 2045. Specifically,
AdopDER estimated service point-level adoption of DERs and developed hourly load impacts from
those DERs by census block group will help Avista understand which areas of its distribution system
will likely experience DER load growth. Table ES-1 summarizes the DER technologies included in the
forecasts, which are grouped into two major categories: 1) Electric Vehicles (EVs) and Charging, and
2) New Generation and Storage.
Table ES-1. Technologies Included in DER Potential Study
ELectric Vehicles
• •
• Charging New
Storage
Light-duty vehicles, battery electric vehicles (LDV BEV) Customer Solar
Light-duty vehicles, plug-in hybrid electric vehicles (LDV PHEV) Customer Battery
Storage
Medium-duty vehicles, battery electric vehicles (MDV BEV) Customer Wind
Heavy-duty vehicles, battery electric vehicles (HDV BEV)
Level 1 electric vehicle supply equipment(L1 EVSE)
Level 2 electric vehicle supply equipment(1_2 EVSE)
Direct current fast-charging electric vehicle supply equipment
(DCFC EVSE)
1 Washington Utilities and Transportation Commission.Order 01 Approving Clean Energy Implementation Plan Subject to Conditions.
Avista 2021 Clean Energy Implementation Plan List of Conditions.URL:
https://apiproxy utc wa.gov/cases/GetDocument?doclD=255&year=2021&docketNumber=210628
Z AEG's DER and demand response(DR)potential studies for Avista are concurrent but independent.AEG strived to make the results of
those studies consistent by aligning per-customer impacts and adoption counts for both EVs and Customer Battery Storage units.
However,the DR forecast employs a different methodology,which assumes program participation rates and includes Avista's Idaho service
territory,while the DER forecast includes only Washington.Therefore,the results across the two studies may differ.

Appendix F
Key Results
Table ES-2 summarizes the DER forecast results in 2045 for the reference scenario. Residential and
fleet EV supply equipment (EVSE) is projected to have the most significant load impacts in Avista's
Washington service territory, adding nearly 1,700 GWh of energy consumption in 2045. Because most
residential customers charge their EVs in the late evening and night hours, the daily peaks of
residential EVSE are not expected to coincide with Avista's planning peak hour.
Customer solar dominates new customer generation and is forecasted to reduce delivered loads by
roughly 120 GWh by 2045. While the impact of customer storage load is minimal, nearly 100 MW of
storage capacity will be available by 2045.
Table ES-2.2045 Results Summary,Reference Scenario
NameplateShare of
AnnualLoad Nameplate July Peak December
NamedResource Capacity Impact Capacity in Load Impact' Peak Load
•.
Community'Customer
Solar 105 127 46% 33 0
Customer
Battery 96 2 58% -3 -9
Storage
Customer 1 -0.3 45% -0.1 0
Wind
Residential 1,544 853 38% 62 62
EVSE
Fleet EVSE 692 841 67% 101 105
Public and
Workplace 171 206 60% 33 33
EVSE
a. The term"peak"refers to a planning peak beginning at 17:00 and ending at 18:00 local time.
Key Recommendations
This study represents an initial forecast of potential DER adoption in Avista's Washington electric
service territory, using the best information available duringthe analysis.As the AEG Team developed
these initial forecasts, we identified specific activities that Avista could undertake to improve the
data available for future DER forecasts, including:
Address Fleet Data Gaps. Finding fleet vehicle data is challenging. Secondary data likely
undercount smaller light-duty vehicle (LDV) fleets. Therefore, the AEG Team recommends that
Avista conduct the following activities:
o Continued outreach to fleet operators. Continue surveying and collaborating with
transit authorities, school districts, and parcel delivery companies in its service territory,
as such outreach will help inform future DER forecasts.
3"Named Communities"refers to service points located in a highly impacted census tract,a vulnerable census tract,or tribal land.The
team details this definition in Section 2,Project Overview,of this report.
iii

Appendix F
o Analysis of satellite imagery. Satellite imagery is a low-effort method to determine
commercial and industrial fleet service points. Consider analyzing satellite imagery to
help inform EV fleet forecasting.
o Acquire fleet inventory data. The Washington Department of Ecology is currently
conducting a fleet inventory. Once this data becomes available, the AEG Team
recommends Avista pursue and use it.
Develop Commercial EV Charging Profiles. Limited data are available to characterize EVSE
charging profiles, especially for commercial fleets. The AEG Team recommends that Avista
conduct load research on commercial fleet charging.
Develop Seasonal EV Charging Profiles. The team did not have sufficient data to characterize
seasonal differences in EV charging profiles (kW per hour) and driving patterns (vehicle miles
traveled per day), so we assumed the summer and winter charging profiles are the same in
Avista's service territory. However, the winter charging profile may be more significant due to
vehicle cabin space heating or smaller because of less driving in the winter. Therefore, we
recommend that Avista conduct load research on seasonal charging.
Conduct Additional Scenario Analyses. The DER adoption forecast analyzed two scenarios: a
reference scenario and a high-incentive scenario. Consider adding additional scenarios to study
the impacts of climate change (e.g., weather, customer grid resiliency) and ancillary services
incentives on DER forecasting.
Integrate the DER and Demand Response (DR) Potential Studies. Some types of DERs, like EV
charging and customer battery storage, can be leveraged in DR events.Therefore, it would benefit
Avista to integrate its DER and DR potential studies to avoid overestimating or underestimating
the combined potential.
Consider Adding Building Electrification. Building electrification and load flexibility can affect
customers' decisions regarding DER installations. Therefore, including building electrification
and associated load control measures (e.g., connected thermostats, heat pump water heater
switches) in future DER potential studies would provide Avista with a more comprehensive
understanding of customer load growth and opportunities to shape it with programs and rates.
Consider Adding Emerging Technologies. Emerging technologies, such as autonomous
vehicles and vehicle-to-grid technologies, can change customer energy consumption patterns.
Therefore, in future DER potential studies,Avista may want to consider emerging technologies as
they become commercially available.
iv

Appendix F
CONTENTS
EXECUTIVE SUMMARY........................................................................................... II
StudyBackground.......................................................................................................................................................ii
Approach......................................................................................................................................................................ii
KeyResults...................................................................................................................................................................iii
KeyRecommendations..............................................................................................................................................iii
1 1 INTRODUCTION ................................................................................................1
Backgroundand Objectives......................................................................................................................................I
Valueto Avista.............................................................................................................................................................I
StudyLimitations........................................................................................................................................................2
ReportOrganization..................................................................................................................................................3
2 PROJECT OVERVIEW..........................................................................................4
Approach.....................................................................................................................................................................4
NamedCommunities........................................................................................................................................6
ModelingScenarios..........................................................................................................................................6
3 DETAILED RESULTS: ELECTRIC VEHICLES AND CHARGING ........................................8
VehicleAdoption........................................................................................................................................................8
ChargingAdoption....................................................................................................................................................9
LoadImpact................................................................................................................................................................11
AncillaryServices.......................................................................................................................................................15
4 DETAILED RESULTS: NEW CUSTOMER GENERATION AND STORAGE ........................... 17
CustomerSolar.......................................................................................................................................................... 17
Adoption............................................................................................................................................................ 17
LoadImpact......................................................................................................................................................18
CustomerWind.........................................................................................................................................................20
Adoption...........................................................................................................................................................20
LoadImpact.......................................................................................................................................................21
CustomerBattery Storage.......................................................................................................................................21
Adoption............................................................................................................................................................21
LoadImpact......................................................................................................................................................22
AncillaryServices......................................................................................................................................................22
5 CONCLUSIONS AND RECOMMENDATIONS............................................................ 25
SummaryResults......................................................................................................................................................25
Recommendations....................................................................................................................................................25
AGLOSSARY ...................................................................................................A-1
B UTILITY SURVEY ............................................................................................B-1

Appendix F
C DER FORECASTING METHODOLOGY ................................................................. C-1
D STAKEHOLDER ENGAGEMENT.......................................................................... D-1
E SUPPLEMENTAL ELECTRIC VEHICLE DATA...........................................................E-1
vi

Appendix F
LIST OF FIGURES
Figure 2-1. Modeling Process Diagram .........................................................................................5
Figure 2-2. Named Communities Map..........................................................................................6
Figure 3-1. Residential Vehicles, Reference Scenario.....................................................................8
Figure 3-2. Non-Residential(Fleet)Vehicles, Reference Scenario....................................................9
Figure 3-3. 2045 EVSE Megawatt Capacity by Customer Segment, Reference Scenario ..................... 10
Figure 3-4. 2045 EVSE Megawatt Capacity by EVSE Type, Reference Scenario.................................. 10
Figure 3-5. 2045 EVSE Megawatt Capacity by Named Community Status and Scenario...................... 11
Figure 3-6. Annual Charging Load Impact(GWh), Reference Scenario ............................................ 12
Figure 3-7. Locational Residential EVSE Load Impact in 2045.Washington Service Territory(Left)and
Detailed Spokane Region (Right) .......................................................................... 13
Figure 3-8.Locational Non-Residential EVSE Load Impact in 2045.Washington Service Territory(Left)
and Detailed Spokane Region (Right) .................................................................... 14
Figure 3-9. Summer Average Hourly Load Profile for EVSE in 2045, Reference Scenario..................... 15
Figure 4-1. 2045 Customer Solar Nameplate Capacity(MW) by Sector, Reference Scenario............... 17
Figure 4-2. 2045 Customer Solar Nameplate Capacity (MW), by Named Community Status and
Scenario........................................................................................................... 18
Figure 4-3. Annual Customer Solar Load Impact(GWh), Reference Scenario................................... 18
Figure 4-4. Locational Customer Solar Load Impact in 2045. Washington Service Territory (Left) and
SpokaneRegion (Right)....................................................................................... 19
Figure 4-5 Average Hourly Load Profile for Customer Solar in 2045, Reference Scenario ................... 20
Figure 4-6. 2045 Customer Wind Nameplate Capacity(MW).......................................................... 21
Figure 4-7. 2045 Customer Storage Nameplate Capacity(MW) by Sector, Reference Scenario............ 22
Figure 4-8.Average Hourly Load Profile for Customer Storage in 2045, Reference Scenario ............... 22
vii

Appendix F
LIST OF TABLES
Table ES-1.Technologies Included in DER Potential Study.............................................................. ii
Table ES-2. 2045 Results Summary, Reference Scenario ............................................................... iii
Table2-1. In-Scope DER Technologies .........................................................................................5
Table 3-1. EVSE Load Impact in 2045, by Scenario and Customer Segment...................................... 12
Table 3-2. EVSE Load Impact in 2045, by Scenario and Customer Segment...................................... 16
Table 4-1. 2045 Customer Solar Load Impact, by Scenario and Customer Segment .......................... 19
Table 5-1. Summary Results for 2045, Reference Scenario............................................................ 25
Table E-1.Year 2030 Electric Vehicle Results Summary, High-Incentive Scenario............................ E-1
Table E-2.Year 2045 Electric Vehicle Results Summary, High-Incentive Scenario............................ E-1
Table E-3. DCFC Charging Load Profiles.................................................................................... E-2
Table E-4. L1 and L2 Fleet Charging Profiles .............................................................................. E-3
Table E-5. Residential L1 and L2 Charging Profiles...................................................................... E-4
Table E-6. Public and Workplace Charging Profiles..................................................................... E-5
Table E-7. Charging Nameplate kW Assumptions........................................................................ E-6
viii

Appendix F
Distributed Energy Resources Potential Study
1 1 INTRODUCTION
This introductory section describes the study's purpose, objectives, and the AEG team's approach to
forecasting and estimating the DER potential using two modeling scenarios. It also discusses the
study's limitations and overall value to Avista.
Background and Objectives
Avista Utilities (Avista) contracted with AEG, with subcontractors Cadeo Group and Verdant
Associates (collectively the AEG Team), to conduct a potential assessment of Distributed Energy
Resources (DERs) in its Washington electric service territory.
Avista's primary objectives for completing this study include:
Satisfy condition 144 from the Washington Utilities and
Transportation Commission's (WUTC's) approval of Avista's
Clean Energy Implementation Plan (CEIP). CONDITION 14 FROM WUTC
APPROVAL
Develop reasonable estimates for new customer Avista will include a DER potential
generation, storage, and electric vehicles localized within assessment for each distribution feeder
Avista's WA electric service territory. no later than its 2025 Electric Integrated
Resource Plan(IRP)and gather input
Investigate effects in highly impacted or vulnerable from the IRP Technical Advisory
population areas. Committee JAC),Energy Efficiency
Advisory Group(EEAG),and Distribution
Utilize a robust forecasting model that can be updated and Planning Advisory Group(DPAG).
enhanced overtime. The assessment will include a low-
Document methods, data sources, and inputs and provide income DER potential assessment.
results in a format that Avista can incorporate into other Understand DER forecasting
planning efforts. methodologies currently employed by
other utilities.
Engage internal and external stakeholders to get buy-in on
study results.
Value to Avista
In addition to satisfying the WUTC condition, the activities and results associated with this study
provide other valuable insights to Avista:
Informs Avista's 2025 Electric Integrated Resource Plan (IRP): This study provides a
bottom-up DER potential estimate, grounded in several reliable data sources, for the adoption
and load impact from electric vehicle charging and customer solar photovoltaic (PV) for use in
Avista's 2025 IRP's load forecast. Avista will need to plan its future portfolio of energy resources
around these DER technologies.
Informs Distribution Planning Activities: As DER adoption becomes more common, the
team expects it to have disparate impacts across areas of Avista's electric distribution system.
For instance, the AEG team expects electric vehicle charging to impact the industrial regions of
Spokane County more heavily than other areas of the service territory, and these impacts are
4Avista will include a Distributed Energy Resources(DERs)potential assessment for each distribution feeder no later than its 2025 electric
IRP.Avista will develop a scope of work for this project no later than the end of 2022,including input from the IRP TAC,EEAG,and DPAG.
The assessment will include a low-income DER potential assessment. Avista will document its DER potential assessment work in the
Company's 2023 IRP Progress Report in the form of a project plan,including project schedule,interim milestones,and explanations of how
these efforts address WAC 480-100-620(3)(b)(iii)and(iv).
Applied Energy Group, Inc. I www.appliedenergygroup.com 1

Appendix F
Distributed Energy Resources Potential Study
likely to trigger upgrades to distribution system infrastructure (i.e., service transformers and
feeder lines).The DER Potential Study helps identify the areas on Avista's distribution system that
will likely experience load growth from DERs over the next decade. For example, the results from
the DER Potential Study will be incorporated into the data assumptions for the 2025-2026 System
Assessment to help identify system deficiencies and proactively propose appropriate corrective
action plans.
Informs Customer Engagement: The AEG team located over 8,000 commercial fleet
vehicles using various data sources to support this study. These data serve a dual purpose. In
addition to identifying locations on Avista's grid likely to experience significant load growth, they
also give Avista information that it can use to engage with its customers and advance
transportation electrification initiatives with public and private entities. Similarly, Avista can use
the results to engage customers regarding solar and storage programs.
Study Limitations
Like all potential studies, this study has limitations that can affect the interpretation of results and
findings.The primary limitations include:
The Study Only Includes the Most Favorable Generation Technologies. For this study,the team
focused on customer solar and customer wind. Due to their unfavorable economics, the team
considered but did not include other generation technologies (e.g., biomass-fired generation and
combined heat and power).
Individual Customer Behaviors Deviate from "Average" Customer Behavior. This study, like
others, requires hundreds of assumptions concerning service territory averages and other high-
level estimates. Individual customer behaviors, however, will vary from those service territory
averages, and such behavioral information is unavailable for a broad study like this. For example,
the AEG team assumed the average market share of BEVs in transit agency fleets would be 33%
in 2030. Consider two hypothetical fleets where fleet A plans to have a 100% BEV share by 2030,
while fleet B will not electrify until 2032. Because the DER Potential Study uses averages, we
would assume that fleets A and B have the same proportion of BEVs (33%).
Another example of how data gaps can affect the modeling results involves our assumption that
all private MDV and HDV fleets have the same average daily charging profiles.Again, consider two
hypothetical fleets: fleet A is an MDV fleet that delivers locally and charges overnight,while fleet
B is an HDV fleet that makes long-haul daily charges while loading at the warehouse. This DER
Potential Study assumes that fleets A and B have identical load profiles.
Scenario Analyses are Limited. The analysis includes two scenarios—Reference and High-
Incentive Scenarios—described in Appendix C. The solar and EV markets and the team's
assumptions used to characterize them are incredibly complex. As such, this study focuses on
two plausible future outcomes for DER adoption.
The Study is not a Comprehensive Load Forecast. This study focuses on the load impacts of
adopting DERs across Avista's distribution system. However, the project scope did not include a
granular load forecast to account for other types of energy loads, such as space heating, lighting,
and industrial production, and how those loads interact with DERs, energy efficiency, and
demand response to get a complete view of the distribution system. As such, Avista will use the
results of this study in tandem with other study results to conduct further analysis on how
incremental DER adoption impacts its distribution system.
Applied Energy Group, Inc. I www.appliedenergygroup.com 2

Appendix F
Distributed Energy Resources Potential Study
Report Organization
The remainder of this report is organized as follows:
Project Overview describes the study's tasks, forecasting approach, and modeling scenarios.
Electric Vehicles: Modeling Scenarios and Results presents detailed electric vehicles and
charging results for the two scenarios.
New Customer Generation and Storage: Modeling Scenarios and Results provides detailed
forecast results for customer-sited solar PV, wind, and battery storage for the two scenarios.
Conclusions summarize key findings and recommendations for Avista to consider in future DER
planning activities.
Appendix A contains a glossary of the acronyms used in this report.
Appendix B discusses the DER forecasting methodologies of priority utilities, including
PacifiCorp, Portland General Electric, Puget Sound Energy, Sacramento Municipal Utility District,
Seattle City Light, and Southern California Edison.
Appendix C details the DER forecasting methodology used by the AEG team to complete this
study.
Appendix D provides examples of Avista's engagement with DER stakeholders during the
development of this study.
Appendix E provides the EV charging load profiles used in this study and summary tables of the
EV adoption and load impact results from the high-incentive scenario.
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Appendix F
Distributed Energy Resources Potential Study
21 PROJECT OVERVIEW
The AEG team performed six discrete tasks to complete this study:
Task 1: Survey Priority Utilities. The AEG team conducted a literature review and interviewed
subject matter experts to characterize other electric utilities' DER forecasting methods. In
collaboration with Avista, we selected six priority utilities to survey, representing Avista's regional
peers and other leading West Coast utilities with advanced DER programs. The priority utilities are
PacifiCorp, Portland General Electric, Puget Sound Energy, Sacramento Municipal Utility District,
Seattle City Light, and Southern California Edison. The written deliverable from this task—a
memorandum—is included in Appendix B of this report.
Task 2: Develop DER Forecasting Methodology. The AEG team developed a comprehensive plan
for the DER forecasting approach, employing data from Avista and other secondary sources to
forecast DER adoption and load impacts.The DER Forecasting Methodology document is included in
Appendix C of this report.
Task 3: Forecast the Electric Vehicles and Charging Potential. For this task, the AEG team
followed the methods described in the DER Forecasting Methodology document (Task 2) to
model the adoption and load impact of electric vehicles and charging equipment in Avista's
Washington service territory through 2045. Section 4 of this report presents the results.
Task 4: Forecast the New Generation and Storage Potential. The AEG team followed the
methods described in the DER Forecasting Methodology document(Task 2)to develop a forecast
of customer-sited solar PV, storage, and wind adoption and the associated load impacts in
Avista's Washington service territory through 2045. Section 5 of this report presents the results.
Task 5: Present DER Forecast Results to Stakeholders. In March 2024,the AEG team presented
the DER forecast results to stakeholders from Avista's IRP Technical Advisory Committee JAC),
Energy Efficiency Advisory Group (EEAG), and Distribution Planning Advisory Group (DPAG). Staff
from the Washington Utilities and Transportation Commission (WUTC) and the Washington State
Department of Commerce also participated in the stakeholder meeting. Appendix D contains the
stakeholder presentation slides and meeting notes. It also summarizes the stakeholder
questions and Avista's responses.
Task 6: Develop Final Report. This report represents the deliverable of the study's final task. In
addition, the AEG team provided Avista with model input data and a summary of the results of
the modeling activities.
Approach
The study is focused on the distribution system. As such, the AEG team performed the forecast
analysis at a census block group level to help Avista understand at a high level of resolution which
areas of its distribution system are likely to experience DER load growth.
For the modeling analysis,the team used AdopDER, a software application written in Python that was
initially developed with Portland General Electric (PGE) for PGE's integrated resource planning and
distribution system planning activities.AdopDER estimates service point-level adoption of DERs and
creates long-term, hourly load impacts from those DERs at a granular level across a utility distribution
system. Figure 2-1 illustrates how AdopDER uses a consistent framework to forecast DER adoption
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Appendix F
Distributed Energy Resources Potential Study
and DER load impacts. Appendix B details the process flow steps and describes the data sources
leveraged for the analysis.'
Raw Data
Input
Development
r r r r
Initial Site Customer Customer Adoption DER Load
Characteristics Forecast Intelligence Curves Impacts
DER
Forecast* . . I .... i M
Update Time Ste
Stock Assessment Load Impact 8760 Forecast
*Repeat with alternate inputs for each scenario
Figure 2-1. Modeling Process Diagram
Table 2-1 summarizes the DER technologies included in the forecast. For each technology, the team
developed a forecast of adoption and load impact for 2023 through 2045 in Avista's Washington
electric service territory.
Table 2-1. In-Scope DER Technologies
Electric Vehicles and Charging New Generation and Storage
Light-duty vehicles, battery electric
Customer Solar
vehicles (LDV BEV)
Light-duty vehicles, plug-in hybrid
electric vehicles (LDV PHEV) Customer Battery Storage
Medium-duty vehicles, battery electric
Customer Wind
vehicles (MDV BEV)
Heavy-duty vehicles, battery electric
vehicles(HDV BEV)
Level 1 electric vehicle supply
equipment(L1 EVSE)
Level 1 electric vehicle supply
equipment(L2 EVSE)
Direct current fast-charging electric
vehicle supply equipment(DCFC EVSE)
'Appendix B contains clarifications and edits to the original document due to data availability and quality.
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Appendix F
Distributed Energy Resources Potential Study
Named Communities C
The AEG team collaborated with Avista to define a
Named Community as any service point for which one "
or more of the following is true:
nak
• Highly Impacted is in a census tract with a
Washington Department of Health "EHD v2.0 r
Overall Rank"score of 9 or 10. "eN0°"
C
• Vulnerable is in a census tract with a
composite score of 9 or 10 in the sensitive - F
population or socioeconomic subcategories,as
identified by the WA Department of Health's Y r` oeurc
Environmental Health Disparities Map.
• Tribal Land is in a tribal land identified by an
ata
Avista-provided GIS shape file.
Moses Lake
The darker-shaded regions of the map in Figure 2-2
indicate the locations of Named Communities in
Avista's Washington service territory. The lighter-
shaded regions are Non-Named Communities.
Modeling Scenarios
This study examines two scenarios: a reference and a ston
high-incentive scenario. The two scenarios represent _
Kennewick
plausible future outcomes for DER in Avista's
Washington service territory. walla walla
The reference scenario represents the "most likely"
future outcome and is informed by current trends and Figure 2-2. Named Communities Map
the Washington state policy landscape. In it, we
simulate adoption using knowledge of current incentive programs and typical "s-curve" changes in
market share. In other words, under the reference forecast,we do not assume the existence of to-be-
determined future programs, incentives, and interventions that may promote DER adoption,whether
these interventions come from the utility, state, or federal level. Specifically, the reference scenario
uses the following assumptions:
• Residential EV market share follows California's Advanced Clean Cars II regulation, with the
Named Community market share adjusted downward.
• Non-residential EV market shares are consistent with those of regional literature review(e.g.,
Washington EV Council, Seattle City Light Electrification Study, Atlas Public Policy
Washington Public Vehicle Electrification Assessment.
• Solar PV and storage adoption follows current market trends,with the adoption rate in Named
Communities being lower than in Non-Named Communities.
The high-incentive scenario represents an alternative future where federal, state, and local policies
incentivize DER adoption in Named Communities. The high-incentive scenario uses the following
assumptions:
• Residential EV market share in Named Communities is the same as in Non-Named
Communities.
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Appendix F
Distributed Energy Resources Potential Study
• Residential Solar PV and storage adoption rates in Named Communities are the same as in
Non-Named Communities.
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Appendix F
Distributed Energy Resources Potential Study
31 DETAILED RESULTS: ELECTRIC VEHICLES AND
CHARGING
This section describes the detailed forecast results for electric vehicles and charging. Appendix C
discusses the forecasting modeling approach, including data sources and assumptions. Appendix E
provides supplemental electric vehicle data.
Vehicle Adoption
In the reference scenario, the AEG team expects there to be a total of 545,000 vehicles of any fuel
type associated with residential service points in the Avista Washington service territory by 2045, as
illustrated in Figure 3-1.This total includes 346,000 battery electric vehicles(BEVs)and plug-in hybrid
electric vehicles (PHEVs) (64% of the total residential vehicle stock), a substantial increase over the
7,000 existing residential BEVs and PHEVs.This forecast accounts for Washington State's aggressive
zero-emission vehicle (ZEV) mandate that all new, light-duty vehicles sold within the state meet ZEV
Program standards by 2035.E However, the assumed average vehicle lifetime of 15 years somewhat
tempers the EV growth. In the high-incentive scenario, where we assumed higher incentives for
customers in Named Communities, we forecast an accelerated adoption of BEVs and PHEVs, with
73% of the residential vehicles becoming BEVs and PHEVs by 2045.
600,000
500,000
400,000
t
0 300,000
iu
s
E
Z 200,000
100,000
0
m 'T N (D r, Co o) O N m � m w rl co m O N m q m
N N N N N N N m m m m m m m 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 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
Year
■ICE ■BEV/PHEV
Figure 3-1. Residential Vehicles, Reference Scenario
Figure 3-2 displays the reference scenario's non-residential vehicles (fleet vehicles) by fuel type and
weight class for the 2023 to 2045 timespan. Overall, we forecast 59,000 fleet vehicles by 2045,
including 39,000 light-duty vehicles (LDVs), 20,000 medium-duty (MDVs), and heavy-duty vehicles
(HDVs).Among MDVs and HDVs,the team expects 49%to be BEVs by 2045.7 Within the LDV segment,
we forecast 78%to be BEVs and PHEVs by 2045. In the high-incentive scenario,we assumed identical
6 "Zero Emission Vehicles", Department of Ecology. Accessed on May 2, 2024. URL: https://ecology.wa.gov/air-climate/reducing-
greenhouse-gas-emissions/zev.
7 The team assumes that MDVs and HDVs will electrify with BEVs only. PHEVs do not have a substantive market share in these weight
classes and are unlikely to achieve a significant market share in the study's time horizon.
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Appendix F
Distributed Energy Resources Potential Study
market shares for fleet vehicles.' Consequently, the two scenarios have the same BEV and PHEV
penetration estimates.
70,000
60,000
50,000
U
40,000
6
30,000
E
Z 20,000
10,000 IIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIJIM
0
CO -q M w r, O] D) O N M 7 N CD r, N O O N M V In
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
Year
■LDV ICE LDV BEV/PHEV ■MDV/HDV ICE MDV/HDV BEV/PHEV
Figure 3-2. Non-Residential(Fleet)Vehicles,Reference Scenario
Charging Adoption
The BEVs and PHEVs identified in Figure 3-1 and Figure 3-2 form the basis for electric vehicle supply
equipment (EVSE) in Avista's Washington service territory. We choose to display nameplate capacity
rather than the number of service points because fleet and public EVSE typically have a higher rated
capacity and thus can more significantly impact electric consumption than residential charging.
Figure 3-3 illustrates the forecast estimate for EVSE's nameplate capacity in megawatts (MW) by
customer segment under the reference scenario. Most capacity is associated with residential
customers (1,554 MW), but we expect a substantial fleet (692 MW) and public and workplace
charging(171 MW) capacity,too.
8 The team, after thorough research, determined BEV and PHEV adoption rate impacts for Named Communities relative to Non-named
Communities for residential customers only. Thus, we assumed that the adoption rate of BEV and PHEV for non-residential (fleet)
customers is at parity between Named Communities and Non-named Communities.
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Appendix F
Distributed Energy Resources Potential Study
Non-Res NonRes
(Fleet) (Public+
692 W(rkplace)
171
Residential
1,544
Figure 3-3.2045 EVSE Megawatt Capacity by Customer Segment,Reference Scenario
Figure 3-4 displays the relative EVSE proportions by type (e.g., L1, L2, and DCFC) in the reference
scenario. L2 will have the most charging capacity(1,923 MW of 2,407 MW total).
DCFC
346 L1
138
L2
1,923
Figure 3-4.2045 EVSE Megawatt Capacity by EVSE Type,Reference Scenario
Figure 3-5 shows how EVSE capacity varies by scenario. The high-incentive scenario has
approximately 260 MW incremental EVSE capacity relative to the reference scenario(2,407 MW in the
reference scenario vs. 2,665 MW in the high-incentive scenario) due to greater BEV and PHEV
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Appendix F
Distributed Energy Resources Potential Study
adoption in the residential sector. The team expects the incremental EVSE capacity in the high-
incentive scenario to occur mainly in Named Communities.
1,273
1,262
Named
Named
0 0
Reference High Incentive
Figure 3-5.2045 EVSE Megawatt Capacity by Named Community Status and Scenario
Load Impact
Under the reference scenario, Figure 3-6 shows the expected load impact (GWh) from vehicle
electrification in Avista's Washington service territory. By 2045, the team expects BEVs and PHEVs to
account for approximately 1,900 GWh of electric consumption, an increase of about 1,880 GWh
relative to current electric vehicle consumption. If the load forecast that AEG created for Avista's
2023 Integrated Resource Plan9 holds, this level of vehicle electrification would account for
approximately a third of total electricity consumption1) in the Avista Washington service territory by
2045 (i.e., 1,900 GWh divided by 5,800 GWh equals 33%).
9 Avista Utilities. 2023 Electric Integrated Resource Plan. Appendix C-AEG Conservation Potential and Demand Response Potential
Assessments. "AEG. Avista Electric Conservation Potential Assessment for 2022-2045." December 9, 2022. URL:
https://www.myavista.com/-/media/myavista/content-documents/about-us/our-company/irp-documents/2023/appendix-c-cpa-and-dr-
ootential-assessments.odf
io The team approximated Avista's 2045 load forecast of 5,800 GWh for Washington service territory in 2045 based on Tables 4-1,4-3,and
4-5 in"Appendix C-AEG Conservation Potential and Response Potential Assessment."See footnote reference 4.
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Appendix F
Distributed Energy Resources Potential Study
2,000
1,800
1,600
1,400
1,200
s
1,000
0
800
600
400
200
0
CO V (n 0 n 00 a) O N M V In (D r N D) O N CO V LO
N N N N N N N CO M CO M CO CO 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 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
Year
■Residential ■Non-Residential(Public/Workplace) ■Non-Residential(Fleet)
Figure 3-6.Annual Charging Load Impact(GWh), Reference Scenario
Table 3-1 shows the 2045 EVSE load impact by scenario. We expect 158 incremental GWh in 2045 in
the high-incentive scenario relative to the reference scenario (2,057 GWh vs. 1,899 GWh). This
increase is due to residential, public, and workplace charging. In the high-incentive scenario, we
expect additional adoption of BEVs and PHEVs in Named Communities, but not every dwelling unit
can accommodate EVSE. Thus, increased public and workplace charging will meet some charging
demand.
Table 3-1. EVSE Load Impact in 2045,by Scenario and Customer Segment
Customer Segment 2045 Load Impact, 14 •.• Impact,
High-
Scenario •
Residential 853 978
Non-residential(Public
and Workplace) 206 237
Non-residential(Fleet) 841 841
Total 1,899 2,057
The average daily load in megawatt-hours (MWh) associated with residential and non-residential
EVSE by census block groups across Avista's Washington service territory is shown in Figure 3-7 and
Figure 3-8, respectively.While the project scope does not include an analysis of how EVSE will impact
the available headroom on specific distribution feeders and substations, certain areas of the
distribution system will be affected more than others. For example, we anticipate that residential
EVSE will typically add less than 10 MWh per day per census block group, with more significant
amounts in the suburban areas surrounding the city of Spokane (Figure 3-7).
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Appendix F
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D—k U C !-
i i
}
m C...-Alen. - —
la
G3
O20024 .pb9x Cpe SV fm'p�,- I % n J2024 Pb.x ,O n511eeAlaP
Daily MWH
D 0-1 1-5 ■ 5-10 ■ 10-50
Figure 3-7. Locational Residential EVSE Load Impact in 2045. Washington Service Territory(Left)and Detailed
Spokane Region(Right)
In contrast, we expect non-residential (fleet) charging to be more concentrated in some regions of
the service territory. For example, the AEG team forecasts that census block groups in the industrial
region bounded by Spokane River and Interstate 90 could see upwards of 100 MWh of average daily
energy consumption by 2045 due to fleet and public charging under the reference scenario. (See the
darkest shaded regions in Figure 3-8). Though this load growth will happen over time, our findings
allow Avista to reach out to fleet customers to discuss their electrification plans. This, in turn, will
enable Avista to assess when distribution system upgrades will be required and help shape how and
when customers will charge EV fleets in the future.
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Appendix F
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omak
1 �
coep.c'Aiene
e / Iley vEae n
4 s
Le iston
O22 epbox®OpanSVee Map\ l _02D24 Mapb,, Ope 1—IM,
Daily MWH
c 0-1 1-5 ■ 5-10 ■ 10-50 ■ 50-100 ■ 100 or more
Figure 3-8. Locational Non-Residential EVSE Load Impact in 2045. Washington Service Territory(Left)and Detailed
Spokane Region(Right)
Figure 3-9 illustrates the expected 2045 summer hourly charging profile for the reference scenario.
We assume charging will occur mostly late into the afternoon or evening.11 During the summer
season, at Avista's planning peak for the hour beginning at 17:00 local time, we estimate 196 MW of
load, ramping up to approximately 420 MW during the hour beginning at 22:00 local time, when
residential customers are typically at home, and fleet customers have usually completed their daily
activities. Because the team did not have sufficient data to characterize seasonal differences in EV
charging load profiles (kW per hour) and driving patterns (vehicle miles traveled per day) within
Avista's service territory, we assumed that the hourly charging profile does not vary over the year.
Therefore, the winter and summer hourly charging profiles are nearly identical in our modeling
results.
11 The team used load profiles from Avista's 2022 Transportation Electrification report to characterize the hourly EVSE load profiles for this
study.These curves indicate that Avista's customer EVSE load peaks in the evening hours.
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Appendix F
Distributed Energy Resources Potential Study
450
400
350
300
0
250
0-
200
bA
Q 150
100
50
0
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23
Hour Beginning
■Residential Non-Residential(Public/Workplace) ■Non-Residential(Fleet)
Figure 3-9. Summer Average Hourly Load Profile for EVSE in 2045, Reference Scenario
Note that Figure 3-9 represents service territory aggregates. The behavior of individual fleets and
specific census block groups will vary. For example, public transit authorities may employ on-route
charging rather than depot charging to manage the operational efficiency of their fleets; this is an
example of a location-specific behavioral difference that would make charts like Figure 3-9 differ if
viewed for each census block group.
The AEG team relied primarily on Avista's 2022 Transportation Electrification Report load profiles.12
These load profiles do not assume explicit direct load control(DLC) measures or pricing schemes like
Time-of-Use (TOU) rates,which typically influence hourly charging shapes. Because quantifying load
impacts associated with DLC or TOU rates was not part of the project scope, the AEG team
recommends that Avista assess DLC and TOU rates in future DER potential studies.This will become
increasingly important as Avista develops its strategy for managing the growth of charging loads in its
service territory.
Ancillary Services
The team assumes that the residential EVSE load is eligible for use in ancillary services because it
could be controlled through a DLC program. Based on assumptions consistent with Avista's 2023
Integrated Resource Plan,we assume the following for the ancillary services potential:13
15% participation in a Residential EVSE DLC program.
DLC reduces load impact by 75% during event hours.
50% of DLC load reduction is available for ancillary services.
12 Avista Utilities. 2022 Annual Transportation Electrification Report. Submitted to the Washington Utilities and Transportation
Commission. March 31, 2023. URL: https://www.myavista.com/-/media/myavista/content-documents/energy-savings/evs/avista-2022-
a n n u a l-te-re po rt.p df
13 Avista Utilities. 2023 Electric Integrated Resource Plan. Appendix C-AEG Conservation Potential and Demand Response Potential
Assessments. "AEG. Avista Electric Conservation Potential Assessment for 2022-2045." December 9, 2022. URL:
https://www.myavista.com/-/media/myavista/content-documents/about-us/our-company/irp-documents/2023/appendix-c-cpa-and-dr-
potential-assessments.pdf
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Appendix F
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Applying these assumptions to the 62 MW of projected residential EVSE load during the planning peak
hour, we estimate 4 MW of potential for ancillary services, as illustrated in Table 3-4. The team does
not consider non-residential EVSE to have ancillary services potential, as fleet and public charging
typically have less flexibility than residential charging.
Table 3-2. EVSE Load Impact in 2045,by Scenario and Customer Segment
NameplateAnnual, Share of July Peak December Ancillary
•
ResourceLoad
. •. Capacity
Impact
Residential •
EVSE 1,544 853 38% 62 62 4
Fleet EVSE 692 841 67% 101 105 0
Public and
Workplace 171 206 60% 33 33 0
EVSE
a. The term"peak"refers to a planning peak beginning at 17:00 and ending at 18:00 local time.
14"Named Communities"refers to service points located in a highly impacted census tract,a vulnerable census tract,or tribal land.The
team details this definition in Section 2,Project Overview,of this report.
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Appendix F
Distributed Energy Resources Potential Study
41 DETAILED RESULTS: NEW CUSTOMER GENERATION
AND STORAGE
This section describes the detailed forecast results for new customer generation and battery energy
storage; details on the forecasting modeling approach, including data sources and assumptions, are
provided in Appendix C.
Customer Solar
Adoption
Figure 4-1 displays the AEG team's forecast of customer-sited solar nameplate capacity (MW) in
2045.We expect current trends to continue,with the residential customer segment dominating solar
adoption. The residential segment will account for over 85% of the 104 MW new customer solar in
2045. However, our analysis indicates that some larger commercial customers will start adopting
solar at more elevated rates than historically.
Non-
Residential
16
Residential
88
■Residential ■Non-Residential
Figure 4-1.2045 Customer Solar Nameplate Capacity(MW)by Sector, Reference Scenario
Figure 4-2 shows the expected customer solar adoption for the two scenarios. The high-incentive
scenario has an incremental 15 MW of new solar capacity relative to the reference scenario (119 MW
vs. 104 MW), which comes from Named Communities.
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Appendix F
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58
57
Named
Named
a 0
Reference High Incentive
Figure 4-2.2045 Customer Solar Nameplate Capacity(MW),by Named Community Status and Scenario
Load Impact
In the reference scenario, 104 MW of new customer solar will yield 127 GWh of load reduction by
2045. The load reduction increases rapidly in the early years of the forecast-2023 through 2030—
but then levels off. This is illustrated in Figure 4-3. The leveling off is caused by Avista's net-energy
metering (NEM) tariffs, which will be sunset in 2029, rendering the economics of customer solar
adoption less attractive. While the team did not investigate a shift in the policy landscape in the two
scenarios, we note that preserving NEM or alternative incentive mechanisms would further increase
the load reduction from customer solar.
M � M O r m O O N M C M O r m O O N M ';IM
N N N N N N N CO M CO M CO M CO M CO M V 7 V 7 V 7
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
0
-20
-40
-60
t
3: -80
0
-100
-120
-140
-160
Year
■Residential ■Non-Residential
Figure 4-3.Annual Customer Solar Load Impact(GWh),Reference Scenario
Table 4-1 summarizes the customer solar load impacts by 2045 for the two scenarios. In the high-
incentive scenario,we forecast an additional 18 GWh load reduction in 2045 relative to the reference
scenario (145 GWh vs. 127 GWh).
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Appendix F
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Table 4-1.2045 Customer Solar Load Impact,by Scenario and Customer Segment
Segment 2045 Load Impact, Reference 2045 Load Impact, High-
Scenario(GWh) Incentive Scenario (GWh)
Residential -107 -125
Non-Residential -20 -20
Total -127 -145
Figure 4-4 illustrates the average daily load reduction (in MWh) from customer solar adoption by
census block group.We expect customer solar adoption to be more diffuse than EV charging,as most
block groups will have less than 5 MWh of daily load reduction in 2045 under the reference scenario.
The most significant solar adoption levels are expected in residential areas with a higher
concentration of single-family homes.
C..,an�
l
Q ,
. .ion.poox000ensveeimeo
Avg Daily MWH
m 0-1 0 1-2 ■ 2-5 ■ 5 or more
Figure 4-4. Locational Customer Solar Load Impact in 2045. Washington Service Territory(Left)and Spokane Region
(Right)
Figure 4-5 shows the hourly load impact shape for customer solar.As is expected, customer solar has
a more considerable load reduction in summer with lower cloud cover and longer daylight hours.The
AEG team forecasts a maximum of 71 MW of solar generation at an hour beginning at 14:00 local time
on a typical July day by 2045. A typical December day will have a significantly reduced generation
profile,with a maximum of 25 MW per hour beginning at 11:00 local time. During the summer season,
at Avista's planning peak for the hour starting at 17:00 local time, we estimate 33 MW of load
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Appendix F
Distributed Energy Resources Potential Study
reduction. Our estimates are based on typical meteorological year data and thus would vary daily
with actual solar irradiance patterns.
0
0 1 2 3 4 5 6 8 9 10 11 12 13 14 5 16 17 18 19 21 2223
-10
-20
2 -30 25 MW
4) maximum 4 33 MW
0--40 generation generation at
f in winter summer
uo-50 planning peak
Q
-60
-70 4- 71 MW maximum
generation in summer
-80
Hour Beginning
—December —July
Figure 4-5 Average Hourly Load Profile for Customer Solar in 2045, Reference Scenario
Customer Wind
Adoption
Currently, customer-sited wind is being adopted minimally in Avista's Washington service territory,
and we do not anticipate substantial adoption in the upcoming years. In total,we forecast a mere 0.4
MW of new customer wind capacity by 2045, and this total does not vary substantively by scenario.
Figure 4-6 shows the AEG team's forecast for customer wind adoption by 2045.
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Appendix F
Distributed Energy Resources Potential Study
Non-
Residential
0.1
Residential
0.3
■Residential ■Non-Residential
Figure 4-6.2045 Customer Wind Nameplate Capacity(MW)
Load Impact
We estimate that customer wind will account for less than 1 MW capacity on a typical day and
generate less than 1 GWh in energy annually by 2045. The team has provided Avista with these
estimates but has excluded charts for annual generation (in MWh) or an hourly profile (in MW) in this
report due to the minimal impact of customer wind.
Customer Battery Storage
Adoption
The current adoption of customer battery energy storage in Avista's Washington service territory is
unknown but likely minimal because Avista does not have programs that cover energy storage.
However, Avista recently introduced a pilot TOU tariff, which creates a tiered rate structure that
incentivizes reduced energy consumption and creates arbitrage opportunities for using energy
storage during peak periods. Our adoption forecast assumes this TOU rate structure is paired with
current technology pricing trends. Figure 4-7. 2045 Customer Storage Nameplate Capacity (MW) by
Sector, Reference Scenario illustrates the results of the customer battery storage nameplate capacity
forecast by 2045. In the reference scenario, we anticipate 74 MW of storage capacity for non-
residential customers and 22 MW for residential customers.
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Appendix F
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Residential
22
No
n-
Residential
74
■Residential ■Non-Residential
Figure 4-7.2045 Customer Storage Nameplate Capacity(MW)by Sector, Reference Scenario
Load Impact
In the reference scenario, 96 MW of customer battery storage will yield a load addition of 2 GWh by
2045 due to round-trip efficiency losses. The hourly shapes depend on the desired state of charge,
charging, and dispatch for TOU rate arbitrage. Figure 4-8 shows the average load profile for customer
storage (MW) in 2045.
The project scope did not include simulating dispatch for demand response or resiliency events.
From a resource planning perspective, such events would influence the typical hourly shape (MW)
but have minimal impact on the annual energy load impact (MWh).
15
10
0
5
C
a
°' 0
3: 0 1 2 3 4 5 6 7 8 9 10 11 12 13 1 15 16 17 18 9 20 21 22 23
00
Q -5
-10
-15
Hour Beginning
—December —July
Figure 4-8.Average Hourly Load Profile for Customer Storage in 2045, Reference Scenario
Ancillary Services
The AEG team assumes that 80%of customers' battery storage capacity is eligible for use in ancillary
services, which allows for some reserve capacity. Thus, the team estimates 77 MW (80% of 96 MW)
of ancillary services potential for customer battery storage, with non-residential customers
Applied Energy Group, Inc. I www.appliedenergygroup.com 22

Appendix F
Distributed Energy Resources Potential Study
accounting for 59 MW and residential customers accounting for 18 MW. Customer solar and wind
generation resources are intermittent due to their weather dependence, so the team assumes these
resources do not offer any potential for ancillary services.
Applied Energy Group, Inc. I www.appliedenergygroup.com 23

Appendix F
Distributed Energy Resources Potential Study
51 CONCLUSIONS AND RECOMMENDATIONS
This section summarizes the results and findings from the DER potential forecast and provides
recommendations for how Avista can update and enhance future DER potential assessments.
Summary Results
The reference scenario in Table 5-1 summarizes the 2045 DER potential results. The residential and
fleet EVSE will have the most significant load impacts in the Avista Washington service territory,
adding nearly 1,700 GWh of energy consumption in 2045. Customer solar will decrease energy
consumption by almost 130 GWh in 2045.
Table 5-1. Summary Results for 2045,Reference Scenario
Share of
NamedNamepLate Annual[Load Nameplate July Peak December
Resource Capacity Impact Capacity in Load Impact' Peak Load
Impact'
Community Customer
Solar 105 127 46% -33 0
Customer
Battery 96 2 58% -3 -9
Storage
Customer 1 -0.3 45% -0.1 0
Wind
Residential 1,544 853 38% 62 62
EVSE
Fleet EVSE 692 841 67% 101 105
Public and
Workplace 171 206 60% 33 33
EVSE
b. The term"peak"refers to a planning peak beginning at 17:00 and ending at 18:00 local time.
Recommendations
As the team notes in the Utility Survey Memo (Appendix B), the current state of DER potential
forecasting is bespoke and faces many of Avista's data gaps.The AEG team recommends six actions
Avista can take before the next iteration of the DER potential study to increase the fidelity and depth
of insights from a location-specific study like this one.
Address Fleet Data Gaps. Forthis study,the team estimated the size and location of commercial
fleets using two methods. First, Avista surveyed commercial vehicle fleets in its service territory,
identifying dozens of smaller fleets. Additionally, the team used secondary data and satellite
imagery to identify many larger fleets in the service territory, including school district buses and
parcel delivery vehicles. While these efforts successfully obtained data from dozens of fleets,
they are not comprehensive and likely undercount smaller LDV fleets. Three activities that the
team recommends that Avista pursue to collect additional fleet data follow:
o Continued outreach to fleet operators. Avista has begun outreach to fleet operators in its
service territory to understand electrification plans and possible charging locations.
Applied Energy Group, Inc. I www.appliedenergygroup.com 25

Appendix F
Distributed Energy Resources Potential Study
Collecting and cleansing data from these outreach activities will advance Avista's ability to
inform forecasting studies.
o Analysis of satellite imagery. Though an imperfect indicator of the presence of vehicle
fleets, satellite imagery is a low-effort method of identifying fleets at Avista's commercial and
industrial service points. Collecting and cleansing data from an analysis of satellite imagery
will advance Avista's ability to inform forecasting studies like this one.
o Acquire fleet inventory data. Washington Department of Ecology is currently conducting a
fleet inventory" that requires fleets with five or more vehicles to register the vehicle types,
counts, and depot locations. The team recommends that Avista pursue this data source for
its service territory when it becomes available.
Develop Commercial EV Charging Profiles. Limited data are available to characterize EVSE
charging profiles, especially for commercial fleets. The AEG Team recommends that Avista
conduct load research on commercial fleet charging.
Develop Seasonal EV Charging Profiles. The team did not have sufficient data to characterize
seasonal differences in EV charging profiles (kW per hour) and driving patterns (vehicle miles
traveled per day), so we assumed the summer and winter charging profiles are the same in
Avista's service territory. However, the winter charging profile could be more significant due to
vehicle cabin space heating or smaller because of less driving in the winter. Therefore, we
recommend that Avista conduct load research on seasonal EV charging.
Conduct Additional Scenario Analyses. The DER adoption forecast analyzed two scenarios: a
reference scenario and a high-incentive scenario. Consider adding additional scenarios to study
the impacts of climate change (e.g., weather, customer grid resiliency) and ancillary services
incentives on DER forecasting.
Integrate the DER and Demand Response (DR) Potential Studies. Some types of DERs, like EV
charging and customer battery storage, can be leveraged in DR events.Therefore, it would benefit
Avista to integrate its DER and DR potential studies to avoid overestimating or underestimating
the combined potential.
Consider Adding Building Electrification. Building electrification and load flexibility can affect
customers' decisions regarding DER installations. Therefore, including building electrification
and associated load control measures (e.g., connected thermostats, heat pump water heater
switches) in future DER potential studies would provide Avista with a more comprehensive
understanding of customer load growth and opportunities to shape it with programs and rates.
Consider Adding Emerging Technologies. Emerging technologies, such as autonomous
vehicles and vehicle-to-grid technologies, can change customer energy consumption patterns.
Therefore, in future DER potential studies,Avista may want to consider emerging technologies as
they become commercially available.
15 Washington Department of Ecology. Fleet Reporting Platform Guidebook for Fleet Managers. August 2023. URL:
https://apps.ecology wa.gov/publications/UlPages/documents/2302068.pdf
Applied Energy Group, Inc. I www.appliedenergygroup.com 26

Appendix F
Distributed Energy Resources Potential Study
A I GLOSSARY
The Glossary section defines terms and acronyms used in this report.
Ancillary Services: Ancillary services help grid operators maintain a reliable electricity system by
ensuring the proper flow and direction of electricity and addressing imbalances between supply and
demand.
BEV: Battery electric vehicle
Customer Solar PV:Customer-sited solar photovoltaic(PV) panels installed behind the utility meter.
Typically, this is rooftop solar PV.
Customer Storage: Customer-sited battery storage installed behind the utility meter.
Customer Wind: Small, customer-sited wind generation installed behind the utility meter.
DCFC: Direct current, fast charging EVSE (50 kW or more)
DLC: Direct load control
DOC:Washington Department of Commerce
EV: Electric vehicle
EVSE: Electric vehicle supply equipment;vehicle chargers
HDV: Heavy-duty vehicle (Class 7 and 8, 26,001 lbs. or more)
ICE: Internal combustion engine vehicle
L1: Level 1 EVSE (typically 1 to 3 kW)
L2: Level 2 EVSE (typically 7 to 22 kW)
LDV: Light-duty vehicle (Class 1 and 2, 0-10,000 lbs.)
MDV: Medium-duty vehicle (Class 3 through 6; 10,001-26,000 lbs.)
Peak Hour: Avista's "Planning peak" is at hour-beginning 17:00/hour-ending 18:00 on weekdays in
July and December. The planning peak may differ from the actual system peak periods.
PHEV: Plug-in hybrid electric vehicle
WUTC:Washington Utilities and Transportation Commission
Applied Energy Group, Inc. I www.appliedenergygroup.com A-1

Appendix F
Distributed Energy Resources Potential Study
6 I UTILITY SURVEY
The memorandum that describes the results from the utility survey(Task 1):
OP n�DF
Avista Task 1 Utility
Survey FINAL Memo_
Applied Energy Group, Inc. I www.appliedenergygroup.com B-1

Appendix F
Distributed Energy Resources Potential Study
C I DER FORECASTING METHODOLOGY
The document that describes the DER forecasting approach (Task 2):
Task 2 DER
Forecasting Method
Applied Energy Group, Inc. I www.appliedenergygroup.com C-1

Appendix F
Distributed Energy Resources Potential Study
D I STAKEHOLDER ENGAGEMENT
During the development of the DER Potential Study,the AEG team and Avista staff engaged with DER
stakeholders several times, including the customer fleet survey Avista conducted in conjunction with
the development of the DER Forecasting Methodology document (Task 2) and the March 27, 2024,
stakeholder meeting when the project team presented and discussed the preliminary DER results
(Task 5). Evidence of DER engagement can be found below.
Avista Customer Fleet Survey:
In late 2023, Avista Utilities engaged MDC Research to survey its commercial and industrial
customers about vehicle fleets and fleet electrification plans. 76 Avista customers completed the
survey, with approximately 2,300 vehicles (LDV, MDV, HDV, and forklifts). The team describes its
approach to using these data in Appendix C (DER Forecasting Methodology) but will keep survey
results private due to the sensitive nature of the responses.
DER Potential Study slides presented at the March 27, 2024, stakeholder meeting(Task 5):
FINAL Avista DER
Potential Study Stakel
Meeting notes from the March 27, 2024, DER Potential Study stakeholder meeting, including a
List of meeting attendees (Task 5):
'!2 DF
Stakeholder meeting
notes March 27,2024
Questions submitted by Washington Utilities and Transportation Commission (WUTC) staff
following the DER Potential Study stakeholder meeting,with answers provided by Avista:
POF
Public Engagement
Appendix D_WUTC
Questions submitted by the Department of Commerce (DOC) staff following the DER Potential
Study stakeholder meeting, with answers provided by Avista:
�0
Public Engagement
Appendix D_DOC Qt
Applied Energy Group, Inc. I www.appliedenergygroup.com D-1

Appendix F
Distributed Energy Resources Potential Study
E I SUPPLEMENTAL ELECTRIC VEHICLE DATA
Table E-1 and Table E-2 summarize the EV adoption and load impact results from the high-incentive
scenario.
Table E-3 through Table E-6 show the EV charging load profiles we used as inputs in the DER Potential
Study.The hourly load profiles are unitized to 1 kW of nameplate capacity. For example, consider the
Fleet HVD DFC C load profiles in Table E-3 where the utilization is 0.473(43.7%) in the hour beginning
at 0:00 on weekdays. Because we assume that Fleet DCFC has a nameplate capacity of 150 kW(see
Table E-7), the assumed kW for a DCFC port in a weekday hour beginning at 0:00 is 0.437 x 150 kW=
66 kW. The 0.437 estimate is a function of nameplate kW, vehicle miles traveled, miles per kW, and
vehicles per port. For a detailed explanation of the utilization estimates, see the DER Forecasting
Methodology document in Appendix C.
Table E-1. Year 2030 Electric Vehicle Results Summary, High-Incentive Scenario
Vehicle Weight Peak ...
Total.Class .
impact(MW) Consumption
LDV 519,499 20% 104,838 26.4 284,418
MDV 16,087 3% 436 3.0 25,913
HDV 10,348 3% 350 2.2 15,646
Total 545,934 19% 105,624 31.6 325,977
Table E-2. Year 2045 Electric Vehicle Results Summary, High-Incentive Scenario
Vehicle Weight Peak Load Annual
TotalClass -. Consumption
impact(MW)
LDV 573,839 74% 426,534 97.8 1,389,054
MDV 17,855 30% 5,434 15.0 286,129
HDV 12,603 37% 4,662 19.3 381,437
Total 604,297 72% 436,630 132.1 2,056,621
Applied Energy Group, Inc. I www.appliedenergygroup.com E-1

Appendix F
Distributed Energy Resources Potential Study
Table E-3. DCFC Charging Load Profiles
School, .. •.
�W,,kd�ayW�,,kencl Weekday Weekend Weekday Weekend Weekday Weekend Weekday Weekend
0 0.437 0.437 0.268 0.268 0.178 0.000 0.361 0.361 0.000 0.000
1 0.328 0.328 0.201 0.201 0.134 0.000 0.181 0.181 0.000 0.000
2 0.260 0.260 0.159 0.159 0.106 0.000 0.090 0.090 0.000 0.000
3 0.164 0.164 0.100 0.100 0.067 0.000 0.054 0.054 0.000 0.000
4 0.137 0.137 0.084 0.084 0.056 0.000 0.018 0.018 0.000 0.000
5 0.191 0.191 0.117 0.117 0.078 0.000 0.005 0.005 0.000 0.000
6 0.273 0.273 0.167 0.167 0.111 0.000 0.005 0.005 0.000 0.000
7 0.232 0.232 0.142 0.142 0.095 0.000 0.006 0.006 0.000 0.000
8 0.260 0.260 0.159 0.159 0.106 0.000 0.006 0.006 0.258 0.258
9 0.246 0.246 0.151 0.151 0.100 0.000 0.005 0.005 0.258 0.258
10 0.273 0.273 0.167 0.167 0.111 0.000 0.018 0.018 0.258 0.258
11 0.164 0.164 0.100 0.100 0.067 0.000 0.045 0.045 0.258 0.258
12 0.109 0.109 0.067 0.067 0.045 0.000 0.072 0.072 0.258 0.258
13 0.123 0.123 0.075 0.075 0.050 0.000 0.090 0.090 0.258 0.258
14 0.068 0.068 0.042 0.042 0.028 0.000 0.086 0.086 0.258 0.258
15 0.055 0.055 0.033 0.033 0.022 0.000 0.077 0.077 0.258 0.258
16 0.109 0.109 0.067 0.067 0.045 0.000 0.054 0.054 0.258 0.258
17 0.328 0.328 0.201 0.201 0.134 0.000 0.027 0.027 0.258 0.258
18 0.711 0.711 0.435 0.435 0.290 0.000 0.072 0.072 0.258 0.258
19 0.547 0.547 0.334 0.334 0.223 0.000 0.316 0.316 0.258 0.258
20 0.519 0.519 0.318 0.318 0.212 0.000 0.519 0.519 0.000 0.000
21 0.355 0.355 0.217 0.217 0.145 0.000 0.596 0.596 0.000 0.000
22 0.683 0.683 0.418 0.418 0.279 0.000 0.542 0.542 0.000 0.000
23 0.601 0.601 0.368 0.368 0.245 0.000 0.474 0.474 0.000 0.000
Note:We assume schools do not charge during the summer months.
Applied Energy Group, Inc. I www.appliedenergygroup.com E-2

Appendix F
Distributed Energy Resources Potential Study
Table E-4. L1 and L2 Fleet Charging Profiles
Fleet �� - chool.
Beginning Weekday Weekend Weekday Weekend Weekday Weekend Weekday Weekend Weekday Weekend
0 0.415 0.415 0.246 0.246 0.175 0.175 0.058 0.058 0.232 0.000
1 0.311 0.311 0.184 0.184 0.131 0.131 0.044 0.044 0.174 0.000
2 0.246 0.246 0.146 0.146 0.104 0.104 0.035 0.035 0.138 0.000
3 0.156 0.156 0.092 0.092 0.066 0.066 0.022 0.022 0.087 0.000
4 0.130 0.130 0.077 0.077 0.055 0.055 0.018 0.018 0.073 0.000
5 0.182 0.182 0.107 0.107 0.077 0.077 0.026 0.026 0.102 0.000
6 0.259 0.259 0.153 0.153 0.110 0.110 0.036 0.036 0.145 0.000
7 0.220 0.220 0.130 0.130 0.093 0.093 0.031 0.031 0.123 0.000
8 0.246 0.246 0.146 0.146 0.104 0.104 0.035 0.035 0.138 0.000
9 0.233 0.233 0.138 0.138 0.099 0.099 0.033 0.033 0.131 0.000
10 0.259 0.259 0.153 0.153 0.110 0.110 0.036 0.036 0.145 0.000
11 0.156 0.156 0.092 0.092 0.066 0.066 0.022 0.022 0.087 0.000
12 0.104 0.104 0.061 0.061 0.044 0.044 0.015 0.015 0.058 0.000
13 0.117 0.117 0.069 0.069 0.049 0.049 0.016 0.016 0.065 0.000
14 0.065 0.065 0.038 0.038 0.027 0.027 0.009 0.009 0.036 0.000
15 0.052 0.052 0.031 0.031 0.022 0.022 0.007 0.007 0.029 0.000
16 0.104 0.104 0.061 0.061 0.044 0.044 0.015 0.015 0.058 0.000
17 0.311 0.311 0.184 0.184 0.131 0.131 0.044 0.044 0.174 0.000
18 0.674 0.674 0.399 0.399 0.285 0.285 0.095 0.095 0.377 0.000
19 0.519 0.519 0.307 0.307 0.219 0.219 0.073 0.073 0.290 0.000
20 0.493 0.493 0.292 0.292 0.208 0.208 0.069 0.069 0.276 0.000
21 0.337 0.337 0.199 0.199 0.142 0.142 0.047 0.047 0.189 0.000
22 0.648 0.648 0.384 0.384 0.274 0.274 0.091 0.091 0.363 0.000
23 0.570 0.570 0.338 0.338 0.241 0.241 0.080 0.080 0.319 0.000
Note:We assume schools do not charge during the summer months.
Applied Energy Group, Inc. I www.appliedenergygroup.com E-3

Appendix F
Distributed Energy Resources Potential Study
Table E-5. Residential L 1 and L2 Charging Profiles
Hour L1, Residential BEV and L2, Residential PHEV L2, Residential BEV
PHEV
Beginning
Weekday Weekend Weekday Weekend Weekday Weekend
0 0.405 0.375 0.029 0.027 0.104 0.096
1 0.366 0.328 0.026 0.023 0.094 0.084
2 0.345 0.315 0.025 0.023 0.089 0.081
3 0.379 0.341 0.027 0.024 0.097 0.088
4 0.366 0.332 0.026 0.024 0.094 0.085
5 0.302 0.251 0.022 0.018 0.078 0.065
6 0.162 0.085 0.012 0.006 0.042 0.022
7 0.102 0.038 0.007 0.003 0.026 0.010
8 0.081 0.051 0.006 0.004 0.021 0.013
9 0.077 0.055 0.005 0.004 0.020 0.014
10 0.055 0.051 0.004 0.004 0.014 0.013
11 0.072 0.047 0.005 0.003 0.019 0.012
12 0.094 0.064 0.007 0.005 0.024 0.016
13 0.115 0.072 0.008 0.005 0.030 0.019
14 0.119 0.072 0.009 0.005 0.031 0.019
15 0.124 0.094 0.009 0.007 0.032 0.024
16 0.102 0.136 0.007 0.010 0.026 0.035
17 0.136 0.158 0.010 0.011 0.035 0.041
18 0.162 0.175 0.012 0.012 0.042 0.045
19 0.196 0.204 0.014 0.015 0.050 0.053
20 0.264 0.285 0.019 0.020 0.068 0.073
21 0.375 0.405 0.027 0.029 0.096 0.104
22 0.413 0.430 0.030 0.031 0.106 0.111
23 0.413 0.439 0.030 0.031 0.106 0.113
Applied Energy Group, Inc. www.appliedenergygroup.com E-4

Appendix F
Distributed Energy Resources Potential Study
Table E-6. Public and Workplace Charging Profiles
Weekday Weekend Weekday Weekend Weekday Weekend
0 0.000 0.000 0.111 0.111 0.064 0.064
1 0.000 0.000 0.086 0.086 0.049 0.049
2 0.000 0.000 0.079 0.079 0.046 0.046
3 0.000 0.000 0.079 0.079 0.045 0.045
4 0.000 0.000 0.064 0.064 0.037 0.037
5 0.001 0.000 0.066 0.066 0.038 0.038
6 0.007 0.000 0.088 0.088 0.051 0.051
7 0.024 0.000 0.130 0.130 0.075 0.075
8 0.045 0.000 0.190 0.190 0.109 0.109
9 0.046 0.000 0.277 0.277 0.159 0.159
10 0.042 0.000 0.371 0.371 0.213 0.213
11 0.036 0.000 0.398 0.398 0.229 0.229
12 0.028 0.000 0.538 0.538 0.309 0.309
13 0.031 0.000 0.514 0.514 0.296 0.296
14 0.035 0.000 0.432 0.432 0.248 0.248
15 0.037 0.000 0.452 0.452 0.260 0.260
16 0.028 0.000 0.392 0.392 0.225 0.225
17 0.011 0.000 0.345 0.345 0.198 0.198
18 0.004 0.000 0.314 0.314 0.180 0.180
19 0.001 0.000 0.317 0.317 0.182 0.182
20 0.001 0.000 0.209 0.209 0.120 0.120
21 0.001 0.000 0.169 0.169 0.097 0.097
22 0.000 0.000 0.149 0.149 0.086 0.086
23 0.000 0.000 0.150 0.150 0.086 0.086
Applied Energy Group, Inc. I www.appliedenergygroup.com E-5

Appendix F
Distributed Energy Resources Potential Study
Table E-7. Charging Nameplate kWAssumptions
Charging Use Case Nameplate kW
L1, Residential BEV and PHEV 1.5
L1, Fleet LDV 1.5
L2, Residential BEV 7.0
L2, Residential PHEV 7.0
L2,Fleet HDV 19.2
L2, Fleet LDV 19.2
L2, Fleet MDV 19.2
L2,School 19.2
DCFC,Fleet HDV 150.0
DCFC, Fleet MDV 150.0
DCFC,School 50.0
DCFC,Transit Depot 150.0
DCFC,Transit Route 450.0
Public L2 11.5
Public DCFC 150.0
Workplace L2 11.5
Final Section Note
DO NOT ADD ANY CONTENT AFTER THE FOLLOWING EVEN PAGE BREAK
Applied Energy Group, Inc. I www.appliedenergygroup.com E-6

APPLIED ENERGY GROUP
Applied Energy Group, Inc.
2300 Clayton Rd., Suite 1370
Concord, CA 9450

Appendix G
2025 Electric Integrated
Resource Plan
Appendix G — Public Input and
Results Data
°,VV 1sra

Appendix G
Please see folders with the following data files:
• Energy Efficiency Avoided Costs
0 2025 IRP PRiSM 062524 No EE
0 2025_IRP_PRiSM_062524_No EE_Capacity Only
0 2025 IRP PRiSM 062524 No EE No Build
o EE Avoided Cost 062424 Final
• Modeling Inputs
o CCA Price Forecast
o Load Forecast and Scenarios
o Natural Gas Price Forecast
o Social Cost of Carbon
o Supply Side Resource Options
• Named Community Maps
o CEAP Update — Named Communities Clarkston
o CEAP Update — Named Communities Main Area
o CEAP Update — Named Communities Spokane
• PRiSM Model Files
0 0_2025_IRP_PRiSM_082724_Energy Efficiency Solution
0 1 2025 IRP PRiSM 082724 PRS
0 2 2025 IRP PRiSM 082724 Alt Reasonable Lowest Cost
0 3 2025 IRP PRiSM 071924 Baseline
0 4 2025 IRP PRiSM 082724 Clean Resource Portfolio
0 4_2025_IRP_PRiSM_082724_Clean Resource Portfolio_Higher PRM
0 5 2025 IRP PRISM 082724 Low Load
0 6_2025_IRP_PRiSM_082724_High Load
0 7_2025_IRP_PRiSM_091124_WA Building Electrification
0 8_2025_IRP_PRiSM_091124_WA Building & High Transportation
Electrification
0 9_2025_IRP_PRiSM_091124_WA Building & Transportation
Electrification- no new ng
0 10 2025 IRP PRiSM 09114 WA Max Customer Benefits
0 11 2025 IRP PRiSM 082724 500 MW Nuclear
0 12 2025 IRP PRiSM 082724 17% PRM
0 13 2025 IRP PRiSM 082724 30% PRM
0 14 2025 IRP PRiSM 082724 P2G Unavailable
0 15_2025_IRP_PRiSM_082724_Min CETA Target
0 16_2025_IRP_PRiSM_082724_Max CETA Target
0 17_2025_IRP_PRiSM_082724_PRS Cost Cap Constrained
0 18 2025 IRP PRiSM 091124 Data Center
0 19 2025 IRP PRiSM 082724 RCP 8.5 Load

Appendix G
0 20_2025_IRP_PRiSM_082724_System Building & Transportation
Electrification No new NGRCP8.5
0 21_2025_IRP_PRiSM_082724_No Regional Transmission
0 22 2025 IRP PRiSM 082724 NE Retire 2026
0 23 2025 IRP PRiSM 082724 200 MW Low Cost Wind Limit
0 24 2025 IRP PRiSM 082724 No IRA Tax Incentives
0 25 2025 IRP PRiSM 082724 2035 NE Retire
o Resource Portfolio Summary
• Weather Data
o Climate Change Temperature Data for Load Forecast RCP4.5
o Climate Change Temperature Data for Load Forecast RCP8.5
o Comparison 2020-24 RCP4.5 RCP8.5 and Actual
o Peak and Energy Forecast Climate Data

Appendix G

2025 Electric Integrated
Resource Plan
Appendix H — Confidential Inputs
and Models
Idaho — Confidential pursuant to Sections 74-109, Idaho Code
Washington — Confidential per WAC 480-07-160
�� iilSTA

Appendix H
Appendix H Content
The Company makes data input files in native format, models, and other various content used for its Integrated Resource
Planning process available to stakeholders. Non-confidential, non-proprietary IRP content can also be found at Integrated
Resource Planning (myavista.com). In a manner to further increase transparency and provide clarity for stakeholders, the
following table provides context on data files, models and other content included in Appendix H.
File/Folder Name Folder File Type Description of Content
01—Preferred Resource Strategy ARAM-Reliability Excel Reliability and market reliance study for select year.
Studies
03—Baseline ARAM-Reliability Excel Reliability and market reliance study for select year.
Studies
04—Clean Resource Portfolio by ARAM-Reliability Excel Reliability and market reliance study for select year.
2045 Studies
09_System Building and ARAM-Reliability Excel Reliability and market reliance study for select year.
Transportation Electrification Studies
11_Least Cost + 500 MW ARAM-Reliability Excel Reliability and market reliance study for select year.
Nuclear in 2040 Studies
12_17% PRM ARAM-Reliability Excel Reliability and market reliance study for select year.
Studies
13_30% PRM ARAM-Reliability Excel Reliability and market reliance study for select year.
Studies
14—Power to Gas Unavailable ARAM-Reliability Excel Reliability and market reliance study for select year.
Studies
18—Data Center Load ARAM-Reliability Excel Reliability and market reliance study for select year.
Studies
2025 IRP Confidential Inputs Aurora Excel Aurora inputs
2023 IRP Aurora Aurora zip Includes deterministic, stochastic, change sets,
Stochastic—Archive04O22024 market scenarios — high natural gas, low natural
gas, national CO2 price and Aurora database for
US/Canada.
Avista Corp 2021 Electric IRP 1

Appendix H
2026-2045 Hourly CETA NA Excel Hourly Dispatch Analysis using Aurora Dispatch
Analysis with Aurora Dispatch
2045 Hourly CETA Analysis NA Excel Hourly CETA Analysis in ARAM — verifying reliability
Optimized Dispatch in 2045
Avista L&R Report NA Excel Avista L&R position
Avista Corp 2021 Electric IRP 2

This Page is Intentionally Left Blank

Appendix 1
2025 Electric Integrated
Resource Plan
Appendix I — Confidential
Historical Generation Operation
Data
Idaho — Confidential pursuant to Sections 74-109, Idaho Code
Washington — Confidential per WAC 480-07-160
�i -VISTA

Appendix I
This Page is Intentionally Left Blank

Appendix J
2025 Electric Integrated
Resource Plan
Appendix J — New Resource
Table for Transmission
�4VIsra

Appendix J
Appendix J
New Resource (>1 MW) Table For Transmission
Resource Capacity Year
Resource Note Location POR POD Start Stop MW Total
Wind E. Washington AVA.SYS AVA.SYS 1/1/2029 Indefinite 200.0 200.0
Wind E. Washington AVA.SYS AVA.SYS 1/1/2030 Indefinite 200.0
Natural Gas CT Rathdrum CT Site Rathdrum, ID AVA.SYS AVA.SYS 1/1/2030 Indefinite 90.0 290.0
Wind E. Washington AVA.SYS AVA.SYS 1/1/2031 Indefinite 100.0
Wind Montana Colstrip/BPA AVA.SYS 1/1/2031 Indefinite 100.0 200.0
Wind Montana Colstrip/BPA AVA.SYS 1/1/2032 Indefinite 100.0 100.0
Wind Off-System BPA AVA.SYS 1/1/2033 Indefinite 157.0 157.0
Renewable Fueled CT Greensferry Rd Rathdrum, ID AVA.SYS AVA.SYS 1/1/2040 Indefinite 90.2
Natural Gas CT Rathdrum CT Site Rathdrum, ID AVA.SYS AVA.SYS 1/1/2040 Indefinite 90.2 180.4
Wind PPA Replacement Big Bend Area AVA.SYS AVA.SYS 1/1/2041 Indefinite 140.0 140.0
Renewable Fueled CT Greensferry Rd Rathdrum, ID AVA.SYS AVA.SYS 1/1/2042 Indefinite 209.8
Natural Gas CT Rathdrum CT Site Rathdrum, ID AVA.SYS AVA.SYS 1/1/2042 Indefinite 94.9 304.7
Wind PPA Replacement Whitman County, WA AVA.SYS AVA.SYS 1/1/2043 Indefinite 120.0
Solar+ Energy Storage Asotin County, WA AVA.SYS AVA.SYS 1/1/2043 Indefinite 180.0 300.0
Solar+ Energy Storage TBD AVA.SYS AVA.SYS 1/1/2044 Indefinite 120.0
Energy Storage Boulder Park Spokane Valley, WA AVA.SYS AVA.SYS 1/1/2044 Indefinite 26.1
Wind Off-System BPA AVA.SYS 1/1/2044 Indefinite 108.4 254.5
Nuclear Off-System BPA AVA.SYS 1/1/2045 Indefinite 100.0
Kettle Falls Upgrade & Unit 2 Kettle Falls, WA AVA.SYS AVA.SYS 1/1/2045 Indefinite 67.6
Energy Storage TBD AVA.SYS AVA.SYS 1/1/2045 Indefinite 85.3
Geothermal Off-System BPA AVA.SYS 1/1/2045 Indefinite 20.0
Wind Off-System BPA AVA.SYS 1/1/2045 Indefinitel 200.0 1472.9
2599.5 2599.5
Does not include generation related to ammonia production

Appendix K
2025 Electric Integrated
Resource Plan
Appendix K — Washington State
Schedule 62 ( Partially
Confidential )

Appendix K
Fourteenth Revision Sheet 62
Canceling
WN U-28 Seventh Substitute Thirteenth Revision Sheet 62 62
AVISTA CORPORATION
dba Avista Utilities
SCHEDULE 62
QUALIFYING FACILITIES
WASHINGTON
AVAILABLE:
In all the electric territory served by Avista in the State of Washington.
APPLICABILITY:
Except as expressly provided herein, this schedule is only applicable to any individual,
partnership, corporation, association, governmental agency, political subdivision,
municipality, or other entity(the"Customer")installing, owning and generating electricity for
delivery to the Company at a point of delivery on the Company's electrical system in the State
of Washington where: a) the facility is a Qualifying Facility ("QF"), meaning either a
cogeneration facility or a small power production facility,pursuant to Section 201 of the Public
Utility Regulatory Policies Act of 1978 and defined in WAC Chapter 480-106, and b) output
is offered for sale to Avista pursuant to WAC Chapter 480-106.
Avista's contracting procedures and standard contract provisions filed with the
Commission shall be used where applicable.
POWER RATES:
Avista will pay the following avoided cost rates for delivered electricity, paid in United
States dollars based on megawatt-hour(or partial megawatt-hour)production:
I. Power Rate Options Available to Qualifying Facilities with a nameplate rating of five
(5) megawatts alternating current(MW-AC) or less.
(1) Specified Term—Standard Power Rates
(a) Total payment will be the summation of energy and applicable capacity values
in their associated tables. (D)
(b) This schedule includes compensation for RECs; they become the property of (T)
Avista.
Issued October 26, 2022 Effective January 1, 2023
Issued by Avista Corporation
By Patrick Ehrbar, Director, Regulatory Affairs
V

Appendix K
Sixth Revision Sheet 62A
Canceling
WN U-28 Substitute Fifth Revision Sheet 62A
AVISTA CORPORATION
dba Avista Utilities
(N)(D)
o
3
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Issued November 1, 2024 Effective January 1, 2025
Issued by Avista Corporation
By Patrick Ehrbar, Director, Regulatory Affairs
V � .

Appendix K
Fifth Revision Sheet 62B
Canceling
WN U-28 Substitute Fourth Revision Sheet 62B
AVISTA CORPORATION
dba Avista Utilities
(N)(D)
E
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Issued November 1, 2024 Effective January 1, 2025
Issued by Avista Corporation
By Patrick Ehrbar, Director, Regulatory Affairs
Q01j. r . a�

Appendix K
Third Revision Sheet 62C
Canceling
WN U-28 Substitute Second Revision Sheet 62C
AVISTA CORPORATION
dba Avista Utilities
(N)(D)
v
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azc az ° d e ro 11V
Issued November 1, 2024 Effective January 1, 2025
Issued by Avista Corporation
By Patrick Ehrbar, Director, Regulatory Affairs
PCL ��

Appendix K
Fifth Revision Sheet 62D
Canceling
WN U-28 Substitute Fourth Revision Sheet 62D
AVISTA CORPORATION
dba Avista Utilities
(N)(D)
v
0
3
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Issued November 1, 2024 Effective January 1, 2025
Issued by Avista Corporation
By Patrick Ehrbar, Director, Regulatory Affairs
Qavr . a�

Appendix K
Fifth Revision Sheet 62E
Canceling
WN U-28 Substitute Fourth Revision Sheet 62E
AVISTA CORPORATION
dba Avista Utilities
(N)(D)
v
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U N � v; � eo
Issued November 1, 2024 Effective January 1, 2025
Issued by Avista Corporation
By Patrick Ehrbar, Director, Regulatory Affairs
Qavr . a�

Appendix K
Third Revision Sheet 62F
Canceling
WN U-28 Substitute Second Revision Sheet 62F
AVISTA CORPORATION
dba Avista Utilities
(N)(D)
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Issued November 1, 2024 Effective January 1, 2025
Issued by Avista Corporation
By Patrick Ehrbar, Director, Regulatory Affairs
Qavr . a�

Appendix K
Third Revision Sheet 62G
Canceling
WN U-28 Substitute Second Revision Sheet 62G
AVISTA CORPORATION
dba Avista Utilities
(N)(D)
E
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Issued November 1, 2024 Effective January 1, 2025
Issued by Avista Corporation
By Patrick Ehrbar, Director, Regulatory Affairs
PCL ��

Appendix K
Third Revision Sheet 62H
Canceling
WN U-28 Substitute Second Revision Sheet 62H
AVISTA CORPORATION
dba Avista Utilities
(N)(D)
E
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Issued November 1, 2024 Effective January 1, 2025
Issued by Avista Corporation
By Patrick Ehrbar, Director, Regulatory Affairs
r-

Appendix K
Second Revision Sheet 621
Canceling
WN U-28 First Revision Sheet 621
AVISTA CORPORATION
dba Avista Utilities
(2) Short Term—Time of Delivery Power Rates (M)(K)
(a) Total payment will be the summation of the energy and applicable capacity
payment on a per-delivered MWh basis.
(b) The energy payment shall be equal to the summation of all metered net output of
the QF multiplied by the Powerdex Hourly Mid-Columbia Electricity Index("Mid-
C Index")price in effect at the time of the delivery.Where the Mid-C Index ceases
to exist, its successor will be used. Where no successor exists, another index shall
be agreed to by the parties.
(c) The capacity payment will be the "Levelized Hourly Capacity Values Applied to )(D
All Sales in All Contract Years Based on First Year of Contract Delivery
($/MWh)"rates from the Specified Term—Standard Power Rates section
applicable to the QF resource type. )(D
(d) This schedule does not provide compensation for RECs; they remain the property
of the customer.
(3) As-Available Power Rates
The As-Available Power Rate shall apply to all customers providing QF output to the
Company on an as-available basis. It shall be based on the Powerdex hourly Mid-C Index
for electricity, calculated on an hourly or monthly basis as determined by the Company.
Where the Mid-C Index ceases to exist, its successor will be used. Where no successor
exists, another index shall be agreed to by the parties. There will be no capacity payment
made for As-Available deliveries. This schedule does not provide compensation for RECs;
they remain the property of the customer.
II. Power Rates Available to Qualifying Facilities with a nameplate rating exceeding five (5)
MW-AC.
(1) IRP-Based Rates — IRP-Based Rates are calculated using a Commission-approved
methodology. In the absence of an approved methodology, IRP-Based Rates will be
calculated in a manner consistent with the last acknowledged Integrated Resource Plan.
For illustrative purposes, the present forecasts of capacity and energy, both independently
and combined, are provided below. (M)(K)
(M)Material transferred from Seventh Substitute Original Revision sheet 62C.
(K)Material transferred to Original Sheet 62N.
Issued October23, 2023 Effective January 1, 2024
Issued by Avista Corporation
By Patrick Ehrbar, Director, Regulatory Affairs
r

Appendix K
Third Revision 62J
Canceling
WN U-28 Substitute Second Revision Sheet 62J
AVISTA CORPORATION
dba Avista Utilities
(N)(D)
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mop n 'v�11^No oe O 0� On � � � r9i• Mam � `� ^n $ `ANm •^Npe r°g. ^ � E � D � '�^ °c vvi aqc mL C m N ti 7 ry m m
� $ � ° w 'o_ 0 a = S
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N N 00 00 ti N N r M M O O N N O .y O^i 10 T O ti W $ T M O N N O N N p Q « p
pmp y h op 1� Ih o pp p y pp r T a N O 1� W OI C C t
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aZ � aZ � iN 4Mi i 16 1 d (N)(D)
Issued November 1, 2024 Effective January 1, 2025
Issued by Avista Corporation
By Patrick Ehrbar, Director, Regulatory Affairs

First Revision 62K Appendix K
Canceling
WN U-28 Fifth Substitute Original Sheet 62K
AVISTA CORPORATION
dba Avista Utilities
(2) As-Available Power Rates—The As-Available Power Rate will be negotiated on a case- (M)(K)
by-case basis reflecting the unique attributes of the QF facility and the Company's
avoided costs.
(3) Non-Binding Term Sheets for QFs with nameplate capacities exceeding 5 MW-AC can
be found at: hllps://myavista.com/about-us/services-and-resources/interconnection.
III. Contracting Procedures.
These contracting procedures are provided by Avista pursuant to WAC 480-106-030(2)
and apply to Qualifying Facilities. They apply to any Customer intending to contract
to deliver the output from its Qualifying Facility to the Company at a point of delivery
on the Company's electrical system in the State of Washington. These contracting
procedures may be adjusted periodically.
(1) Procedures
A. To obtain an indicative pricing proposal for a proposed Qualifying Facility, the
Customer shall provide the Company information that is reasonably required to
develop such a proposal. Indicative pricing for facilities with a nameplate
generation capacity of five megawatts (5 MW) or less shall be the Power Rates
contained in this schedule. Existing Qualifying Facilities that are seeking to
renew an expiring contract with Avista are not required to provide information
previously provided to Avista, but shall provide Avista any updates to the
information previously provided. General information regarding a Qualifying
Facility shall include:
i) Qualifying Facility owner name, organizational structure and chart,
and contact information;
ii) generation and other related technology applicable to the Qualifying
Facility;
iii) design capacity, station service requirements, and the net amount of
power, all in kilowatts (M), to be delivered to the Company's electric
system by the Qualifying Facility;
iv) schedule of estimated Qualifying Facility electric output, in an
8,760-hour electronic spreadsheet format;
v) ability, if any, of Qualifying Facility to respond to dispatch orders
from the Company;
(K)Material transferred to Original Sheet 62P. (M)(K)
(M)Material transferred from Fifth Substitute Original Revision Sheet 62F.
Issued October 26, 2022 Effective January 1, 2023
Issued by Avista Corporation
By Patrick Ehrbar, Director, Regulatory Affairs
r-

Appendix K
WN U-28 Original Sheet 62L
AVISTA CORPORATION
dba Avista Utilities
vi)map of Qualifying Facility location,electrical interconnection point,and (M)
point of delivery;
vii) anticipated commencement date for delivery of electric output;
viii) list of acquired and outstanding Qualifying Facility permits, including
a description of the status and timeline for acquisition of any outstanding
permits;
ix) demonstration of ability to obtain Qualifying Facility status;
x) fuel type(s) and source(s);
xi) plans to obtain, or actual, fuel and transportation agreements, if
applicable;
xii) where Qualifying Facility is or will be interconnected to an electrical
system besides the Company's, plans to obtain, or actual, electricity
transmission agreements with the interconnected system; and
xiii) interconnection agreement status.
B. Where the Company determines that the Customer has not provided some or all of
the information that is required by Section(1)A,the Company shall,within ten(10)
business days of the date that Customer provides information to the Company
pursuant to Section(1)A, notify the Customer in writing of any deficiencies.
C. Following the Company's receipt of all information required in Section (1)A, the
Company shall, within twenty (20) business days of such receipt of information,
provide the Customer with an indicative pricing proposal containing terms and
conditions tailored to the individual characteristics of the proposed Qualifying
Facility; provided, however, that for Qualifying Facilities eligible for Published
Rates pursuant to the Washington Utilities and Transportation Commission's
eligibility requirements, the indicative pricing proposal shall be the Power Rates
contained in this schedule which shall be deemed to be provided to the Customer
on the day the Company receives all of the information required in Section (1)A
and the proposed non-price terms and conditions shall be as set forth in the Form
of Power Purchase Agreement for Small Qualifying Facilities on file with the
Washington Utilities and Transportation Commission.
(M)Material transferred from Fifth Substitute Original Sheet 62G. (M)
Issued October 26, 2022 Effective January 1, 2023
Issued by Avista Corporation
By Patrick Ehrbar, Director, Regulatory Affairs
r-

Appendix K
WN U-28 Original Sheet 62M
AVISTA CORPORATION
dba Avista Utilities
(M)(D)
D. The indicative pricing proposal provided to the Customer pursuant to Section(1)C
will not be final or binding on either party. Prices and other terms and conditions
will become final and binding on the parties under only two conditions:
i) The prices and other terms contained in a power purchase agreement
shall become final and binding upon full execution of such power purchase
agreement by both parties, or
ii) If an irreconcilable disagreement arises during the contracting
process, the Company or the Customer may petition the Washington
Utilities and Transportation Commission to resolve the disagreement,
which may include making a determination about whether the Customer is
entitled to a legally enforceable obligation in the absence of a fully executed
power purchase agreement for the output of such Qualifying Facility and, if
so, the date such legally enforceable obligation occurred.
E. If the Customer desires to proceed with contracting its Qualifying Facility with the
Company after reviewing the indicative pricing proposal provided in accordance
with Section (1)C, it shall provide the Company with any additional information
that the Company reasonably determines necessary for the preparation of a draft
power purchase agreement,which shall include:
i) updated information of the categories described in Section (1)A;
ii) evidence of site control for the entire contracting term;
iii) anticipated timelines for completion of key Qualifying Facility
milestones, to include:
a. licenses,permits, and other necessary approvals;
b. funding;
c. Qualifying Facility engineering and drawings;
d. significant equipment purchases;
e. construction agreement(s);
£ interconnection agreement(s); and
g. signing of third-party transmission agreements, where applicable; and, (M)
(M)Material transferred from Fifth Substitute Original Sheet 62H.
Issued October 26, 2022 Effective January 1, 2023
Issued by Avista Corporation
By Patrick Ehrbar, Director, Regulatory Affairs

Appendix K
WN U-28 Original Sheet 62N
AVISTA CORPORATION
dba Avista Utilities
iv) additional information as explained in the Company's indicative pricing (M)
proposal.
F. If the Company determines that the Customer has not provided sufficient
information as required by Section (1)E, the Company shall, within ten (10)
business days of the date that Customer provides information to the Company
pursuant to Section (1)E, notify the Customer in writing of any deficiency.
G. Following satisfactory receipt of all information required in Section (1)E, the
Company shall, within fifteen (15) business days of the Company's receipt of
the information required in Section (1)E, provide the Customer with a draft
power purchase agreement containing a comprehensive set of proposed terms
and conditions; provided, however, that for Qualifying Facilities that are
eligible for Published Rates pursuant to the Washington Utilities and
Transportation Commission's eligibility requirements,the draft power purchase
agreement shall be the Form of Power Purchase Agreement for Small
Qualifying Facilities on file with the Washington Utilities and Transportation
Commission. The draft power purchase agreement provided to the Customer
pursuant to this Section(1)G shall serve as the basis for subsequent negotiations
between the parties and, unless clearly indicated, shall not be construed as a
binding proposal by the Company.
H. Within ninety (90) calendar days after its receipt of the draft power purchase
agreement from the Company pursuant to Section (1)G, the Customer shall
review the draft power purchase agreement and shall: i)notify the Company in
writing that it accepts the terms and conditions of the draft power purchase
agreement and is ready to execute a power purchase agreement with same or
similar terms and conditions as the draft contract; or ii) provide the Company
with written comments and proposals based on the draft power purchase
agreement.The Company shall not be obligated to commence negotiations with
a Customer or draft a final power purchase agreement unless or until the
Company has timely received an initial set of written comments and proposals
from the Customer, or notice from the Customer that it has no such comments
or proposals, in accordance with this Section(1)H.
I. After Customer has satisfied the requirements set forth in Section (1)H above,
unless the Customer has notified the Company in writing that it accepts the
terms and conditions of the draft power purchase agreement and that it does not
have any additional issues to discuss prior to executing a final power purchase
agreement, Customer shall contact the Company to schedule a meeting to negotiate
or discuss any issues regarding the draft power purchase agreement. (M)
M Material transferred from Fifth Substitute Original Sheet 62I.
Issued October 26, 2022 Effective January 1, 2023
Issued by Avista Corporation
By Patrick Ehrbar, Director, Regulatory Affairs
V

Appendix K
WN U-28 Original Sheet 620
AVISTA CORPORATION
dba Avista Utilities
The Company may request such a meeting if it has any issues regarding the (M)
Qualifying Facility or draft power purchase agreement that it wants to discuss
with the Customer prior to executing a final power purchase agreement. All
meetings scheduled pursuant to this Section (1)(I) shall be scheduled at such
times and places as are mutually agreeable to the parties.
J. In connection with any contract negotiations between the Company and the
Customer, the Company:
i) shall not unreasonably delay negotiations and shall respond in good
faith to any additions,deletions or modifications to the draft power purchase
agreement that are proposed by the Customer;
ii) may request to visit the site of the proposed Qualifying Facility if
such a visit has not previously occurred;
iii) shall update its pricing proposals at appropriate intervals to
accommodate any changes to the Company's avoided-cost calculations,the
proposed Qualifying Facility or proposed terms of the draft power purchase
agreement;
iv) may request any additional information from the Customer
necessary to finalize the terms of the power purchase agreement and to
satisfy the Company's due diligence with respect to the Qualifying Facility.
K. When both parties are in full agreement as to all terms and conditions of the
draft power purchase agreement, including the price to be paid for delivered
power pursuant to such draft agreement, the Company shall prepare and
forward to the Customer, within ten (10) business days, a final, executable
version of the power purchase agreement.
L. The Customer shall, within sixty (60) business days of its receipt of a final,
executable version of the power purchase agreement, execute and return the
final power purchase agreement to the Company.
M. Where the Customer timely executes and returns the final power purchase
agreement to the Company in accordance with Section(1)L,the Company will,
within sixty (60) business days of its receipt of the power purchase agreement
executed by the Customer, execute such power purchase agreement.
N. Failure of the Customer to meet any timelines set forth in this Section relieves
the Company of any obligation under this tariff until such time as the Customer (M)
(M)Material transferred from Original Sheet 62N and Fifth Substitute Original Sheet 62J.
Issued October 26, 2022 Effective January 1, 2023
Issued by Avista Corporation
By Patrick Ehrbar, Director, Regulatory Affairs
V

Appendix K
WN U-28 Original Sheet 62P
AVISTA CORPORATION
dba Avista Utilities
resubmits its Qualifying Facility and the procedures begin anew. If the (M)
Customer does not execute the final power purchase agreement per Section
(1)L, such final power purchase agreement shall be deemed withdrawn and the
Company shall have no further obligation to the Customer under this tariff
unless or until such time the Customer resubmits the Qualifying Facility to the
Company in accordance with this Schedule.
(2) The Company's obligation to purchase a Qualifying Facility's energy and/or
capacity is conditioned upon the Qualifying Facility obtaining a valid
interconnection agreement prior to its first delivery of such output. Where the
Qualifying Facility will be interconnected to a third-party electrical system, the
Company's obligation to purchase such electrical output will be conditioned on
the Customer obtaining a firm transmission agreement or agreements to deliver
electrical output to the Company's system for the term of the power purchase
agreement. (M)
(M)Material transferred from Fifth Substitute Original Sheet 62K.
Issued October 26, 2022 Effective January 1, 2023
Issued by Avista Corporation
By Patrick Ehrbar, Director, Regulatory Affairs
r-

2025 Electric Integrated
Resource Plan
Appendix M — Public Comments
��AVISTA

Appendix M: Public Comments- Public Meeting
Avista's Natural Gas & Electric Integrated Resource Plan Public Meeting and Public Comments
November 13, 2024
Avista held two Integrated Resource Planning public meetings on November 13, 2024 in an on-line
format. Invitations to the meeting were sent to all customers with emails and to all advisory committee
members. Meetings were held at 7:30 am and 12:00 pm. The meeting discussed the draft resource plan
for the 2025 Electric IRP.
This document summarizes feedback from the participants from these meetings including:
1) Poll Question Results
2) Table of Questions and Answers
3) Follow-up Email Correspondence
In addition to questions asked during the public meeting, questions and comments asked by the general
public via's Avista's IRP comment form are also included.
Avista Corp 2025 Electric IRP 1

Appendix M: Public Comments- Public Meeting
These are results of the poll questions given to the audiences for both public meeting webinars.
Webinar Poll Questions
What would you prioritize among the choices below, acknowledging that they are all important?
• Environmental issues— 11
• A reliable system—39
• Affordability—29
• Equitable investments—2
What type of Demand Response program interests you?
• Different electric prices by time or day or season (time of use)—28
• Paid to reduce if utility notifies of an opportunity(peak time rebate)—37
• Utility controls your thermostat or water heater(direct load control)—3
• None interest me— 12
What resource technology should prioritize to meet future demand?
• Solar- 13
• Wind -8
• Energy Storage- Batteries— 11
• Natural Gas— 17
• Nuclear—31
Avista Corp 2025 Electric IRP 2

Appendix M: Public Comments- Public Meeting
Participant Questions/Comments During the Meetings
Avista answered many questions during the two events, below is a list of comments and questions from
these meetings with responses.
Question Avista Response
What assumptions does your model use regarding Avista's load forecast includes both population
population growth in the geographic areas you growth and changes in electric use per customer.
serve?And are you planning for growth in the size The annual average customer growth rate used in
of that service area also? the end use load forecast for all sectors was 0.6%
for Washington and 0.7% in Idaho.
Will the passing of initiative 2066 impact electric The passing of initiative 2066 protects access to
load forecast (reducing load)? natural gas for residents and businesses. This
could reduce electric load relative to assumptions
on electrification.
Do you anticipate an increase in the use of ground While ground source heat pumps are one of the
source heat pumps to reduce electricity used by most efficient ways to heat your home, the cost of
standard heat pumps (formerly known as air equipment and installation has always been the
conditioning)? stumbling block for customers and Avista does not
expect a change in adoption rates unless the net
benefits of the technology change.
You missed the load that electric vehicles add Avista includes forecasts for customer-owned
electric vehicles as part of its load forecast.
Since you purchase energy from Power Providers, Avista currently offers net metering benefits for
why doesn't Avista buy it from customers? My systems under 100 kW. Customers may also be
solar array produces about 10,000 kwh/year eligible for state and/or federal incentives. For
excess power, which goes to Avista for free. If more information or if you have additional
Avista paid customers for their excess solar questions about your specific situation, contact
power, wouldn't that incentivize customers to solar(a)avistacorp.com .
install solar? It seems that utilities don't like
customer solar power, for obvious reasons.
Time of Use would be great, with adjustments for Thank you for your comment.
any disproportionate impacts on low-income folks
Many of California's wildfires are due to PG&E's Avista is committed to keeping people and
overweening focus on growing "green" energy and property safe. For more information on current
eliminating carbon based energy resources rather safeguards for preventing, mitigating and reducing
than adding and maintaining electricity distribution the impact of wildfires, see Avista's 10-year
infrastructure. What are your plans for increasing Wildfire Resiliency plan.
and maintaining electricity and natural gas
distribution infrastructure and not following
California's example?
Would Idaho [low-income] customers be able to The Community Solar program is for Washington
participate in the Community Solar program? Or customers only. The federal government is
would it just be available for Washington funding a similar program that could be available
customers? to Idaho in the next year or two.
Recommend Avista not purchase from the just Thank you for your comment.
permitted Horse Heaven wind project in Benton
County, WA. Local citizens are 90%+ opposed
and could be a nightmare for Avista
Will the levelized costs for P2G used in Avista's The levelized costs of all resource options,
modeling forecast be made publicly available? included power to gas, used in modeling are
available on our website.
What incentives will there be for customers to For more information regarding incentives, please
install solar panels and possibly batteries on their contact solar .avistacorp.com or
home? rebates m avista.com .
Avista Corp 2025 Electric IRP 3

Appendix M: Public Comments- Public Meeting
Is Avista still planning to meet a 100% Clean Avista is planning to meet its 100% Clean Energy
Energy goal by 2045?You note building out new target by 2045 as required by Washington State
Natural Gas facilities in the 2040's, so I'm trying to subject to the cost cap provisions in the law.
figure out how it makes financial sense to build a Avista provides electricity in Washington and
new gas facility in 2040 and then retire it a few Idaho and balances the policies of both states.
years later by 2045...? Retirement of a peaker plant in the 2040s, could
require another gas peaker to meet Idaho
capacity needs.
Hydro power needs to be a part of your poll Thank you for your comment.
question
The new generation of smaller, modular nuclear Thank you for your comment.
reactors may be an interesting option as the
technoloqV matures.
There has been much talk about breaching dams. Avita has no plans to breach any of its dams.
Will that affect Avista's ability to generate energy, Avista meets nearly 40% of it's energy need with
and if so, by how much? hydro resources. Hydro meets 55% of winter peak
and 61% of summer peak.
Are the solar additions in 2040-2045 standalone Avista's analysis shows it's likely to be solar plus
only, or inclusive of solar+stora e? an onsite storage facility.
In estimating cost for building nuclear power Avista's modeled the newer small modular
facilities, are you using cost of historical nuclear reactors as a resource option. Although using cost
power plant costs (large, completely custom per kilowatt metrics larger facilities may be lower
designed and built and hence very expensive)? Or cost per unit.
are you using the much lower costs associated
with the new, smaller, modular systems?
Possible Al data centers would be a huge drain. There's pros and cons. A large load (i.e.100-
What are the plans to deal with that possibility? 500MW)would create a larger base to spread
fixed costs which would lower costs for other
customers. The downside is that Avista would
have to build or acquire more generation to serve
a data center.
Just to be clear, do you consider Natural Gas to For Washington, natural gas is not considered a
be "clean"? "clean" resource for generating electricity.
What adjustments can Avista make to estimates Heat pumps are efficient in certain temperature as
of demand when the efficiency of heat pumps is low as 30 degrees. At temperatures below that,
considered? Heat pumps are very efficient and heat pumps struggle to provide enough heat and
imply a reconsideration of primary energy may require supplemental heat or oversizing. The
estimates in some cases. load forecast includes increasing adoption of heat
pumps and these characteristics.
Will 'Avista be implementing a Virtual Power Plant Avista PRS includes customer battery storage and
in the future? may be termed as a Virtual Power Plant.
What about winterized heat pumps of the kind Heat pumps are efficient in certain temperature as
used in Norway? low as 30 degrees. At temperatures below that,
heat pumps struggle to provide enough heat and
may require supplemental heat or oversizing.
Heat pump technology is being improved with the
intent of addressing these cold weather issues.
Where does nuclear power fit into your IRP? Avista modeled newer small modular reactors as
one of its resource options. It was selected as part
of Avista's preferred resource strategy in 2045.
Is natural gas availability effected by clean energy Technically no.
laws?
A new fee is being added on to the electric bill and Thank you for your comment.
the gas bill. So some people will get double
whammy when they have both. There are man
Avista Corp 2025 Electric IRP 4

Appendix M: Public Comments- Public Meeting
people, elderly and low income, that will really feel
the affect in their pocket books
What is the basis for the large EV forecast? Avista worked with a consultant Cadeo, their
study largely looked at consumer trends and
commercial demand (via survey)given the local
demographics and economy.
Earlier in the year there was a significant amount Avista sees hydro remaining a viable clean,
of press about hydro generation facilities in affordable resource. With current technology, the
Oregon and Washington having to meet rigorous amount of wind and solar resources necessary to
demands in order to remain active. How do you replace hydro capacity is not realistic for many
foresee the hydropower market remaining a viable reasons.
resource, or do you foresee the demand for it to
be replaced by wind/solar?
Was the one coal fired generation facility the only Colstrip is Avista's only coal-fired generation
one in the Avista portfolio that will be coming facility and Avista's 15% ownership of units 3 and
offline?What was that facilities generation per 4 will be transferred to Northwestern end of 2025.
ear? Avista's portion of Colstrip is 222 MW.
What about other dynamic rate plan options like Avista is not considering a subscription service at
energy use rate subscriptions? this time
Why am I not compensated for excess solar Net metering is available to Washington and
energy production in Idaho while I have friends in Idaho customers. For more information regarding
Washington that are? your circumstance, contact solar(c�avistacorp.com
How long does it take to import energy from It's instantaneous and seamless to customers.
Dakotas to Idaho/wa?
More efficient devices generate much higher man- Thank you for your comment. Community safety
made electromagnetic fields that may negatively and wellbeing is important to Avista.
effect the human body. Being highly sensitive to
these electromagnetic fields, this concerns me
greatly as man-made electromagnetic fields have
negatively effected my health. What options are
available more efficient devises that are healthy
for the human body?
Is wind low cost simply due to economic Cost of wind generation is mostly affected by its
incentives? Or for other reasons? production capability and cost to construct, for
Avista's IRP, it found wind would not be
purchased early without the tax incentives.
Don't forget that all fossil fuels are currently Thank you for your comment.
enjoying massive taxpayer support
Will Avista keep your transmission rights out of Avista plans to keep its transmission rights out of
Colstrip, once you stop ownership of units 3/4? Colstrip. This transmission can be used for the
transmission from N. Dakota mentioned earlier.
Also if there's ever available transmission, Avista
can "sell"those rights. Both of these options
would benefit customers.
Has Avista looked at Co-gen from waste heat at Avista does not have any compressor stations on
N.G. Compressor Stations? its system. Avista would be willing to purchase
power from owners of natural gas compressor
stations who develop co-gen.
Do you see a significant difference is energy Yes, Idaho's avoided cost is lower due to the
savings from efficiency programs between WA exclusion of clean energy premiums, the Power
and Idaho customers given that the WA efficiency Act preference and the avoidance of the social
rebates tend to be higher? cost of greenhouse gas as required by
Washington. These requirements lead to greater
Avista Corp 2025 Electric IRP 5

Appendix M: Public Comments- Public Meeting
incentives for customers, but come at a cost to
higher retail rates.
is it true they are trying to get away from gas? Washington legislation has not been favorable
makes it difficult for people that have homes and toward natural gas for end use, making the future
rentals with has furnaces as that has been the of natural gas more tenuous.
most affordable for people to run so they tend to
lean towards natural gas but people are worried
that if they put in gas furnaces that they will not
have gas available down the round from rumors
going around
Since the Federal Government is pushing There are funding sources to expedite nuclear
clean/green energy are grants and federal funding power including loan programs and production tax
available to expedite nuclear power generating credits.
facilities?
Why didn't all homes get a solar capable meter All AMI meters are solar capable. Only customers
upgrade? who have chosen to opt-out of receiving an AMI
meter would have meters that are not solar
capable. Because of that, those customers are not
able to install solar.
With Washington pushing toward everything The distribution grid is evaluated every two years
electric, how does Avista expect to increase for capacity constraints looking out ten years.
secondary electrical lines to meet the demand? Avista has recently started including electrification
forecasts into that evaluation. Avista will reinforce
the system as necessary to accommodate those
expected needs. The expectation is that a
percentage of service transformers, distribution
conductor and substation transformers will have
capacity constraints as the electrification transition
occurs. The annual impacts of the transition may
vary greatly as the rate of the transition varies with
changes in technology, social drivers, the
economy, State policy goals etc.
Who does the current TAC currently consist of? More information about TAC members and other
advisory groups can be found on our website
under"Avista Advisory Groups".
I didn't notice anything addressing electricity being Avista currently trades power with buyer/sellers in
transferred back and forth to the CAISO network. California and across the west.As the system
Do you foresee that need/ability increasing. depends more on storage and variable energy
resources trading energy will likely increase.
What is Avista position on the Lower Snake River Avista does not own or buy power directly from
Dams these facilities and has no position on the future of
these facilities.
Does Avista have any incentive to continue using Being a combined electric and natural gas utility
natural gas for electricity because you also have a does not create any benefit or impact on the
natural gas utility? decision to use natural gas for power generation.
Although offering both energy sources can create
economies of scale if our operations.
On the transmission expansion slide, are the The small red arrows between the BPA network
small red arrows in between the BPA network transmission lines indicate the approximate points
system transmission lines areas where Avista is where Avista's transmission system connects with
looking to expand? BPA and where Avista serves its retail load. The
figure on the transmission slides does not
represent the entirety of Avista's transmission
Avista Corp 2025 Electric IRP 6

Appendix M: Public Comments- Public Meeting
system but highlights the role of transmission from
North Dakota in serving our customers.
Not sure if Avista can look into hydro from Canada is expanding hydro and Avista would be
Canada. interested in purchasing more energy permitting
there's enough transmission available to get it to
us and pricing is comparable.
Public Email Comments &Questions
Reply comments are included where related to resource planning, comments/questions not related to
resource planning were directed to other departments within Avista. Customer names were edited to only
include first names. Responses below are also edit to pertain to IRP related content.
Email Comment
You should concentrate more on getting through the nert 2-3 years as cycles are suggesting that war,
both international and inteernal (civil) are likely. See Martin Armstrong
https://www.armstrongeconomics.com/..
If the grid goes down, WHAT IS YOUR ACTION PLAN? How long can the NG flow to households and
business w/o electricity? What is your plan to mitigte SABOTAGE?
Best,
Richard
Reply Response
Thank you for sharing your concerns. The resource plan is generally designed around how do meet
growing demand to ensure we do not have blackouts. Avista does have plans to deal with energy
security issues, but are not generally discussed publicly.
For your question regarding natural gas flow without power, Avista can continue to serve customers
natural gas when there are power outages, the twos stems are independent.
Email Comment
Reducing and/or outlawing natural gas is one of the stupidest things to come out of"big climate".
Please lobby against the ploys of"big climate", even those executives and activists employed by Avista
who believe in it. Your job should be to produce plentiful, affordable, reliable energy for your
customers. "Big climate"thinking they have some moral high ground, when anyone who looks will find
multitudes of professional scientists who disagree with the conclusions of the IPCC and "big climate", is
a false appeal to authority.
The most important things the world can do is get those societies who burn dung to instead burn wood,
get those who burn wood to burn coal, and get those who burn coal to burn natural gas. The obvious
next step is nuclear.
Dennis
Reply Response
Thank you for your comment and it will be noted in our filing so your opinion can be heard. Avista must
follow state law regarding climate policy and develop plans and offer services complying with the state
law. The best way to be heard or enact change is through our democratic process, so I encourage you
to vote your opinion in this election as many of the causes you are concerned with are on the ballot
through the initiative process.
Avista Corp 2025 Electric IRP 7

Appendix M: Public Comments- Public Meeting
Email Comment
I am now confident this email will not matter, but perhaps by letting you know my feelings it will help me
and my changing attitude about Avista as an Avista customer.
1)You have scheduled two (2)virtual meetings on the same single day.
As to my schedule, I have back-to-back Teams and Zoom meetings that day and therefore cannot
participate in providing feedback or learning more.
You should schedule more than just one (1) day of involvement meetings to facilitate greater feedback.
But that may not be your objective.
2) 1 went to the MyAvista IRP link and found that each individual content item and sub-items has a
separate link. There was no way to simply open a PDF file or similar single click option to either
download or print out the IRP document(s). After clicking a couple, I experienced great, frustration
because the information found in each link was not cohesive to understanding the full IRP plan.
Perhaps this is also intentional in order to reduce the number of people who can read and understand
the whole document. I believe that is what you are asking people to do in order to provide solid, rather
than emotional, feedback to your IRP.
3)A friend in Spokane has told me that your plan includes raising local electrical rates to a level that
matches what California is paying Avista for the electricity transferred to the California grid, he reported
as 25 cents per KH, or higher. Providing electricity to local markets is easer, less costly, and with less
transmission loss than transmitting electricity across multiple state lines and over great physical
distances. If this is true, it only represents your utilities desire for greater profits and investor ROI,
rather than keeping rates reasonably profitable for Avista and affordable for local service
users/customers.
4)With increased data and cloud storage centers being added to Avista's service area, increased
demand for electricity for in-home technology, all electric appliances, electric vehicles, and far greater
electricity demand from other new technology,Avista should be developing a plan to improve local and
service area electricity production to meet the growing demand rather than focusing on pre-establishing
a rate Avista wants for their investors and creating a plan that will do that without concern for regular
families/couples/individual customers in the service area.
A. Related to that, why do high quantity electricity users get greater discounts than home
consumers who are reminded regularly to reduce their electricity consumption?
B. Why is there no adjustment incentive for people to charge their electric vehicles or use of other
higher electricity use at night or during periods of less demand? I previously
read Avista is concerned about the growing demand for electricity during daylight hours but does
not offer incentives to shift that demand to a more favorable demand timeframe for
Avista. ISN'T THIS PART OF AVISTA'S RATTIONALIZATION FOR THE NEW"SMART"
METERS, so Avista can know when the electricity is used?
We only moved back to eastern Washington in December of 2016, and my wife was killed on WA395 in
2017, but sadly my experience of Avista over this time has generally not been good, and the
messaging put out by Avista is less than positive or people centered for the average home customer. I
miss Utah Power for their great community awareness, and great people centered customer care.
Thank you for reading this, if anyone actually does.
Lynn
Reply Response
Thank you for your email. I can try to help you with your questions. I can also jump on a call with you to
discuss if you'd like to learn more.
1)We've been testing the most successful ways to find when people are able to attend. We've been
mostly focused on the time of day rather than multiple days. I will take that idea to the team who sets
Avista Corp 2025 Electric IRP 8

Appendix M: Public Comments- Public Meeting
up these meetings.As for now, maybe your best bet to listen to the recording of the meeting, but there
will be more of these types of engagement opportunities.
2) 1 apologize for your frustration accessing the IRP content, the complete draft of the IRP is contained
in this link https://www.mVavista.com/-/media/mVavista/content-documents/about-us/our-companV/irp-
documents/2025/2025-draft-electric-irp-complete.pdf, all remaining information on the website is
additional information, such as appendices or information from our public process-we have people
who are only interested in certain items and the links are arranged in a way to make sure those can
find them. Due to the volume of information it is difficult to simplify the data into a few links.
3) On page 53 of the IRP (previous link), you do see the 25 cent rate in 2045.Avista's forecast in future
rates is a result of state policy in Washington.Also in the chart is Idaho's rate forecast of 18 cents. The
extra cost is due to the clean energy requirements from the state CETA law enacted in 2018, where as
in Idaho we do not have the same requirements and the rate forecast is lower.Avista is required to
follow state law and will unfortunately have to increase rates by acquiring more expensive generation
to comply with the state law. The location of our future resources will be determined by what is lowest
cost that meets state law, the only reason we would look for generation sources requiring transmission
is if the total cost is less then other options. Regarding how Avista shareholders profit,Avista only
makes profit on investments in assets, the location does not matter, nor the type of investment. I'm
happy to discuss that with you on a call is well.
4) 1 would like to know more about what you think we can do to better serve our local community, either
we not informing what we are currently doing or we are missing something, perhaps this is something
we can discuss as I'd like your input.
a) I think this could be a question of rate class, large industrial customer to pay less then
residential. The main reason for this is due to they do not use the local distribution system, so these
customers only pay for infrastructure they use, and in this case they do use less of the system.Also
large customer energy use is typically flatter, meaning they do not have high demand in extreme
weather events, in this case they do not cause the need for extra generation or delivery infrastructure
to serve them and if they have what we call "peaky" loads, they pay extra through a demand charge.
Regarding the comment regularly reducing energy consumption.Are you referring to our energy
efficiency programs? In this case we have programs for all customers, but there are many opportunities
to help customers find more effective ways to use less energy at a lower cost. I'm happy to discuss this
with you as well
b) Different rates for the time of day is what we refer to as time of use pricing. We are testing
this right now in a couple different programs- see links below, but yes, this is one of the advantages of
the new meters, in addition to customers having more information about what and when they are using
energy. This new pricing structure is first going to be tested with volunteers before we decide if any
decisions are made if the company should offer different rate alternatives.
https://www.myavista.com/energy-savings/green-options/peak-time-rebate
https://www.myavista.com/energy-savings/preen-options/time-of-use
I hope this answers some of your questions and again please take me up on a chance to chat. If so,
please reply and I can offer some times I can set up a teams meeting or call you directly,
Email Comment
Here's my response to our future energy needs.As homeowners we are asked to turn our thermostats
down, reduce our lighting or use LEDs, and insulate our houses. Those are all good things.
However, I think the same should apply to large businesses. For example, I see that the best western
in Moscow Idaho has an outdoor gas flame display that serves no purpose other than a decoration.
Also, I see other businesses leaving their lights on in the parking areas and inside the buildings at night
when nobody is there. I understand a few lights for security are important but it isn't necessary to light
up large areas. I also wonder if these large buildings turn the heat down to conserve energy at night
when they are empty.
Avista Corp 2025 Electric IRP 9

Appendix M: Public Comments- Public Meeting
Thank you
Jerry
Reply Response
We appreciate your time to respond to our invite and hope you can join one of meetings. Your
comments will be shared across Avista and with our regulatory commissions. But I would like to ensure
you we do work with our larger businesses to conserve energy and take advantage of our rebate
programs, they are just not as publicly broadcasted like residential programs because we use a
different marketing strategy with those customers.
Email Comment
Just because you call it clean energy does not make it CLEAN. WE NEED ALLL ENERGY SOURCES
TO BE ENERGY INDEPENDENT. CLIMATE CHANGE IS A CON OR A SHAM AND YOU WANT TO
DO SOLAR AND WIND BECAUSE IT IS CLEAN. CHINA IS NOT OUR FRIEND. THE WEF IS NOT
OUR FRIEND. JOHN KERRY AND AL GORE ARE NOT OUR FRIENDS. WE HAVE HYDRO POWER
WHICH IS CLEAN AND HAS AN AGRICULTURAL BENEFIT NUCLEAR ENERGY IS CLEAN AND
ABUNDANT. CITIES WITH AN ABUNDANT WATER SUPPLY COULD HAVE A SMALL LOCAL
NUCLEAR POWER PLANT WHCH WOULD CREATE LOCAL JOBS. WE NEED TO DEVELOP ALL
THESE OTHER FORMS OF ENERGY BEFORE WIND AND SOLAR. IN SPOKANE WE HAVE
SEASONS, SO ELECTRIC CARS AND BATTERIES DO POORLY IN THE COLD. ELECTRIC CARS
ARE HEAVIER AND THEREFORE IF ALL THE CARS ARE HEAVIER THEN ROADS AND PARKING
GARAGES WILL NEED TO BE ENGINEERED FOR THE INCREASED WEIGHT. I LIKE THE GAS
AND DIESEL ENGINS AND THE EFFICIENT AND AVAILABILITY OF THE FUELS. I WOULD
SUGGEST STOP SUPPORTING THE PROPAGANDA AND DEVELOP ALL ENERGY SOURCES.
SINCERELY SCOTT
Reply Response
Comment Noted
Email Comment
Quit subsidizing the Dams on the Snake River , with my rate dollars .
Everyone knows they are Loosing Money Big Time .
The energy they produce is NOT NEEDED , and is excess power .
And this at the Cost of All Our Precious Salmon .
You and Bonneville Power and The Army Corps of Engineering are responsible for this , and are what's
Wrong with my State of Washington .
Also , You have Lied , Cheated and Broked Your Word and Agreements with the Indigioness Peoples
and Nations , of America .
Yet You Continue , have You NO SHAME ???
Reply Response
Thank you sharing your concerns with me regarding the Snake River Dams. Avista does not own or
directly buy power from these projects. I'm happy to include your concerns in our resource planning
process.
Email Comment
To whom it may concern:
Hello,
Unfortunately, I am unable to attend your upcoming virtual meeting but would like to make a
suggestion. I live in the Avondale neighborhood in Hayden and we have had several outages over the
ears. Your meeting is focusing on the next 20 years of Avista and their future goals.
Avista Corp 2025 Electric IRP 10

Appendix M: Public Comments- Public Meeting
We currently have "overhead" electrical lines in this neighborhood and I would like to recommend
Avista bury those overhead lines to underground lines if at all possible. I believe it would help prevent
the several outages which are usually caused by HIGH winds. I feel this improvement would prevent
outages and the neighborhood would look so much nicer!!!
Thank you for your time.
Sincerely,
Carrie
Reply Response
Thank you for sharing your concerns, this is definitely a common issue across the country. The general
purpose of today's meeting is to share and get feedback on how we will provide (or generate)the
power to meet growing demand. While your issue is equally important because we need to be able to
deliver the power we generate, undergrounding lines is definitely a way to improve our reliability, but it
also expensive especially if the system already exists above ground and could create rate pressure. I
will definitely share your concerns with others here at Avista. One thing we are thinking about is how
we can improve reliability regardless of the line to deliver power, I am referring to home generation or
storage, but also improving homes to without retain temperatures longer without heat/AC in the event
of an outage. While there is no simple cheap answer to any of these options, trying to develop more
resilient system is on our minds, but the greatest challenge will be understanding the trade off between
affordability and increased reliability.
Email Comment
I wrote into the Spokane paper a year ago. Wish I had an option to change my Utility company . It's an
embarrassment how little to know effort Avista makes in regard to electric charge stations, or credit for
home chargers. The charge station at your facility on 15th street , shows what kind of an industry
leader you are. Reminded now to post again in the local paper .
Thanks,
Dave
Reply Response
Hi Dave, I forwarded your concern to our electric vehicle team. If you don't get an reply feel free to
contact me.
Email Comment
You asked for comments. We just wanted to say that we believe that there is nothing intrinsically wrong
with "fossil fuels"for electric generation. America is the best there is in the world at managing
emissions and minimizing risk to citizens. Solar panels and wind generators require huge quantities of
mined elements and create a lot of toxic waste that has to be disposed of. Situations like the huge solar
farm in Texas that was destroyed by hail and created a toxic mess are one more reason to not go that
route. The gargantuan blades from the wind generators that have to replaced more often that it
seemed like initially, and also create a waste problem. Trucking them to somewhere back East to grind
them up, or burying them in middle America is not in the least bit energy efficient. Then there's the
hundreds of tons of concrete that is involved in their bases. All mined. Not"green."
We will trust that reason and common sense will prevail as we move forward with electric energy plans
in America. Reliable is#1, affordable is#2 for us (and not affordable to the consumer because it's
government subsidized to make it so). Hopefully, new nuclear technology will help fill the gap.
Sincerely,
Danny and Gretchen
Reply Response
Hi Danny and Gretchen,
Thank you for your comments, I appreciate hearing your preference on reliability and affordability. As
we are required to change our energy mix to comply with Washington law, we'll continue to do your
Avista Corp 2025 Electric IRP 11

Appendix M: Public Comments- Public Meeting
best to meet reliability and affordability objectives. We also collect all comments and do include them
when we meet with our regulators so customer's voices are heard.
Email Comment
is it true they are trying to get away from gas? makes it difficult for people that have homes and rentals
with gas furnaces as that has been the most affordable for people to run so they tend to lean towards n
atural gas but people are worried that if they put in gas furnaces that they will not have gas available do
wn the rd from rumors going around. Mainly referring to ID &WA as I am a local realtor/broker here an
d it is a constant concern
Reply Response
Sorry we did not get to your question during the meeting today. There is no current law prohibiting use
of natural gas in homes in WA or ID. The current WA building code does make it more expensive to
install natural appliances for new residential construction and basically prohibits it in new commercial
buildings. Although with the passage of initiative 2066, the building may have to be modified to remove
these requirements. I think some of the concerns with prohibiting natural gas is in two factors 1) its
possible the state could prevent replacing existing gas appliances upon failure. This has not happened
but has been a concern. The second concern is pricing. The Climate Commitment Act requires utilities
to buy"allowances"to offset the greenhouse gas emissions from customers use of natural gas, these
allowances are purchased from the state and the cost transferred to customers. Basically this a
mechanism to increase the cost to use natural gas to either encourage customers to switch to another
source or for utilities to find a way to provide gas without greenhouse emissions (which is significantly
more expensive at this time). Lastly, I don't expect Idaho to require any restrictions to natural gas
unless it is done at the federal level.
Email Comment
Thanks for asking for my input. I won't be able to attend the meetings but my feedback is that Avista
should plan on using nuclear power. In my opinion, solar panel technology will become obsolete
before it pays for the cost of installing it not to mention the land required and the birds that will be
killed. Solar panel waste when disposal is required will be a huge problem. Windmills also kill too
many birds. Additional hydro power should bu a used if available
Best regards
Reply Response
Thanks for the input. I hope you have time later to listen to our meeting, we do expect nuclear power in
the future as well as retaining our hydroelectric facilities. Regarding wind and solar, we do expect both
to be in our energy mix, but understand your concerns. We'll definitely be working with impacted
parties to ensure we minimize unintended consequences when it comes time to build these resources.
Email Comment
If WA State eliminates all Nat'l Gas for power generation, how will that impact those home owners with
nat'I gas heating and cooking stoves?
Thanks!
Tom
Reply Response
Current Washington state law does not prohibit natural gas for home use. With the passage of initiative
2066, there is additional protection for its continued use for existing and future customers.
Email Comment
I read the voluminous sitrep and long term planning document. Lots of complexity and a lot of
unknowns. My sense of it all is you folks have done a thorough job. And my conclusion, having done
some of this kind of planning work for Seattle City Light in the 70's, is pretty simple: go for the various
kinds of what is known as clean energy, especially including wind and solar in the forms that have been
Avista Corp 2025 Electric IRP 12

Appendix M: Public Comments- Public Meeting
evolving. WPPS was a disaster back in my day; the new small nuke plants may be an improvement
over those huge money pits, but I'm still convinced that energy efficiency and decentralized on-site
power production is the low cost and best long term solution. That would include solar panels required
on all new homes and commercial buildings for domestic hot water, industrial cogeneration where
possible, retro-fitted and new smart sensors in all commercial structures for lighting and HVAC, solar-
generating shingles, day/night solar/wind hydro pumping options, most-efficient heat pumps, improved
transmission lines, and others I'm not very familiar with. All of those can be proposed, encouraged,
and often subsidized by Avista in keeping with financial evaluation against other more traditional
options.
Which leads to my other major point. Hopefully the utility planning and operations mind-set includes
focusing on all of the above as a first option, depending on cost-benefit analysis of course. My
experience at Seattle City Light was that the engineering staff had relative blinders on; they were not
open to consideration of much of the newer technologies that could not be immediately switched on
and off at a central office. But, through public pressure (it's a public utility where the mayor and city
council select utility management), we did make strides in home/commercial energy conservation that
was absolutely cost-effective.
Lastly, I hope Avista does all it can to avoid encouraging and supplying power to crypto mining
facilities. Bad deal all around.
Bob
Reply Response
Hi Bob,
Thanks for the comments. From a resource planning effort, energy efficiency definitely gets priority, the
state is ensuring in many cases it passes the cost benefit test by including non-energy benefits and
preference adders-this will of course increase cost, but is the direction of our regulator. I will of course
include your comments in our plan. Lastly, we don't have any direct large crypto mining facilities yet!
Email Comment
Hi, thank you for your email! I would like to mention a concern I have with regards to phasing out
natural gas heating in favor of heat pumps.
I am concerned about the efficacy and longevity of heat pumps in our climate, since we did hit-10' last
winter, with a-300 windchill. What I am not sure may be being considered is that my HE condensing
furnace is probably way more efficient and practical for the climate of Eastern Washington. Has the
governor ever had -30' blast him in the face when he opened his front door?
Heat pumps require running 24/7 in such temperatures, don't they?And just HOW much power does
that use, how much would/does it cost compared to my furnace that fires for about ten minutes per
hour???And how much pollution does my ten minutes per hour in -30' actually create?
Another factor is that in times of long power outages, people can still take showers if their hot water
tank is gas-an advantage so awesome that people flock to those who have them so they can shower
after four days without power. I experienced that growing up, when we lost power for over a week in a
deep freeze. A friend loaned us a propain heater for the bathroom so we could shower. We were also
able to do laundry, and heated and cooked via wood stove. Some things to consider when we have a
high population of vulnerable seniors currently.
It will be neat to hear from others. Thank you for inviting us all into these discussions, Avista!
Reply Response
Thank you for your comments and support for natural gas. We'll ensure to include your comments in
resource planning efforts to ensure policy makers are educated on the benefits of natural gas.
James Gall
Manager of Resource Analysis, Avista
Email Comment
Priest River, ID and Newport, WA would be enhanced by natural gas piping.
Reply Response
Hi Jon
Avista Corp 2025 Electric IRP 13

Appendix M: Public Comments- Public Meeting
You've identified a place we've been looking at for a long time. Unfortunately we need more demand
for gas in the area to make it work. The closest pipe is in Sandpoint. I'm not saying we'll never get gas
in your area, but it will take a collective effort to make it happen of interested customers in order to
make it cost effective for us to do the line extension.
Email Comment
Hello,
Avista requested comments from customers on long-term planning.
The most important thing to me is that Avista focuses on increasing solar and wind energy generation.
We need to phase out natural gas and all other unsustainable, polluting resources.
Thank you,
Cariann
Reply Response
Thank you for your comment we'll include it in our resource planning process. With Washington's
Clean Energy Transformation Act, we'll continue investing in renewable resources and energy storage
until we can reliably and affordable serve customers without using natural gas for power generation.
Email Comment
I got this at 9:06 this morning so I missed the zoom meeting. My thoughts of how we need to move
forward as a community is to model ourselves after the German town that had all customers install
solar. They paid their normal bill and money earned, set up someone else's solar. Several years later
no one paid any electric bills and the overages were sold to surrounding communities and the
county. They use all of the proceeds for funding community centers, schools etc. They support the
whole community!!!!
Betsy Czin er
Reply Response
Comment Noted
Email Comment
Hi Barbara,
The state government has a war on carbon. Avista sells carbon in the form of methane, sometimes
called natural gas.
What is Avista's position on hydrocarbons? We use hydrocarbons to power our cars and
homes. Avista appears silent on the decarbonization movement. Our family enjoys the comfort and
warmth provided by burning methane and propane.
Has Avista taken a stand? Or is Avista attempting being politically correct?
Thank you,
Ken
Reply Response
First I would say thank you for your comment-and we appreciate the support of natural gas. Avista is
committed to providing natural gas well into the future. The state of Washington has definitely created
challenges as you have mentioned. As you know we are subject to the requirements the state
legislature and the appointed regulatory commission directs us to. We have seen the Washington
citizens pass the initiative 2066 and that does send a message customers would like to retain natural
gas as an option. Although, the carbon cap and trade initiative failed. With this a cost of carbon will be
factored into how we continue supplying natural gas, there are options to provide carbon neutral or free
gas and in some cases electrification may be better from customers in limited circumstances.
Regarding our position question, we strive to educate policymakers so they understand the benefits,
costs, risks, and consequences as they make decisions regarding energy policy.
Avista Corp 2025 Electric IRP 14

Appendix M: Public Comments- Public Meeting
Email Comment
I briefly looked through some of the documentation looking for"net zero" or"climate'.
My brief search found no reference to either term and that makes me happy.
The federal government has lost sight of the intent of utility regulation by demanding particular
emphasis on replaceable, aka renewable energy sources of solar and wind, no matter what that energy
might cost since climate is their only concern. All while rate payers want reduced energy cost, not the
higher cost of solar and wind hidden by environmentally misguided individuals and foreign
governments.
Utilities are paid based upon their costs in an administrative environment. That allows utilities to pass
along increases in production no matter whether they are ridiculous in cost or not. Recent wind
contracts on east coast off shore wind production produces electricity at$150/mw. That is ridiculous
when natural gas can cost as little as $20/mw. There is no social cost nor is there an environmental
cost to using our natural gas.
To depend upon wind and solar as energy sources leads to needing more than 2000 years of grid
upgrades at current construction rates to enable ability to rely on those intermittent non-dispatchable
methods.
Neither wind nor solar should be planned for use. Both technologies are expensive compared to
natural gas and both technologies are more environmentally destructive than using our natural
gas. Using large amounts of land, requiring exemption for killing birds and mammals, plus
dependence on the CCP for providing needed metals is not a reasonable, secure, or economic way to
increase power delivery to consumers like me..
Now nuclear is again getting some attention by large power users. Data centers cannot rely on solar or
wind, they do need uninterrupted, dispatchable power. So, some large data companies, notably
Microsoft has purchased into nuclear reviving Three Mile Island. Avista should pursue nuclear since
next to hydro, it provides the cheapest energy to consumers like me.
CO2 is not a pollutant. CO2 is plant food and necessary for human habitation of this planet. Believing
in the current Washington DC government that there is harm from using coal, natural gas and oil is
fake science promoted by the CCP, Chinese communist party. They want to sell the US solar and
wind parts. They have no interest in CO2 except to leverage the stupidity of Joe Biden's, declared by
executive order, "climate-crisis". Political parties preferring particular power generation must make
economic sense for consumers. Solar and wind do not address anything economically nor do they
provide any benefit to the climate. There is no reason to mitigate co2 production.
Our recent election demonstrates that most of us, actual voters in the US, reject Joe Biden and his
"climate-crisis". Knowing that Joe Bidden's wasteful policies will be removed in favor of using our
natural resources makes sense. But that does demonstrate a core administrative dilemma for
Avista. Does Avista pursue economically, environmentally sane natural gas or get on the Yo-yo of
Washington DC. For the first time in US history communists in China are planning for our natural
resource use and that is being stopped by our next President, President Trump. Please place a hold
on developing any power source by Washington DC climate dictate. Washington DC under Joe Biden
is polluted with climate nonsense.
All warming since the year 2000 is attributable to the Earth's albedo, reflectivity. Recent work by
Nikolov and Zeller demonstrates that the actual measured warming, by NASA under Dr Roy Spencer,
is totally accounted for by Earth's decreasing albedo. No other cause attributed to actually measured
temperature records! Please review"Roles of Earth's Albedo Variations and Top-of-the-Atmosphere
Energy Imbalance in Recent Warming: New Insights from Satellite and Surface Observations"
Thank you for consideration,
Don
Reply Response
Comment Noted
Email Comment
IRP,
Just wanted to add some comments as I was unable to attend the Zoom. I'm a fan of wind and solar
for very small scale use ONLY. Those two sources don't have enough usefulness for large scale
projects and should be avoided for an exponentially better option, which is nuclear energy. The latest
generation of nuclear reactors are clean, consume their own waste which eliminates most of the
Avista Corp 2025 Electric IRP 15

Appendix M: Public Comments- Public Meeting
concern), and provide extremely robust and consistent power- exactly what we need. In fact, no plan
is complete without nuclear. The Biden administration in its final days has implemented a plan to move
forward with nuclear energy on a national level. The Trump administration should be just as friendly
with regards to nuclear and we cannot move forward with nuclear implementation fast enough. Things
move too slowly for most citizens.
Also, we cannot foolishly"turn off' hydroelectric power until nuclear comes on line. Anyone suggesting
the immediate shut down of hydro sources should be muted -there's no reason to be nice about it. It's
not reasonable and the extremist groups (yes, they are extremists) pushing for immediate shut down of
hydroelectric dams need to be told their requests will not be fulfilled anytime soon.
We also must use natural gas resources as often as we can. Even coal -we do not want to turn away
from cheap plentiful sources until we have nuclear power online and in full force. People want reliable
cheap power-that must be delivered!
Thank you,
Chad
Reply Response
Thank you for the comments. We'll ensure your comments are heard.
Email Comment
As a customer and consumer of Avista power, I am concerned that you are talking the talk on climate
action (in the form of Green energy projects), but that you do not plan on walking the walk and doing
what's necessary to move away from dirty energy.
I am urging you to do all you have promised and more to bring healthier and more sustainable energy
solutions to the inland northwest.
Thank you for your time.
Sincerely,
Natasha
Reply Response
Comment Noted
Avista Corp 2025 Electric IRP 16

Appendix M: Public Comments- Public Meeting
Email Comment
Hi Mr. Lyons:
As a long-time Avista customer, I know you have alternative means for energy production in addition to
traditional fossil fuel usage. I'm writing to urge Avista to become even MORE innovative and to make a
concerted commitment to green energy in this coming year. Please "lead the walk" into a greener,
more sustainable future for our world. We can't afford to talk about this any more. NOW is the time for
REAL ACTION as we cut ties to carbon and methane-producing ways. Wind, water, and solar power
MUST be developed quickly if we are to save our planet, and ourselves.
Thank you for your time.
Sincerely,
Helen
Reply Response
Comment Noted
Email Comment
Two areas I would like to see AVISTA pursue in the future: 1. power through forest health residue, and
2. power through recycle waste.
I have seen "power through forest health" used successfully by Chelan County Power in central
Washington State. Basically it consisted of portable generators taken to the site where forest managers
were thinning and removing tree material to make a more wildfire safe environment. Material was
chipped on site and used as fuel for the generator. Power generated was routed directly at a local sub-
station. This accomplishes two objectives: produces rural power, and created a more healthy forest
environment.
Years ago I was involved in a similar discussion in southeast Idaho where the power company wanted
to harvest 50 MBF of aspen residue each year for fueling power generation. That proposal involved
chipping on-site and trucking to a generator. Again the same two benefits of power and healthy forests.
I believe our local recycling programs could be vastly improved and used for power production. If it is
true that most of our current recycle material is barged to China, we are wasting a huge resource. I
have experienced a much more robust recycle program where residents sorted into three containers:
glass, metal and paper. There is tremendous potential for use of at least the paper/cardboard material
for power production.
Let's do it!
Reply Response
Thank you for your comments. Avista currently does exactly what you are recommending, not saying
we couldn't do more, but we currently burn wood waste from across the region in our Kettle Falls
Biomass Plant. Also we are buying power from Spokane's waste to energy facility. We think there is
potential in expanding production using wood in our area but the cost is typically more then other
resources, but does provide the benefits you are describing.
Avista Corp 2025 Electric IRP 17

Appendix M —Public Comments
Responses to WUTC 2025 IRP Comments
Washington Utilities and Transportation Commission Comments
The following recommendations and comments on the draft IRP were provided to Avista Utilities on
November 15, 2024 as part of Docket UE-230793.
WUTC Staff Recommend the following changes, each with corresponding timelines:
Topic No. Recommendation
Preferred 1 Within 120 days of filing the Final 2025 IRP, issue the required all-source request
Resource for proposals to evaluate the cost-effectiveness of all resources to cover the
Strategy capacity shortfall within the next four years.
Avista Response:
It is Avista's intent to provide a draft RFP to staff for comment within 120 days of filing
the Final 2025 IRP.
Load Forecast 2 For the 2027 IRP Update, continue to use end-use modeling techniques and test
its accuracy for use in the long-term load forecast. Check the assumptions built
into the end-use model with real-world trends as they manifest and discuss in a
future TAC meeting.
Avista Response:
Avista intends to perform a plus/delta review of the end use load forecast methodology
to improve and build upon the next forecast subject to staff availability and funding.
Avista will include this subject in future TAC meetings
3 Ahead of the 2027 IRP Update, propose to the TAC a workplan for how Avista
will incorporate sub hourly modeling for DERs, particularly demand response.
Avista Response:
Avista plans to discuss sub-hourly operations with the TAC during the 2027 IRP TAC
process. During this future topic discussion Avista will present the options to consider
sub-hourly benefits and decide a course of action subject to feedback of the TAC.
For the 2027 IRP Update, show detailed analysis that the representative
concentration pathway Avista uses is its best estimation of the most accurate
global prediction, while mitigating both resource adequacy risks and the risk of
inflated costs due to overbuilding. Analysis should incorporate a range of
modeling approaches, including but not limited to predictions from the Northwest
Power and Conservation Council, and the International Panel on Climate
Change, as well as Avista's independent climate research.
Avista Response:
Avista will continue to monitor the RCP studies against actual weather records, but
ultimately will not know what forecast is the most accurate forecast regardless of the
assumed global greenhouse gas emission levels. However Avista's 2025 IRP's
objective was to use current temperature trends taking into account risks of system
reliability if the temperature forecast is incorrect. Avista has chosen it's approach to
plan a system that is resilient to the impacts of climate change, both in summer and
winter months, and will consider the opinions of TAC members, NPCC, and the IPP so
long as the future temperature forecast does place risk to our customer's reliability.
Avista is committed to further discussion on this topic in the 2027 IRP process.
Background: The 2023 and 2025 IRP uses the same dataset as the Northwest Power
and Conservation Council. The base dataset that Avista utilized for assessing the
impact of climate change on both hydrogeneration and load was the study conducted
by the University of Washington and Oregon State University for the River Management
Joint Operating Committee (RMJOC) a committee comprised of the Bureau of
Reclamation, Bonneville Power Administration (BPA), and Army Corp of Engineers.
The RMJOC used an ensemble approach to modeling which resulted in 80 different
scenarios. Each entity using the study is using some method to choose a subset of the
Avista Corp 2025 Electric IRP 1

Appendix M —Public Comments
80 different scenarios. The Northwest Power and Conservation Council chose 3
different scenarios, while the BPA selected 19 of the 80 scenarios as representative of
entire dataset. Avista chose to utilize the same scenarios as BPA and will continue to
use those scenarios.
Resource 5 Continue to participate with Western Resource Adequacy Program to aid in
Adequacy Avista and the region's resource adequacy, while presumably lessening the
burden on any one utility.
Avista Response:
Avista intends to continue to participate in the WRAP so long as a sufficient number of
utilities within the WECC continue to participate to maintain regional reliability.
Distributed 6 For the 2027 IRP Update, hold a DER-targeted TAC Meeting. Pursue the
Energy recommendations that came from the DER Potential Study. Demonstrate through
Resources TAC meetings and include in the 2027 IRP Update, how recommendations were
included, and if any are not, discuss why.
Avista Response:
Pursuing the key recommendation of the DER study require dedicated staff and non-
budgeted expense. To the extent possible, Avista will begin to address key
recommendations of the DER study as staffing and budget allow. Progress on these
recommendations and incorporation into the 2027 IRP Update will be provided in
various TAC meetings as appropriate.
ar the 2027 IRP Update, provide clear analysis for Avista's methodology for
ducing Qualifying Capacity Credit values for demand response over time, as
mand response penetration increases.
Avista Response:
Avista will be participating in a regional study performed by E3 regarding the 2045
clean energy goals in Washington state. The study will include forecasting of QCCs.
Results will be incorporated into the 2027 IRP Update. Avista will also include any
updated information provided by the WRAP to determine future QCC values.
8 For the 2027 IRP Update, incorporate time-of-use opt-out assessments in the
Demand Response Potential Assessment.
Avista Response:
The 2025 IRP did include a study on TOU Opt-out, Avista chose not to include this
program option as a resource due to peak savings not being materially different than
the Opt-in option. However, Avista agrees to include this option as a resource option in
the 2027 IRP, but has reservations implementing opt out programs due to customer
preference for choice. Further the decision to pursue opt-in or opt-out may be more
appropriate for the CEIP process as it may offer a better venue for customer impacts
rior to making a decision.
Supply-side 9 For the 2027 IRP Update, model that the costs of power-to-gas include
Resources conversion costs necessary to repurpose existing plants. Additionally, Avista
should monitor regional hydrogen storage options.
Avista Response:
The 2025 IRP included the appropriate costs in its P2G scenarios. Avista will continue
to research conversion costs to repurpose existing plants should any scenario warrant
repurposing. Further, Avista included the capital costs of hydrogen and fuel as part of
the fuel cost. While there is potential Avista may directly bare these costs, Avista used
the fuel cost approach as these fuels could be used in other industries and therefore a
market may develop.
10 Ongoing: Use the NARUC Advanced Nuclear Tracker to follow regional nuclear
projects around the country, as well as work in conjunction with the Pacific
Northwest National Laboratory for more technical questions about the
technology. Clearly document and demonstrate that Avista is incorporating the
tenants of energy justice particularly as it relates to the impacts of nuclear energy
technology on affected tribes.
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Appendix M —Public Comments
Avista Response:
Avista appreciates the suggestion to use the NARUC tracker, while Avista continues to
research regional nuclear projects. Avista will address tenants of energy justice relative
to nuclear energy as appropriate depending on resource selection.
11 Conduct the planned study on distribution-scale energy storage and incorporate
results into the 2027 IRP update.
Avista Response:
The DER potential study was conducted for the 2025 IRP. Avista will continue to make
improvements which includes consideration of the study recommendations and include
an u date in the 2027 IRP.
Inflation 12 For the 2027 IRP Update, remain up to date on available IRA incentives and
Reduction Act incorporate them into the planning and modeling process.
Avista Response:
Avista will continue to follow available IRA incentives and incorporate within the
an ing and modeling process.
Clean Energy 13 For the 2027 IRP Update, continue to model the PRS to pursue the interim
Transformation targets, and the 2030 and 2045 CETA targets at the lowest reasonable cost,
Act while considering the impact of rate shock in a short period.
Avista Response:
Avista will continue to pursue the interim targets and the 2030 and 2045 CETA targets
at the lowest reasonable cost while considering rate impact.
14 For the 2027 IRP Update, demonstrate the specific actions Avista plans to take to
mitigate energy burden in Named Communities.
Avista Response:
Avista added additional language regarding energy assistance and its impact on energy
burden in the IRP/CEAP
15 For the Final CEAP filed within the 2025 Final IRP, define specific actions for how
Avista will address identified challenges to implementing energy equity rinci les.
Avista Response:
Additional information on overcoming challenges is included in the final draft of the
CEAP as compared to the draft.
State 16 Bring stakeholders together for an in-depth discussion and analysis of the issue
Allocation of diverging state resource needs prior to Avista formally filing anything to the
Commission.
Avista Response:
Avista intends to meet with stakeholders to discuss resource allocation issues in 2025.
Avista Corp 2025 Electric IRP 3

Appendix M: TAC Member Comments Outside of TAC Meetings
TAC Member Comments
This Appendix covers TAC member emails of comments made during the 2025 IRP or filed with
the WUTC. TAC members generally comment during TAC meetings, those comments and
questions are covered in the TAC meeting notes in Appendix A. This document covers
comments and questions provided to Avista outside of the TAC meetings.
Avista Corp 2025 Electric IRP 1

Appendix M: TAC Member Comments Outside of TAC Meetings
William Gary, Subject: Avista IRP TAC Equity Meeting Today, 1/30/2024
Hi James,
really appreciated your meeting today, though I have not heard this detail before on this kind
of subject related to Avista. I was taken by surprise when I saw the last slide about what
options were purposely not included last year in the Integrated Resource Plan. You asked
the audience about what changes might be considered, and I needed some time to think.
At least three of the four items need consideration.
For instance, not including renewables outside of Washington seems illogical. The
transmission system is allowing exchange of electric generation from Washington hydro
across huge distances by way of the HVDC line from Celilo to LA. Californians pay about 32
cents per KWH (according to Bing search), and we pay about 9 cents, causing an imbalance
that will not continue. California may presently have no generation we need or want to pay
for, but it does exist. And they certainly want our power, which will affect long-term planning.
Not considering nuclear power is not environmentally sound or consistent with CETA. While
it may not seem good for the price and other social and physical considerations, it certainly is
appropriate with the water and land resources we have at Hanford Reach. Nuclear is a clear
choice for reducing GHG emissions. It will provoke controversy,just like all proposals.
I understand the aversion to community solar, but I don't agree with it. Community solar has
more benefit because it demonstrates how people can work together to reduce their carbon
footprint. As an educational tool it helps young people and students see one viable way to
reduce climate change. Without that hope our future citizens feel less secure with negative
attitudes in today's world. This works especially well when panels are installed in view on
schools, community centers, and other public buildings. Beyond the Equity metric is this
sense of community and future opportunity. I know you don't want another responsibility
required by the Office of Future Wellness. Please reconsider participating as a partner, not
just a connector, in Community Solar. Clallum Public Utility District is applying directly for
low-income community solar grants from WSU's Energy Program that pay for 100% of the
installation. These are tax credits, to be sure, and they may not fit with Avista's financial
situation.
Thanks again for the opportunity to comment.
Bill Garry
think I was not clear the last slide was a scenario with the purpose was. The goal is to
quantify (cost and resource selection) for a future scenario that only focuses on certain
criteria (meaning only focusing on the customer benefit indicators). Since there is no
requirements for the scenario, we are fishing for what assumptions we should include or not-
so thank you for your feedback. You are the second person to mention to me we should add
nuclear back, so that is helpful feedback. Lastly, we don't see this scenario as a viable plan,
but rather a bookend to understand the cost impacts of only focusing on customer benefit
indicators and not least cost planning- but is a requirement for us to analyze.
Also we did include community solar in our last IRP's preferred resource strategy, but we
have yet to implement any programs. I'm not sure when we will implement a program, but I
have the feeling we'll be asked to create one in the next few years.
Update:
Both nuclear and community solar were selected in the 2025 IRP PRS.
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Appendix M: TAC Member Comments Outside of TAC Meetings
Molly Morgan, WUTC Staff, 4/17/2024
Avista folks,
Staff has some feedback regarding the scenarios, and climate sensitivity analysis of the last
two electric TAC meetings. Looking forward to discussing on Thursday!
1) Staff strongly recommends that Avista rely on the RCP 8.5 scenario year-round,
instead of Avista's proposal to use RCP 4.5 in the winter months and RCP 8.5 in the
summer months. Having taken into account Avista's reasoning that it is concerned
about the 8.5 scenario potentially not accounting for extreme winter cold snaps, Staff
believes there can be other ways to work with this concern such as finding an RCP 8.5
model that includes some degree more of that volatility. Staff highlights that the NW
Power and Conservation Council relies on RCP 8.5 for its climate modeling. For the
purpose of consistency, Staff urged all utilities during the 2022/2023 IRP cycle to
adopt RCP 8.5 as their climate modeling standard. Barring empirical evidence
indicating the future will deviate from RCP 8.5, Staff strongly urges adoption of RCP
8.5 to promote regional consistency in analysis.
a. WAC 480-90-238 (2) (b) "Lowest reasonable cost" means the lowest cost mix
of resources determined through a detailed and consistent analysis of a wide
range of commercially available sources.
i. Staff believes that using two different climate futures within the same
year for planning purposes would not be a consistent analysis. Staff is
open to discussing other ways we can agree on to address Avista's
concerns with winter cold snaps, but using two different climate futures
in each year isn't a reasonable approach from our perspective.
2) Staff would like to briefly provide some follow-up to our discussion on Thursday, the
28t" Staff requested that Avista consider a "plausible worst case scenario" that would
drive customer flight and, among various variables to consider, listed RCP 4.5 among
the variables that might accelerate the possible positive feedback loop noted by Staff.
In response, Avsita staff noted that Avista was considering a similar scenario and
listed RCP 8.5 as the climate change pathway associated with this scenario.
a. Staff recommends that Avista includes RCP 4.5 in a "plausible worst case
scenario". Please consider the following table contrasting RCP 4.5 and 8.5 and
impacts Staff anticipates:
RCP 4.5 RCP 8.5
Colder Warmer
More Heating Degree Days Fewer Heating Degree Days
More Demand from Customers Less Demand from Customers
More CCA compliance instruments Fewer CCA compliance instruments
acquired acquired
More bill impacts on Customers Fewer bill impacts on customers
Greater fiscal pressure for customers Less fiscal pressure for customers to
to leave gas service leave gas service
Less stable customer counts for gas More stable customer counts for gas
service service
b. If Avista has other justifications for why RCP 8.5 presents a less stable future
Staff would be happy to discuss those concerns at a future TAC or inter-staff
meeting.
Molly Morgan she/her
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Appendix M: TAC Member Comments Outside of TAC Meetings
Avista Response
As you describe, Avista utilized RCP 4.5 for non-summer months so we could test cold
events and identify any reliability issues associated with those events. We used RCP 8.5 for
summer events so we could test summer heat and identify any associated reliability issues.
To address concerns that using RCP 4.5 for non-summer months may overestimate load
impacts from climate change we conducted a scenario with RCP 8.5 for the entire year.
Paul Spooner, Subject: Draft Presentations for Avista's 2025 Electric IRP TAC 2
Meeting 1/29/24
Avista IRP team,
I am an Avista Electric customer in Post Falls ID.
As Avista has requested public comment, I read through the DRAFT TAC2 presentation. In
brief, I think you should abandon pursuit of"green" and "equitable" activism and focus on
minimizing cost to the end user. I am appalled by the focus on "Renewable Energy" "Clean
Energy" and reducing "Greenhouse Gas Emissions". CO2 emissions have improved the
climate for both humanity and the ecology. If anything we should be increasing greenhouse
gass emissions, not reducing them. I realize much of this is required by regulatory bodies, but
you should be loudly pushing back against this foolishness, not acquiescing quietly. I am also
deeply offended and alarmed by the insistence on "equity" which amounts to illegal
discrimination. Annette Brandon's "Overview of Equity" attempts to equivocate on this topic by
equating "Equality" with "Equity" but even this fails on slide 4 where Equity is defined as
"Equality in outcomes" in the Venn diagram. This is the kind of resentful excellence-hating
thought that killed over 100,000,000 people in the past 70 years in the failed and failing
communist states. Since these champions of equity are such foes of competence, it comes as
no surprise that Annette has mistyped "Transition fo Clean Energy", has chosen the word
"exasperate" when she clearly meant "exacerbate", and has used the misspelling
"PARTICPATION" not once or twice, but fully four times. If equality of outcomes is important
to Avista, I would expect similar grammatical gaffes elsewhere, but I digress. You are playing
with fire here. It would behoove you to quietly cut all ties with the "Equity Advisory Group" and
all such ideologically motivated organizations and to comply as recalcitrantly as legally
possible with top-down regulatory requirements.
The public utilities should be focused on delivering reliable power at the lowest net cost,
without engaging in environmental and social activism. It is true that emissions have some
costs associated with them, but they are trivial compared to the cost of"green energy".
Enmeshing "equity" concerns in your planning will only lead to grief. Power generation and
grid stability is a difficult enough technical challenge on its own. Distracting your
organizational focus will only lead to an inability to effectively complete your job, from which
failure the poorest and most vulnerable will suffer the most.
For example, poor people die when power fails in the winter. Yet the utility Planning Margin
(page 40, labeled "32" of the "DRAFT 2025 IRP TAC2 Presentations 1-30-24" document)
forecast shows much slimmer margins in the future, both in winter power generation and
overall, in conflict with the margin planning stated by the IRP just a year ago (page 206
labeled 9-15 of the "2023 Electric IRP Final w cover" document) showing consistent
wintertime planning margin moving forward. If you think this is all so much scare-mongering, I
merely note that the actual reported margins for the latest three semiannual reporting periods
(10%, 13%, and 15%) have fallen far below the forecast margin (39%) and are lower even
than the lowest margins projected in the future (17%). It appears all it would take is one bad
winter and the poor will be very equitably freezing to death while those with foresight keep
warm burning wood which, if it makes a difference, is a far"dirtier" fuel even than coal).
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Appendix M: TAC Member Comments Outside of TAC Meetings
Speaking of"clean" energy, I hope I have made it clear that I am in complete opposition to the
notion that CO2 is somehow dirty. However, I grant for the sake of argument that "a transition
to clean energy" (or perhaps "transiton" as Brandon might have it) is the goal. With that
concession, I find it completely baffling that the only mention of the cleanest, most reliable,
safest, and cheapest source of energy is at the very end of the document. Whose unserious,
unscientific, kindergarten-level, self-loathing, luddite idea was it to state off-hand "No nuclear
energy" as if this was a reasonable assumption? The question is rhetorical. It was, no doubt,
a politician. As to the "Affordability Initiative", it's all very nice sounding to forgive "Arrearage"
but what this actually amounts to is wealth redistribution under the guise of compassion. If
you really wanted to make power more affordable, actually lower your costs and prices for all
of your customers. As it is, you are effectively engaging in discriminatory pricing which, I state
once more, is totally illegal.
Equity is a far greater danger to the poor than CO2 emissions and climate change. Your job
as a utility is to make power cheap and reliable. Focus on that, and the rest will follow.
Respectfully,
Paul Spooner P.E.
Avista Response
Thank you for your comments. As an Idaho customer, the equity provisions we are required
to follow will apply to Washington portion of our plan, such as the creation of the equity
advisory group and tracking of customer benefit indicators. The cost to comply with these
requirements will also be assigned to customers in Washington state. Also, our load service
in Idaho will have to follow least cost planning, therefore, costs of uneconomic "clean" energy
will not be borne by customers in Idaho, if the Idaho Commission does not allow these cost to
be included in rates. As you may know we have to balance two very divergent states from a
policy point of view, I am sure at some future point we will have separate plans for both
Washington and Idaho customers.
Bill Garry, Subject: IRP TAC Comments on climate change 4/22/24
Hi John,
Attached are some comments I wanted you to see. These are a little drastic, but I am
concerned that all of us need to better understand the impending catastrophes with some of
the "tipping points" approaching. Especially the Atlantic Meridional Overturning Circulation
possible collapse, and the loss of Antarctica and Greenland glacier ice. This is all difficult to
convey or to predict with certainty, and I appreciate your efforts in planning.
Thanks for the opportunity to comment.
Bill Garry
Attachment:
Here are some comments on the April 9, 2024, Avista IRP TAC meeting which talked about
climate change and climate modeling. I am concerned that using the worst case RCP 8.5, or
"business as usual" case, for predicting energy demands and required loads is ignoring the
massive impacts that warming of 4-5 degrees Celsius by 2100 would have on the whole
world's civil order. We had a simple fire possibly set by a malfunctioning light pole (Medical
Lakes, 2023) cause huge destruction and strife. Large-scale migration to avoid impossible
living conditions may affect millions, if not billions, of people within 25 years. If Washington
State is more favorable for surviving than Bangladesh which actually might be completely
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Appendix M: TAC Member Comments Outside of TAC Meetings
flooded by 2100) or Mexico City (which may have no more water by 2050) we will see more
pressure for more than just "affordable housing".
Simple economics also shows how our cheap electricity will change to expensive as
Californians now pay 32 cents per kilowatt-hour and we pay 10 cents. Better transmission
lines will also mean better competition as well as better supply. The Pacific Intertie already
exists from Celilo to Los Angeles.
I realize the IPCC (Intergovernmental Panel on Climate Change) weaves a web of confusion
with its RCP's and SSP's. They have not been successful explaining what is really a difficult
and impossible job to predict the future. And I understand Avista's predicament in using that
information. You need to use the best available methods. The IRP planning time frame is just
two-three years, and 25 years ahead is impossible. I think it would be good to tell people that
the realities of climate change are not predictable, but the best guesses by knowledgeable
scientists say we face huge problems that will take large investments in production,
transmission, and securing our energy supplies. Conservation is by far the cheapest and
most desirable first effort. This may be against the direction of stockholders, but Avista is a
Public Utility.
Following are a few quotes:
Dr. Richard Moss said in 2010 in the periodical Nature:
"RCP8.5 cannot be used as a no-climate-policy reference scenario for the other RCPs
because RCP8.5's socioeconomic, technology and biophysical assumptions differ from those
of the other RCPs."
Dr Glen Peters, research director at in Norway, tells Carbon Brief:
"With the benefit of hindsight, the 'new scenario framework' (SSP/RCPs) did not
function as planned. The integration between climate models and IAMs (RCPs and
SSPs) never really happened; the RCPs were only intended to be a short-cut, and
merged with SSPs back in 2012, but it is 2019 and we are only now seeing
integration, albeit somewhat limited. At this point I think only a vanishingly small
number of modellers on both climate and energy understand the background on
why SSPs and RCPs were even developed, and that has led to deep
misunderstandings.
Avista Response
Climate science is an ever-changing dynamic field of study. Thank you sharing this
information.
Avista Corp 2025 Electric IRP 6

Appendix M: TAC Member Comments Outside of TAC Meetings
Katie Chamberlain, Renewable Energy Technical & Policy Analyst, Renewable
Northwest, 1131/24
Hi John,
I attended the TAC meeting yesterday on behalf of Renewable Northwest (RNW). Thanks for
all the info - it was great to hear about the ways Avista is incorporating equity into planning
and practice.
I'm emailing Avista for two reasons: first, to offer some thoughts on the overall TAC process
to facilitate deeper engagement, and second, to provide some feedback on the storage
technologies conversation from the first TAC meeting.
1) RNW finds it helpful that the company sends the slides before the meeting so TAC
members can be prepared. In addition, RNW thinks it would be helpful if Avista could highlight
the specific topics/questions they are asking us to weigh in on both in advance of the meeting
and in a brief summary after the meeting. That way it's quite clear what the company
is looking for feedback on, and people can provide comments during the meeting or after in
writing.
2) RNW understands that Avista is deciding which storage options to model and we'd like to
suggest that the company model options for short, medium, and long duration storage,
including lithium ion and sodium ion for short duration, pumped hydro and compressed air
energy storage for medium duration, and metal air and flow batteries for long duration. RNW
believes that modeling a broader set of commercially available storage options would be
beneficial to the resource planning process.
Thank you for your consideration.
Katie
Avista Response
As far a storage, we've not yet added Sodium-ion to our list yet, we are not opposed so we'll
look into it- if you have any sources for information please send them my way. CAES we
dropped a while back and went with the liquid version, maybe we should look into it again.
Thanks again for the ideas.
Update:
Avista decided to not include sodium storage due to cost uncertainty and not being materially
differentiated from lithium-ion from a high-level operating point of view. Avista does see
sodium rather then lithium-ion being a better long-term short-term storage resource if
manufactures move to this direction due to public safety. Avista also chose not to include
CAES as other storage resources are lower cost for the same benefits.
Katie Chamberlain, Renewable Energy Technical & Policy Analyst, Renewable
Northwest, 1/31/24
Hi James,
Thanks for another great TAC meeting today. Kate Brouns (cc'd) and I were in attendance,
and we wanted to follow up briefly about the load forecast. I think you mentioned that the load
forecast doesn't include data center growth but that you were considering either including that
in the high load growth scenario or in a separate scenario. I don't know that we have a
reference between those two approaches, but definitely encourage some consideration of
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Appendix M: TAC Member Comments Outside of TAC Meetings
data center and large customer growth. Looking forward to continued updates and discussion
on this front.
Thanks,
Katie
Avista Response
We likely will include a large customer in the forecast for the DRAFT IRP, if the customer pulls
out before finalizing the IRP we'll remove them for the final IRP. As far as data center what
sizes are you seeing? We have heard of up to 200 MW, but as also around 50 MW. I was
considering assuming 100 MW for the scenario.
Update:
Avista ultimately included a 200 MW data center load scenario
Dave Van Hersett, May 13, 2024
May 13, 2024
To: James Gall, John Lyons and TAC members.
From: Dave Van Hersett, Retired Professional Engineer and Founding TAC Member
Subject: Reflections of six decades of utility service in PNW
Reference: Role of WA UTC, then and now
BACKGROUND: These are the reflections of an 85-year-old on the six decades of my career
as a Professional Engineer in the electric utility industry here in the Pacific Northwest. I first
went to work for The Washington Water Power Company (TWWPCO) the summer of 1960. A
college student working with the mechanical maintenance crew. This was a hands-on
experience on how the utility generation and distribution resources are kept operational. After
graduation from WSU and a tour in the US Air Force during the Vietnam conflict rejoined
TWWPCO as a Mechanical Engineer working on the construction of the Centralia 1400 MW
coal plant, two gas turbine projects and the conception of and development of the 50 MW
wood fueled power plant at Kettle Falls. Note that the 1400 MW centralia plant can run the
city of Seattle by itself. For your prospective, it takes one 100 car train of coal to provide the
energy to run Seattle for a day.
In 1980 1 left regular pay checks to develop 5 — 20 MW wood fueled power plants in Pacific
Northwest sawmills. Next co-founded Northwest Energy Services, Inc. to install energy
efficient improvements on college campuses, hospitals, schools, and grocery store chains.
Measured actual savings and sold these savings to utilities in PNW, mostly Bonneville Power
Administration.
WASHINGTON STATE UTILITY COMMISSION (WUTC) MISSION STATEMENT
EVOLUTION
These six decades of working in the Pacific Northwest utility industry gives me a unique view
of how the WUTC has changed its mission over the years. The Mission Statement for the
WUTC is: TO PROTECT THE PEOPLE OF WASHINGTON BY ENSURING THAT
INVESTOR UTILITIES ARE SAFE, EQUITABLE, RELIABLE AND FAIRLY PRICED.
Over the years the appointed Washington Commissioners have modified their actual mission
from representing the customers interests to that of implementing the political programs
dictated by the current administration. They implement their desires on the investor utilities
by controlling the rate increases they authorize. If the investor utility does not go along with
their program, then the rate increases are withheld. In this manner we now have amateurs
running our electric and natural gas utilities instead of professional engineers trained and
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Appendix M: TAC Member Comments Outside of TAC Meetings
educated in the development, design, installation, and distribution of electric and natural gas
energy resources.
We now see that investor utilities are now selecting more expensive generation options
instead of selecting generation resources that are equitable to all customers, reliable 24 hours
per day, and fairly priced. The utilities have replaced 2 — 3 cent per kwh fossil fueled
generation like Centralia with green 6 -8 cent per kwh wind and solar generation. These
green resources require natural gas (another fossil fuel) generation to back-up the wind and
solar generation when these green resources cannot meet the customers loads. Natural gas
is a energy resource that comes out of the ground and does not need a manufacturing
process as compared to coal and nuclear to generate electric power. Natural gas is the
lowest cost fossil fuel energy resource. The result of green generation has created a huge
demand for limited natural gas resources driving up the price of natural gas two to three times
more than the historical price. We now have amateurs dictating the operation of utilities
rather than the professionally trained engineers and experts managing and running the
utilities.
For instance, how much wind generation is needed to replace the 1400 MW coal plant at
Centralia that could provide electric service to Seattle. It would require seven wind mills per
mile from Seattle to Spokane, some 300 miles. This would mean the construction and
installation of some 2100 wind generators along with the needed new transmission lines to
gather this electric energy for delivery to the customers. Note that this green resource would
only work when the wind is blowing. Also note that solar only works when the sun is shining.
The result we are now experiencing higher energy rates of all kinds for all investor utility
customers. In addition we have more forest fires that create orders of magnitude of more
emissions that cover the whole state at times, and less reliable generation resources to meet
the needs of the investor utilities customers.
The most recent Washington Utility Commion subsidy program, as a result of their caused
higher utility rates, is to have the investor utility, Avista, identify "disadvantaged" customers
and provide them with funds to offset the higher cost of electric services. These funds will be
taken from the existing Avista customers by raising their rates to pay for this subsidy. This is
not a fairly priced service to all customers. It is just another way to tax citizens to pay for the
implementation of political objectives rather than provide equitable, reliable and fair pricing. It
is also another way to get more citizens on the payroll of the government to get more votes.
Note that Avista's electric rates historically are among the lowest in the nation due to Avista
and Washington Water Power's actions in the past. This too is changing in the near future.
HOW TO GET BACK TO REALITY
So how can we get back to having professionals operate utility systems and eliminate the
political influence on our most needed resource, electrical and natural gas energy service to
its customers.
Solution 1: APPOINT COMMISSIONERS THAT HAVE EXPERIENCE AND A STAKE IN
THE SERVICE AREAS UNDER THEIR JURISDICTION. Change the selection process by
removing the appointments by the current political occupants of the state government. We
surely do not need a commissioner from California to direct how we obtain our energy
resources here in the Pacific Northwest.
Solution 2: CHANGE THE BUSINESS MODEL OF THE INVESTOR UTIITY TO THAT OF A
PUBLIC UTLITY ORGANIZATION. This would remove the utility customers out from the
jurisdiction of the WUTC. This can be accomplished by a vote of the customers to form a
public utility.
The WUTC has changed their objectives under the guise of"environmental goals" as lobbied
aggressively by the special interest groups (the one percenters) in the absence of input from
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Appendix M: TAC Member Comments Outside of TAC Meetings
the actual customers. These special interest groups came to the TAC meetings with their
plans only to be rejected by the utilities based on the input from their TAC members. So,
these special interest groups (the one percenters) then went to the state legislature and were
able to pass legislation that required the utilities to adopt higher cost energy resources and
resources that created more pollution for the state. These one percenters also were
successful in passing legislation changing the way we manage our forests to provide fuel for
forest fires rather than to produce products for mankind, like lumber for affordable housing.
Timber is like other crops, is used to support mankind's needs. When I was is high school the
world population was 2 billion, now it is 7 billion. We need lumber products to provide
housing and paper and other products made from trees.
The result is that our state is now having more expensive energy resources for our
businesses and customers, reducing their competitive position in both the domestic and
international market place. Note that businesses are leaving WA state to find a more friendly
business environment, like Boeing.
NOW LET'S LOOK AT THE AVISTA UTILITY'S ROLE FOR ITS CUSTOMERS
When I worked for WWP the overriding mission was to provide the best and lowest price
energy resources for its customers. Over the years their mission has evolved to that of what
they have to do to comply with the dictates of the WUTC. This enabled the utility to provide
compensation to its investors. The customer biased mission in the 60' s and 70's brought
about low cost-hydro, coal generation and biomass fueled generation. These generation
resources were the result of detailed engineering studies and environmental benefits. Their
long-term impact to the customer rates were significant to keep their rates among the lowest
in the nation. This gave our business and economy an advantage over those states and
countries with higher energy costs.
In recent years Avista Utilities has gone along with the demands of the WUTC to insure
approvals of their rate increases. Avista has no market risk as their market is held in place by
the WUTC. Even so the utility executives in recent times have enjoyed a ten-fold increase in
their compensation. At the same time Avista has used the combined strength of the 300,000
plus customers to provide the strength to finance the acquisition of other utility systems and
investing in real estate. Avista should be focused on using their customer strength to provide
reliable and low-cost energy services. Instead, they are installing higher cost and less
reliable wind, solar generation and shutting down low-cost fossil fuel generation per the
dictates of the WUTC. Just what do us customers get from the higher priced Avista
management other than higher rate increases and less reliable electrical and higher priced
natural gas service?
The utility could have gone to the State Supreme Court to challenge the changing role of the
utility commission. This would have been good for the customers and maybe not good for
Avista and its investors.
WASHINGTON STATE COMPETIVE POSITION HAS DETEORIATED
Now lets look at our state's competitive position in the domestic and international market
place. There are about 2400 coal fired coal plants in the world today. China has 950 coal
plants and is building 121 new coal plants. India has 285 coal plants and is building 39 new
coal plants. The USA has 200 coal plants and is building 4 new plants. Just how much
impact on the world pollution will shutting down one coal plant in Washington state impact the
world pollution? The new Washington State environmental laws have also reduced the
management and harvesting of timber in our state. The result is growing trees to produce
fuel for forest fires instead of products for mankind. When I was in high school in the 50's the
summers were spending time at the lake water skiing, etc. Smoke from forest fires was an
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Appendix M: TAC Member Comments Outside of TAC Meetings
unusual event. Now we have smoke from forest fires covering the entire state of Washington
several times a year. Today we have fires that destroy property and kill our citizens because
of the armatures now dictating how to run our forests. We need to revert back to the forest
management practices of the 50's and 60's to eliminate statewide pollution and produce
timber products for our citizens and export products to the nation and the world. These
recent green forest management practices have made ghost towns of 13 towns in the vicinity
of Spokane and the loss of employment of some 30,000 people. To offset the tax revenue
of this loss economic businesses, the state has increased its taxes to provide for the over-
growing government payrolls. Note the price of gasoline for one.
FAILING TO MEET EVER INCREASING POPULATION GROWTH
As I have observed during these 60 years of reflections working in the utility industry, my
hope is that we return to time when we had technically trained personnel running and
managing our greatest resource, energy. Water and energy are the two most important
resources that our customers and citizens need to meet the needs of our ever-expanding
population. When I was in high school in the 50's the world population was 2 billion. The
world population today is 7 billion. Today we have many in the world going hungry and no
water. To provide food, water and shelter for the ever-increasing population we have to
carefully manage and optimize our limited resources. Letting the special interest groups, the
one percenters, call the shots is turning our state and businesses backwards, increasing
pollution and mismanaging our limited resources. The politicians of today seem to be more
interested in getting reelected rather than serving the best interests of the people they
represent.
OUR EDUCATION SYSTEM IS FAILING TO KEEP UP WITH WORLD COMPETITON
Our education system has also lost its way, we now have to get our technically trained
personnel from around the world rather than from our own states and nation schools. Just
compare the names of the doctors on the hospital directories from the 60's to that of today. I
am lucky to be able to retire and enjoy my grandchildren and golf with friends. My wife of 62
years and I have been blessed with four children. They include two engineers, a school
teacher and a business owner and six grandchildren.
GOOD BYE, I TRIED MY BEST, HOPE YOU WILL TOO
There are ten veterans in my extended family. We know the price of freedom and the risks of
not speaking up to those taking our rights for their benefit.
Good bye and good luck, Dave Van Hersett, senior citizen.
Avista Response
Thank you for your comments.
Avista Corp 2025 Electric IRP 11

Appendix M: TAC Member Comments Outside of TAC Meetings
NW Energy Coalition, Fred Huette, letter filed with UTC on November 15, 2024
Avista deserves recognition for its thoughtful planning and commitment to transparency by
making materials, data, and models accessible, while demonstrating increased dedication to
community engagement. We appreciate the company's shift since the last IRP, now focusing
on actionable steps needed before 2030. Overall, we commend Avista for presenting a
thorough, balanced, and well-documented proposal and provide the following high-level
points to help shape the final Electric IRP and Washington CEAP. And on the last point, while
we have concerns and perspectives on the details, we are reassured by Avista's stated
commitment, supported by the details of the Clean Energy Action Plan, to faithfully adhere to
the requirements of the Clean Energy Transformation Act "CETA" .
Avista Response
Avista appreciates the comments.
NW Energy Coalition, Fred Huette, letter filed with UTC on November 15, 2024
Load Forecast:
We share the rising concerns of all involved in electric resource planning across the
Northwest about the future magnitude and shape of new power demand. The projected
increase has substantial uncertainty but also offers the prospect of driving sustainable
economic expansion, emissions reductions, eventual cost stabilization, and contributions via
load flexibility to system resource adequacy and reliability.
The increasing gap in the growth rates between average and peak demand rightly gets
attention in the draft IRP and puts more focus on the ability of demand response ("DR") and
storage to reduce critical peaks and the scarcity pricing, resource adequacy and reliability
stresses.
This is no longer a theoretical issue, and recent heat waves and the extended January 2024
freeze have taught us all difficult and expensive lessons. But that also opens a "learning
opportunity" for closer focus particularly on the critical peak value of energy efficiency,
demand response/load flexibility and storage (both grid-connected and customer-side).
We suggest that Avista immediately begin supplemental studies to go further into the
dynamics of demand surges and the diverse range of measures and strategies for reshaping
demand and reducing cost and reliability risk. With less urgent needs than other regional
utilities, Avista is in a position to address these issues thoroughly and effectively without
needing to make snap decisions.
Avista Response
Avista appreciates these concerns and will consider supplemental studies into the dynamics
of demand surges as staffing and budget allows.
NW Energy Coalition, Fred Huette, letter filed with UTC on November 15, 2024
Customer Energy Efficiency, Demand Response, and Storage:
NWEC has proposed "customer side resources" as a useful framing for spotlighting the very
large, durable and nimble assemblage of actions that customers can take to provide value to
themselves and to the grid. This can be operationalized under the "virtual power plant"
concept or otherwise, but the key attributes are a balance of interests and capabilities
between the utility and customers.
Avista Corp 2025 Electric IRP 12

Appendix M: TAC Member Comments Outside of TAC Meetings
Concerning energy efficiency, NWEC applauds Avista's statement that "Energy efficiency
continues to be a cost-effective method to reduce customer demand and avoid new
generating resources," and that over 150 MW has already been achieved, with an additional
105 aMW in reach by 2045, covering 32% of new demand.
However, we encourage Avista to take a closer look at how the context for utility operations,
resource costs and critical peak challenges is dramatically increasing the real cost-
effectiveness of energy efficiency, including a revamped assessment of diurnal, seasonal and
critical peak conditions. We believe this will open up considerable headroom for additional
and accelerated energy efficiency acquisition, especially when combined with opportunities
for more efficient options for new large loads and building and vehicle fuel switching toward
electric supply.
On demand response, we confess to disappointment with the draft IRP. From now until 2045,
just 30 MW of"pricing" DR and 58 MW of"DLC" programmatic DR is included, most of it after
2035. In addition to mature methods for existing large commercial and industrial load, as well
as important but not yet fully defined options for new data centers and manufacturing
facilities, there is tremendous opportunity for automated appliance DR (space and water
heating, EV charging, etc.).
A moderate "rule of thumb" suggests that achievable DR potential is 10% of peak load. Over
the planning horizon, Avista should consider a DR target level in that range, and for 2030 with
about 2300 MW of peak demand, 5% of that (115 MW) as a potentially achievable target.
Furthermore, the deeper analysis of critical peak conditions we mentioned above has special
relevance here. That amount of DR is the equivalent of a full gas peaker without the
associated scarcity pricing and gas delivery risk, both of which Avista and its customers
unfortunately experienced in January 2024.
No doubt the effort to achieve substantial and accelerated DR is considerable and will take
several years. But the results of the draft IRP pose a serious threat of"analysis paralysis."
Just to name one clear opportunity, Washington state regulations now require that every new
electric water heater be equipped with a CTA-2045 or similar device which provides a literal
plug-and-play for utility device management and flexing peak-correlated water heating
demand in response to grid conditions.
As the cost of highly efficient heat pump water heaters continues to fall, their uptake for
electric water heater replacements, new buildings and gas to electric conversions will grow
rapidly. This is an ideal opportunity for Avista to put grid-managed water heating at the front
end of a broad and fast-growing integrated demand response resource in partnership with its
customers.
Likewise, the opportunities for storage will only grow in the coming years. While lithium ion
batteries remain relatively expensive, they and other formats can be deployed in almost any
context at any scale, and provide reliable and precise capabilities for almost any customer
and grid service. We think storage can be counted on for a greater amount of new system
resources starting immediately.
Avista Response
Avista will continue to evaluate DR potential within our service area and take reasonable
actions that are consistent with our strategy.
Avista Corp 2025 Electric IRP 13

Appendix M: TAC Member Comments Outside of TAC Meetings
NW Energy Coalition, Fred Huette, letter filed with UTC on November 15, 2024
New Supply Resources:
We are encouraged by Avista's commitment to releasing an all-source RFP immediately in
early 2025. This will apply early-mover advantage to Avista's effort to stay with and ahead of
CETA requirements, resource adequacy needs and development of crucial operational
experience, while directly diminishing supply chain constraints and cost and delivery risks.
We also believe this is a big step in the right direction toward resource diversification
specifically to diminish gas power plant wholesale cost and delivery risks, both during stress
periods and generally as LNG exports from western Canada start to shift the supply/demand
balance for the domestic market. In turn early action to acquire clean and diverse resources
could diminish and defer the need for the projected new gas peaker in 2030.
While Avista proposes an action plan item to investigate options to increase natural gas
availability for existing and potential natural gas generation, NWEC is concerned about the
limited topology of the Northwest gas transmission network and increasing operational and
scarcity pricing impacts that already pose serious risks to customer value and system
reliability. As a result, any effort to increase rather than decrease reliance on wholesale
natural gas for power production, especially during critical peak periods, must receive the
closest scrutiny in comparison to alternatives.
Indeed, reliable, clean and affordable opportunities are now available from a diverse strategy
to address those risks: acceleration of customer side resources (energy efficiency, demand
response, distributed generation and storage), additional transmission, and participation in
the widest possible power market to take advantage of load and resource diversity and
optimized dispatch.
On the last point, in mid-January 2024 Avista's participation in the Western Energy Imbalance
Market ("WEIM") provided crucial access to resources and transmission across almost all of
the western grid and flexibility mechanisms within the market to afford relief at that crucial
moment, even as Avista resources were curtailed due to upstream gas pipeline curtailments.
While not directly under the auspices of the IRP, we encourage Avista to move forward on
joining the Extended Day Ahead Market ("EDAM") and augment the demonstrated benefits of
the WEIM.
In conclusion, while investigating further extension to wholesale gas supply would provide
useful information, we strongly recommend adding a comprehensive assessment of these
non-gas alternatives.
Avista Response
Avista investigates a broad range of alternatives to meet customer load, and will continue to
do so.
NW Energy Coalition, Fred Huette, letter filed with UTC on November 15, 2024
Transmission:
While NWEC does not generally take a formal position on new resource and transmission
projects, we are generally supportive of Avista's interest in development of the proposed
North Plains Connector project, along with other regional utilities. While the draft IRP
Avista Corp 2025 Electric IRP 14

Appendix M: TAC Member Comments Outside of TAC Meetings
indicates a related interest in upgrading the Colstrip Transmission System ("CTS"), we also
encourage Avista to consider the possibilities for transmission expansion between the CTS
and the Avista system. While that is necessarily a long and complex build and would involve
multiple partners, we believe there is major value in strengthening access to Montana wind as
well as the MISO and Southwest Power Pool markets that could be enabled by North Plains.
Finally, we congratulate Avista for its joint effort with Idaho Power on the Lolo-Oxbow upgrade
and the federal grant that will enhance available transmission capacity and wildfire resilience.
Avista Response
Thank you for the comment.
NW Energy Coalition, Fred Huette, letter filed with UTC on November 15, 2024
CETA Compliance
NWEC is generally supportive of the draft IRP's directional approach. As mentioned above
we believe the most prudent strategy is "smart from the start," combining the 2025 RFP with
accelerated efforts on customer side resources — demand response, storage and energy
efficiency. While CETA compliance is a requirement, it is also the foundation of a stronger,
cleaner, more resilient and more affordable power supply for customers going forward.
On November 4, 2024, the UTC released another iteration of"CETA Use" draft rules that
remove the prior-proposed monthly use cap for utility compliance (UE-210183). These draft
rules would establish additional utility reporting requirements in order to gather data that
would have been used to calculate and assess the monthly use cap. As this proposal is
finalized, we encourage Avista to support these reporting requirements and recognize the
UTC's authority to implement a monthly use cap in the future.
Avista Response
Avista will continue to monitor the development of the "CETA Use" rules and respond in a
manner consistent with our planning strategy.
NW Energy Coalition, Fred Huette, letter filed with UTC on November 15, 2024
Resource Adequacy
NWEC participates in the public process of the Western Resource Adequacy Program
("WRAP") and applauds Avista's program participation. We encourage a more nuanced
approach to its inclusion within the IRP context. The WRAP program requirements include
qualifying capacity contribution ("QCC") methods, planning reserve margin ("PRIM"), capacity
critical hours, and other aspects that are tightly bound to the short term (season-ahead) and
operational phases of the program, not to the more dynamic view needed for longer term IRP.
We agree with Avista's choice of using its own PRIM values and urge caution in copy-and-
pasting other aspects of the WRAP approach into the IRP context.
In a related matter, we are supportive of Avista's forward-looking approach to a climate-
adjusted baseline. However, we also encourage Avista to adopt a consistent approach to use
of IPCC metrics and methods. For example, in our view RCP 4.5 ("representative
concentration pathway") should be employed year-round. That RCP level actually
encompasses quite high future fossil fuel and other emissions with even more limited
mitigation measures than are currently registered within the UNFCCC Paris Agreement
framework. While there is some risk that climate change will advance more rapidly than
Avista Corp 2025 Electric IRP 15

Appendix M: TAC Member Comments Outside of TAC Meetings
considered under RCP 4.5, there is very little chance that it would reach the levels in the RCP
8.5 analysis. And going forward, the use of split seasonal approaches could create analytical
discontinuities.
Avista Response
Avista chose to use RCP 4.5 for non-summer months and RCP 8.5 for summer months. This
allowed us to evaluate our reliability both with colder winter months and warmer summer
months. Our 2023 IRP utilized RCP 4.5 for the entire year, as you suggest. Avista will
continue to evaluate the use of climate modeling in our load forecasting and IRP reliability
modeling to meet our analysis needs. Avista also appreciates the recommendation of using
RCP 4.5 going forward and will conduct additional analysis to use this data differently to
achieve outcomes covering the risks Avista has with using future temperatures.
Avista Corp 2025 Electric IRP 16

This Page is Intentionally Left Blank

Appendix N
2025 Electric Integrated
Resource Plan
Appendix N — Energy Burden
Assessment
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Appendix N
AVISTA ENERGY BURDEN ASSESSMENT
ENERGY BURDEN REDUCTION STRATEGY
SEPTEMBER 2021
PREPARED FOR PREPARED BY
Ryan Finesilver Hassan Shaban, Ph.D.
Avista Empower Dataworks
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vjsta dataworks

Appendix N
INTRODUCTION
This report presents a suggested strategy for Avista to meet its energy burden
reduction goals. It begins with an overview of Avista's current customer
energy burden, followed by a list of potential actions for reducing customer
energy burden.
CONTENTS 3. ENERGY BURDEN REDUCTION STRATEGY.......................................27
2.1 POTENTIAL ACTIONS.............................................................................28
INTRODUCTION.................................................................................................3 2.2 NEXT STEPS.............................................................................................42
CONTENTS..........................................................................................................3 2.3 ADDITIONAL RESOURCES....................................................................43
1. METHODOLOGY......................................................................................4
1.1 GENERAL APPROACH...............................................................................5
1.2 DATA SOURCES.........................................................................................6
1.3 FINAL ATTRIBUTES AND METRICS........................................................8
2. AVISTA'S ENERGY BURDEN BASELINE.............................................74
2.1 AVISTA RESIDENTIAL SECTOR PROFILE...........................................15
2.2 ENERGY BURDEN ....................................................................................17
2.3 LOW INCOME CUSTOMER SEGMENTS...............................................20
2.4 ENERGY BURDEN PORTFOLIO EFFECTIVENESS..............................22
2.5 ADDITIONAL CONTEXT..........................................................................26

1 : THO DO� OGY
empower dataworlt

Appendix N
1 .1 GENERAL APPROACH
This energy burden assessment relies on collecting
customer-level data, modeling missing attributes, then
aggregating key metrics by geographic, demographic or
building variables for analysis. The customer data comes
from various sources as described in the rest of Section 1.
Some demographic attributes were modeled or inferred
using statistical techniques due to lack of primary data in
CIS or other sources. American Community Survey data
was mainly used to sanity check aggregate statistics of
customer-level data at the census tract level.
Three types of metrics were calculated:
• Metrics related to energy burden based on
demographic and geographic characteristics
• Participation and funding in Avista's Energy
Assistance Programs
• Customer energy use characteristics
The final dataset and results will be packaged in a web
dashboard for Avista staff and the final underlying
dataset will also be provided in a later deliverable.
ENERGY BURDEN ASSESSMENT empower dataworks ENERGY BURDEN REDUCTION STRATEGY • 5

Appendix N
1 .2 DATA SOURCES Efficiency Program in 2019-20, along with installed
measures, estimated kWh savings and rebate amounts.
The rebate amounts were used to aggregate the
The data sources leveraged for the analysis are described "assistance funding" provided to the customer,while the
in this section.
deemed kWh savings were used to estimate the annual
DATA PROVIDED BY AVISTA bill impact based on average bill savings of 9.4
cents/kWh. This rate is in the middle of Avista's tiered
Customer Information System (CIS): This data included residential rate and we expected it be a good estimate of
monthly electricity bills for 24 months in 2019-20, the true bill savings. Avista also provided participation
account numbers and service addresses. A separate data data for the Multifamily Direct Install and residential
extract included the dates and customer accounts that energy efficiency measures - these will be used in later
received late payment notices, allowing us to calculate phases of the energy burden assessment to fully quantify
the on-time payment rate for different customer the energy burden reduction of non-low-income
segments. programs.
Direct Assistance Program Data: We received a list of 2022-45 Conservation Potential Study: A copy of
participating accounts in six of Avista's direct assistance Avista's 2022-45 Conservation Potential Study was
programs (LIHEAP, LIRAP, Senior/Disabled Rate, provided. This gave a big-picture view of anticipated
Project Share, Housing Assistance and other conservation opportunities for the general population in
miscellaneous assistance) in 2019-20, along with discount Avista's service territory and helped frame some of the
amounts and dates. This allowed us to calculate the total recommendations for energy burden reduction
assistance funding at the household level. opportunities.
Energy Efficiency Program Data: We received a list of
participating accounts in the Low Income Energy
ENERGY BURDEN ASSESSMENT empuwei dataworks ENERGY BURDEN REDUCTION STRATEGY• 6

Appendix N
DATA OBTAINED FROM OTHER SOURCES county,we were able to match most of these addresses to
the appropriate land parcel using a "point-in-polygon"
Geocoding: All customer addresses were geocoded to a algorithm. This algorithm detected whether a given
latitude/longitude pair to facilitate geographic analysis. latitude/longitude pair (obtained from geocoding) fell
In addition,we mapped the latitude/longitude pairs to within a particular land parcel (the Spokane county
census tracts, block groups and blocks in order to pull assessor made available a GIS file of parcel boundaries).
additional aggregate statistics.
Customer Demographics: Data was purchased from a
County Assessor Data: We obtained publicly available third-party data compiler that aggregates data from
assessor data from the following counties: Spokane, public sources and credit bureaus. This data was mapped
Stevens, Whitman, Adams, Asotin, Lincoln, Ferry and to the CIS dataset using customer addresses and included
Pend Oreille. A handful of customers in other counties total household income, age of occupants, and
were still included in the analysis but without assessor homeownership status for a little over 60% of residential
data. The assessor data included appraised values for households. Demographic attributes for some customers
homes, square footage, building year built, Washington were modeled due to lack of primary data in CIS or other
state building use codes (residential, mobile homes, sources. The modeling approaches are described in the
commercial and industrial), number of buildings on a next section.
land parcel, and other minor data points that were useful
for performing general QA. American Community Survey(ACS): ACS data (2019 5
year estimates) was primarily used for QA to ensure that
The addresses in this dataset were standardized to US aggregate counts for various demographic attributes
Postal Service format, then matched with addresses in match the expected distributions from ACS.
the CIS data. Some addresses existed in the CIS data but
not in the assessor data (typically happens when multiple
buildings occupy the same land parcel). For Spokane
ENERGY BURDEN ASSESSMENT empower dataworks ENERGY BURDEN REDUCTION STRATEGY• 7

Appendix N
1 .3 FINAL ATT RIBUTES AND METRICS
The calculation methods for the metrics and attributes those initial guesses and adjusts them to ensure that the
used in this report are described in this section. For all overall income distribution within a census tract is
attributes,we also capture metadata related to the source similar to the overall income distribution from the ACS.
of data and the confidence in the value (for example, data The calibration iteratively takes a small sample of
from primary sources has a high confidence, while households (under 10%) and bumps them up or down by
modeled data has lower confidence). All of the data is one income level within certain bounds until the modeled
robust for aggregate analysis, while high confidence data income distribution resembles the ACS income
is better suited to customer-level marketing and program distribution.
targeting.
Validation: The modeling procedure yields fairly good
Household Income: Income data was only available for results - it is able to reproduce the incomes accurately for
60% of households in Avista's service territory. To a hold-out set of data from the original dataset,with
estimate the incomes for the remaining 40%,we used an errors under $5k/year in household income for 85% of the
iterative procedure. test set and errors under $20k/year in household income
for the other 15%. Larger errors tend to happen for
Starting from the households for which we had income households with a larger income,which are not the focus
data,we applied an imputation model - this is a of this study anyway. More importantly, the aggregate
statistical method for filling in missing data by using the metrics related to energy burden (e.g. energy assistance
home's location, home value and building type. In other need and overall burden) are very robust to errors in
words, each household is assigned an income range based individual results because we are ensuring that overall
on the incomes of similar households in their area. This distribution of income is as accurate as possible,while
is the initial guess for that household's total annual
income. Then, an iterative calibration procedure uses
ENERGY BURDEN ASSESSMENT empower dataworks ENERGY BURDEN REDUCTION STRATEGY• 8

Appendix N
the energy use does not change dramatically among unoccupied. Commercial meters were those tagged with
similar households. a specific commercial use by the county assessor or that
were on a commercial rate class (unless they were clearly
Poverty Status: The number of people living in a apartments). Additionally,we filtered out meters using in
household cannot be easily obtained from any public data excess of 60,000 kWh per year as those are likely
sources. This makes it difficult to identify a household's associated with commercial uses or are master metered.
poverty status compared to the Federal Poverty Limit or Meters that showed energy consumption less than 1200
the Area Median Income, both of which are defined by kWh/year were flagged as potentially unoccupied.
household size. The median household size in Avista's
service territory is 2.4 and all figures that require poverty Overall, the number of household meters excluding
status in this report are given as ranges between a commercial and unoccupied meters was 224- 225,000.
household size of 2 and 3. Household size for income Addresses with multiple units or tagged as multifamily
thresholds is a configurable parameter in the data properties by the county assessor were flagged as
dashboard. apartments. Mobile homes were either labelled as such
by the county assessor or were sited in a mobile home
Validation: According to the US Census Bureau, park. Non-multifamily homes with addresses but without
approximately 14% of households in Avista's service an identified land parcel are usually accessory dwelling
territory would fall under 100% of the Federal Poverty units, trailers or mobile homes - these were all included
Limit. In this analysis, the range is between 12 and 17%, in the "mobile home" category.
depending if we assume all 2-person households or 3-
person households, respectively. Validation: The aggregate housing type counts (66%
single family, 25% multifamily and 9%
Building type: Meters were classified into one of five mobile/manufactured homes) agree well with data from
building types: single family, mobile homes, multifamily the American Community Survey for the five main
apartments, commercial or master metered and
ENERGY BURDEN ASSESSMENT empuwei dataworks ENERGY BURDEN REDUCTION STRATEGY• 9

Appendix N
counties in Avista's service territory (approx. 67% single Load Disaggregation and Heating Type: A simple load
family, 25% multifamily). disaggregation was applied for all households using their
monthly energy bills. This involved taking the tenth
Homeownership Status: Homeownership status (rent vs. percentile of monthly energy use (normalized by the
own)was determined using two methods. The number of days in a billing period) as the assumed base
demographic dataset included homeownership for load. Then, the energy use that exceeded the base load in
approximately 60% of customers. For the other 40%, the winter months (October through April) was
households in multifamily apartments were tagged as designated as "heating-related energy use",while the
"Likely Renters", and households without any account energy use that exceeded the base load in the summer
changes during the two year analysis period were tagged months (May through September)was designated as
as "Likely Homeowners". This can potentially "cooling-related energy use".
undercount long-term renters and tag them as
homeowners and it can undercount homeowners who Homes with a heating-related energy use that exceeded
have just purchased their home. We are also exploring 10%were flagged as potentially utilizing electric heat,
whether we can incorporate home sales data - the intent while homes with under 10% heating-related energy use
is to tag households with an account change and an were flagged as gas heated homes.
accompanying sales record as homeowners. However, the
accuracy of the approach seems sufficient for the Validation: The approach has been previously tested by
purposes of large-scale aggregate analysis as in this Empower Dataworks vs. a variable-base degree day
study. regression and it yields similar results but at a much
smaller computational cost. The penetration of electric
Validation: The aggregate homeownership rate from this heat using this approach (56%) is slightly lower than that
analysis (61%) is slightly lower than the owner-occupied in Avista's 2022-45 Conservation Potential Study(58.7%),
housing rate from the American Community Survey(62%) but within the margin of error.
for Avista's service territory.
ENERGY BURDEN ASSESSMENT empuwei dataworks ENERGY BURDEN REDUCTION STRATEGY• 10

Appendix N
Energy Burden and Energy Efficiency Potential Excess Burden: Excess burden is the portion of a
thresholds: These thresholds were set as follows: household's energy burden in excess of the 6%/3%
threshold.
• Electrically heated:
o High-burden threshold: Greater than 6% Excess Burden
o High efficiency potential threshold: Greater = max(0,Energy Burden
— High Burden Threshold)
than 10 kWh/sq.ft. x Annual Household Income
• Gas heated:
o High-burden threshold: Greater than 3% On-Time Payment Rate: This is the proportion of all
(this might change through future CETA energy bills that did not require a late payment or
rulemaking) disconnect notice to be sent out.
o High efficiency potential threshold: Greater Energy Assistance Funding: The dollar amount of
than 7 kWh/sq.ft. funding flowing through energy assistance programs
Energy Burden: Energy burden for a household is (including discount, donation and weatherization
calculated simply by dividing annual electricity expenses programs) through discounts or rebates.
by gross household income. Customer Bill Reductions (Avoided Burden): The total
Annual Electricity Expenses bill impact from energy assistance programs. This is the
Energy Burden =
Annual Household Income same as the assistance funding for direct assistance
programs and is based on measure savings for energy
efficiency programs as described in Section 1.2.
ENERGY BURDEN ASSESSMENT empuwei dataworks ENERGY BURDEN REDUCTION STRATEGY • 11

Appendix N
Avoided Need: The total bill impact specifically for
customers flagged as "high-burden".
Census Tract Statistics: Since each customer has been
mapped to a census tract and block group,we are also
able to match customers to census tract average statistics
(e.g. highly impacted communities, presence of children,
non-English speakers, education level, environmental
pollution etc.). These will be used in later stages of the
analysis and for coordination with Avista's Clean Energy
Implementation Plan.
ENERGY BURDEN ASSESSMENT empower dataworks ENERGY BURDEN REDUCTION STRATEGY • 12

Appendix N
Energy Assistance Need: This is the sum of excess sampled from a small portion of the population (under 10%)
burden across all customers. and extrapolated across a large area. The energy use data is
self-reported and for a single month in the year,which is
Comparison to LEAD tool estimates: Energy assistance then extrapolated to a full year. This calls into question the
need was compared to estimates based on the reliability of energy burden estimates based on this data for
Department of Energy's LEAD tool (currently the only Avista. Through previous assessments, Empower
other estimate for energy assistance need). For Stevens, Dataworks has found that the tool can be accurate in some
Whitman, Adams and Asotin counties, the LEAD jurisdictions but inaccurate in others. For Spokane county,
estimates are 51% higher on average than the actuals the LEAD estimates include the entire county (with areas
from this analysis. This is primarily driven by the outside Avista's service territory), whereas this analysis
customer electricity bills that are consistently higher in only includes Avista customers, so the difference is
the LEAD dataset than actual customer bills from larger.
Avista's CIS system. The data used in the LEAD tool is
Average Annual Electricity Bill ($) Total Assistance Need (million $)
Avista's CIS Current
County System Analysis LEAD dataset LEAD dataset
Adams 1,322 1,616 1.0 1.3
Asotin 1,066 1,279 1.2 1.6
Spokane 1,018 1,215 16 29
Stevens 1,239 1,528 3.2 5.2
Whitman 941 1,213 2.0 3.1
ENERGY BURDEN ASSESSMENT empower dataworks ENERGY BURDEN REDUCTION STRATEGY • 13

2 . AVISTA I S ENERGY
BURDEN BASELINE

Appendix N
2.1 AVISTA RESIDENTIAL SECTOR PROFILE
Avista's service territory in Washington state was under 200% of the federal poverty limit and 42% of
composed of approximately 235,000 residential meters, households would fall under 80% of the Area Median
of which 225,000 were found to be occupied Income.
households (with a detectable energy use and not
designated as shops or garages). Employers: Data from the Employment Security
Department of Washington state shows that other than
Ethnicity: According to the U.S. Census Bureau, Spokane County which has a very diversified economy,
approximately 83% of residents in counties within the other counties within Avista's service territory rely on
Avista's service territory are non-Hispanic white. In jobs in agriculture, education and government and could
particular, Stevens, Whitman and Adams counties have be more susceptible to recessions and other
sizeable populations of Hispanic, American Indian and macroeconomic trends'.
Asian customers.
Household Income: The median household income for
residents in counties within Avista's service territory is
approximately$55,000,well below the state average of
$70,000. Approximately 11% of households would fall
under 100% of the federal poverty limit, 32%would fall
'Washington State Employment Security Department.
https://esd.wa.gov. Retrieved August 2021.
ENERGY BURDEN ASSESSMENT empower dataworks ENERGY BURDEN REDUCTION STRATEGY• 15

Appendix N
Energy Bills: Avista's residential electricity rates are
about average for the Northwest. This results in generally 20000
affordable annual energy bills for most (non-low-income) kA
households (approximately $1040/year with an average 0 15000
annual consumption of 10,800 kWh), despite the high
w
penetration of electric heating in the county(55-60%). v 10000
Figure 1 shows that the distribution of annual energy E
bills has a long tail; a minority(-6%) of households pay z 5000
more than double the overall average energy bill.
0
Home e:Vinta Approximately 30% h in Avista's 0 500 1000 1500 2000 2500 3000 3500 40
g pp y homes 00
Annual Electricity bill(S)
service territory were built after 1980 and 45%were built
between 1940 and 19801. There are about 30,000 homes Figure 1.Household electricity bill distribution for Avista's residential
that are more than 100 years old. Generally, older homes customers
have more opportunities for weatherization, while newer
homes could benefit more from lighting, controls and
efficient appliances.
z County Assessor Data for all Avista counties.
ENERGY BURDEN ASSESSMENT empower dataworks ENERGY BURDEN REDUCTION STRATEGY• 16

Appendix N
2.2 ENERGY BURDEN reduction that would bring all customer electricity bills
below the high burden threshold (6/0 of income for
electric heat and 3% for gas heat).
Avista customers have an average and median energy
burden of 3.4% and 1.7%, respectively. Figure 2
Avista
compares Avista's median energy burden to values
San Francisco
published in other jurisdictions. Seattle -
Metro - Pacific States -
Avista's median energy burden is similar to that of the Portland
Seattle region. It is also lower (on average) than rural Rural- Pacific States
areas in the Pacific states. New England
0 1 2 3 4 5 6
The average household paid $1040/year in electricity bills Median Energy Burden W
in 2019-20. Of Avista's 225,000 identified households,
42,000 were deemed to have a high energy burden, Figure 2.Energy burden benchmarking vs.other regions
meaning that annual electricity bills exceeded 6% of their
income for electrically-heated homes and exceeded 3% of Although averages and medians give a general indication
their income for gas-heated homes. These high-burden of energy burden across a service territory, the reality is
customers paid an average of$1300 in annual electricity that energy burden is a customer-level metric and its
bills; the higher bill average reflects their higher distribution is a better indicator of the burden that
likelihood to live in less efficient or older homes. The on- customers experience. The distribution of energy burden
time bill payment rate is moderate for residential among Avista customers is shown in Figure 3. The blue
customers in general (87%) and much lower (79%) for dashed line represents the 3% high burden threshold for
high-burden customers. The total energy assistance gas heat and the green dashed line represents the 6%
need for Avista is approximately$25M—the total high burden threshold for electric heat.
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Appendix N
Number of Households
—2251000 25000
I I
I I
Electric Heat
Low Income Households 20000
� I I
80% AM I: —94-100k I I Gas Heat
°U' 15000
200% FPL: N72-82k
10000 Bottom line: Our prime target
High Burden Households E I I is approximately 42,000
-421000 Z 5001 I I "high-burden customers"
I
I
Energy Burden a
a 5 10 15 20 25
Median: —1.7%
Average: —3.4% Energy Burden
Figure 3.Distribution of energy burden among Avista customers.
Green line indicates 6%threshold of high energy burden for electric heat.
Blue line indicates 6%threshold of high energy burden for electric heat.
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Appendix N
The goal of an effective energy assistance portfolio Other customer segments will be investigated in more
should be to prioritize the customers who most need the detail in later stages of this energy burden assessment.
assistance, i.e. the customers to the right of the 60/o/3%
thresholds.
Approximately half of the energy assistance need is borne Multifamily
by single family households,with the other half 31%
distributed among multifamily and mobile home Single
dwellers. The highest concentration of need is in mobile Family
52%
home dwellers, requiring more than $800/household in Mobile
assistance on average, compared to $500/household for Home or
ADU
multifamily and $600 per household for single family 17%
households.
Approximately, 65-70% of the energy assistance need for Figure 4.Distribution of energy assistance need by housing type.
Avista customers is among renters, indicating that
conservation programs targeted at high-burden
customers will need to grapple with the split incentive
problem between landlords and tenants, but energy
burden among homeowners should not be neglected. By
sheer volume of need, senior (60+) homeowners in the
Spokane area and renters in the Spokane area bear a large
amount of energy burden. However, other rural areas
have a much higher concentration of need (i.e. high-
burden customers need more assistance on average).
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Appendix N
2.3 LOW INCOME CUSTOMER SEGMENTS
Figure 6 shows the distribution of energy burden and
energy efficiency potential (defined through Energy Use
Intensity thresholds) across all low-income residential High Burden-
High Potential
customers. In a perfect world, the energy assistance 22%
portfolio would match these customer segments. For Low Burden-
or­ Low Potential
example: 41%
• Conservation programs should primarily serve high
burden, high potential households High Burden-
• Direct assistance programs should primarily Low Potential
29% if
serve high burden, low potential households Low Burden-
High Potential
• Crisis/emergency programs should primarily 8%
serve low burden, low potential households
• Traditional conservation programs with financing Figure 5.Avista's low-income customer segments by energy burden and
should serve low burden, high potential households energy efficiency potential.
Aligning targeted customers with program strengths Almost half of Avista's low-income customers are low-
results are the most cost-effective pathway to energy burden and low-efficiency potential. These customers'
burden reduction. energy bills may not be a huge expense relative to
housing, medical and education expenses, and they
should not be prioritized in the more intensive programs,
such as weatherization.
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Appendix N
High burden customers are almost evenly split between
high potential and low potential households. Since 3500
i
neither high or low potential customers dominate the 3000 $400 excess burden
high burden group, this indicates that a more holistic o 2500
L
approach that combines conservation and direct o z000
assistance may be suitable for the first group, while o
1500
direct assistance and lighter touch conservation is more
suitable for the latter group. Z l000
500
In addition, as shown in the figure below, 55% of high- 0
burden households require more than $400 in assistance 0 Soo 1000 1500 z000 2500 3000
to be brought under the high-burden threshold. These Excess burden over Threshold($)
customers would likely benefit from "program stacking",
Figure 6.Distribution of Avista's high-burden customers'excess burden
i.e. being served by a combination of programs optimized over the 6%/3%threshold.
to their need and the condition of their home.
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Appendix N
2.4 ENERGY BURDEN PORTFOLIO EFFECTIVENESS
Washington State's Clean Energy Transformation Act customers through energy assistance programs.
(CETA) has set concrete goals for energy assistance The ratio between energy assistance funding and
funding by electric utilities. These goals are expressed as energy assistance need is the funding ratio.
a percent of energy assistance need. Energy assistance
need can fluctuate based on several factors:
• Avoided burden is the actual dollar reduction in
customer energy bills resulting from energy
• Household energy use and efficiency assistance programs. This is usually lower than the
• Household income levels and, by extension, total energy assistance funding due to overhead
unemployment rates expenses or non-cost-effective conservation
• Weather, especially the severity of cold winter measures. Efficiencies in program delivery and
weather improvements in conservation program processes
can help increase the avoided burden. The ratio
As shown in Figure 8, there are four program-related between avoided burden and energy assistance
metrics that translate energy assistance program funding funding is the operational effectiveness.
into actual avoided need.
• Avoided need is the reduction in customer energy
• Energy assistance need is the total dollar amount bills specifically for high-burden customers. This
required to bring all customer energy bills under a number is usually lower than avoided burden for
6% electric heat/3% gas heat energy burden programs that are not effective at reaching high-
threshold
burden customers. Avoided need and avoided
• Energy assistance funding is the total dollar burden are close to each other in well-targeted
amount that is made available to low-income programs. The ratio between the avoided burden
and avoided need is the targeting effectiveness.
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Appendix N
Energy Assistance Need
Total energy bills over 6 i
threshold
Gap between need and
program funding p g
Overhead + inefficiencies in
Energy Assistance Funding
Total funding earmarked for program delivery
assistance programs 6�,}---- --------------- Bill savings
below 6%
Avoided Burden energy burden threshold
Lifetime bill savings for
all program participants _
Avoided Need
Bill savings for
high-burden participants
above 6%threshold
Figure 7.Energy assistance program effectiveness metrics
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Appendix N
Effective energy assistance programs ensure that the • So overall, the energy assistance portfolio is
difference between avoided need and energy assistance reducing the energy assistance need by
need is as small as possible. For the 2019-20 program approximately 22%.
years (Figure 9), Avista's energy assistance portfolio
metrics were::
• Funding levels appear to be generally sufficient
at this time. If energy burden reduction were to be
• 72%funding ratio: Energy assistance need of pursued solely through increased funding, the
$25M and energy assistance funding of$18M. assistance budget would have to be increased
threefold to meet CETA's 2030 requirements and
• 75%operational effectiveness: 25% of energy fivefold to completely eliminate the energy
assistance funding was used for overhead or the assistance need. Moreover, Avista's partner
installation of non-cost-effective measures. The agencies are definitely not equipped to distribute
portfolio reduced the energy bills for that level of funding. Aside from standard annual
approximately 25,000 households by$500 on budget adjustments or new budgets for pilots,we
average. do not recommend significant budget changes in
• 39%targeting effectiveness: Primarily because the near term, however,we recommend that the
some of the programs are not optimized for allocation of funds among programs be assessed
targeting high-burden customers (i.e. 61% of through an energy burden potential forecast to
avoided burden was applied to customers without a ensure an optimal mix of short-term and long-
high energy burden). The portfolio reduced the term energy burden reduction.
energy bills for 8,500 high-burden households by • The most effective means to reduce Avista's
$500 on average. For 4,000 of these households, the customer energy burden over the next 5-10 years is
assistance was sufficient to bring them below the to focus on better targeting of high-burden
high-burden threshold. households through the existing programs.
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Appendix N
Overall
Effectiveness
100%
75%
50%
2ZT
25%
Funding 72% o%d 39% Targeting
Ratio - Effectiveness
U
Operational
Effectiveness
Figure S.Performance metrics for Avista's energy assistance portfolio.
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Appendix N
➢ Avista's standard residential program (prescriptive
2.5 ADDITIONAL CONTEXT
measures and system conversions) has an
approximate annual budget of$9M. Of all
➢ The top three measures in Avista's 2022-2045 °
participants in this program, approximately 15/0
Conservation Potential Assessment are: fall under 200% of the Federal Poverty Limit and
o Smart thermostats half of those (approximately 8% of all participants)
o Ductless mini-split heat pumps
would be considered "high-burden". Low-income
o Home energy management systems o Windows and high-burden customers are obviously under-
represented in this program, but it is still
o Water heaters
contributing significantly to energy burden
These measures account for almost 40% of reduction.
Avista's residential potential but are highly
inaccessible to low-income high-burden
customers because of technical barriers or
without incentives that cover 100% of cost.
➢ Aside from Avista's income-eligible conservation
programs, the Multifamily Direct Install program
will also be considered as part of Avista's energy
assistance portfolio in the next phase of this
assessment as it serves predominantly low-income
renters (approximately 65-77% of program
participants fall under 200% FPL).
ENERGY BURDEN ASSESSMENT empower dataworks ENERGY BURDEN REDUCTION STRATEGY• 26

� hNIENERGY BURDEN
REDUCTION STRA EGY
empu' wei dataworks
3fliW

Appendix N
to fit W
burden 2.1 POTENTIAL ACTIONS (iii) Avis a'slcurrent robust proygam m x and l(iii)'best
practices gleaned from conversations with peer utilities.
The next 5-10 years will be a period of diminishing
conservation opportunities in the residential sector. At The actions fall in three categories:
the same time, equity requirements in CETA and Avista's i. Research/Planning: Actions needed to monitor and
BCP reinforce the need to prioritize energy burden report energy burden reductions, and set realistic targets
reduction in high-burden households. To meet these
challenges, Avista needs to pursue a holistic strategy that ii. Programs: Actions related to tweaking current
combines best practices in program marketing and programs, or piloting new programs.
delivery, combined with a full portfolio of interconnected
program offerings. iii. Funding: Actions related to funding allocations.
Avista already has an impressive suite of energy The following parameters are given for each action:
efficiency and bill assistance program offerings that are . Readiness level: Has this action been widely
well-designed and well-funded. Avista has also piloted or deployed/researched in other jurisdictions?
implemented numerous initiatives that are considered
best practices. Empower Dataworks considers Avista's • Budget: Expected budget range (outside of Avista
energy assistance program portfolio to be a gold staff time)
standard, especially when it comes to funding levels and
program design.
• Avista staff time: Time needed for project
management or implementation
What comes next is the need to re-orient some of the
programs to be able to achieve better energy burden • Energy burden impact: The relative overall impact to
reductions for high-burden customers. Avista's customer energy burden. The actual impact
will depend on the magnitude of investment in each
To achieve this goal, we are presenting the following list action and its specific design.
of actions for Avista's consideration - these were selected
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Appendix N
POTENTIAL ACTION READINESS LEVEL BUDGET AVISTA STAFF TIME ENERGY BURDEN
IMPACT
Adopt energy burden reduction as a Intermediate Foundational Action
y Y
metric for all conservation programs i + (No direct impact)
Implement an energy equity monitoring $ $ y y Foundational Action
Intermediate
plan i (No direct impact)
Use Energy Burden in Program Design Proven
Implement a targeted marketing and Q Q
Proven y y
outreach strate�v 11 11
Deploy a One Portfolio Model for energy y y
assistance programs '� Intermediate
Community and small business energy y
Proven n
efficient,, i�gh-burden neighborhoods Q
Landlord-targeted energy efficiency 0 Pilot $ $ y Y
Energy Ambassador program • Pilot � 411 y Y y
Democratizing the smart home Pilot $ $ $ y y
Income self-certification Intermediate $ Y y
Pre-weatherization incentives Proven y
Review regional and program-level Y Q
Proven n
funding allocations
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Appendix N
Back to list of actions
ADOPT ENERGY BURDEN REDUCTION AS A Target Customer Segment: All program participants
METRIC FOR ALL CONSERVATION PROGRAMS Budget: Internal Staff Only
Type. Research/Planning Required Avista Staff time: Moderate (Conservation staff
time to make internal business case)
Readiness level: Intermediate
Main Goal: Measure program progress towards energy
equity and affordability
Description: As a first step, the Avista Conservation team will need to
get internal buy-in to adopt energy burden-related metrics
"You cannot manage what you cannot measure" as formal program metrics. This includes developing the
If Avista's programs are meant to prioritize high-burden internal business case and verifying the feasibility of doing
customers, then they need to excel at reaching high- this through data sharing, technical infrastructure and
burden customers and identifying high-burden customers reporting tools. Ideally, this would happen in coordination
among program participants. This is not an with the Energy Assistance team so that energy burden
insurmountable task, particularly for the low-income can be used for reporting across Avista's energy assistance
energy efficiency program,where incomes are already portfolio.
collected as part of the intake process.
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Appendix N
Back to list of actions
IMPLEMENT AN ENERGY EQUITY MONITORING Target Customer Segment: All program participants
PLANBudget: Moderate (Planning studies and IT system setup)
Type: Research/Planning Required Avista Staff time: Moderate (Conservation staff
for project management, IT staff for 6-9 months to set up
Readiness level: Intermediate internal systems)
Main Goal: Evaluate the reduction in energy burden and
access to programs for high-burden customers. Include
metrics in annual conservation reports
Description: Subtasks:
Following the adoption of energy burden as an internal ➢ Transfer income data from CAAs for all program
program metric, the next step would be to build the applicants and program participants
infrastructure required to facilitate energy burden
reporting. One potential option is for Avista to adopt the ➢ Set up internal database systems to facilitate energy
Energy Equity Monitoring Plan that was prepared as part burden calculations
of this Energy Burden Assessment. The plan details the ➢ Develop 2-3 key metrics by program in order to assess
methodology and types of studies/analysis that would be energy burden reduction performance
required on an ongoing basis, in order to plan, evaluate
and design equitable programs. ➢ Integrate these metrics in standard program reporting
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Appendix N
Back to list of actions
USE ENERGY BURDEN IN PROGRAM DESIGN Target Customer Segment: Program participants
Type Research/Planning
Budget: Internal Staff Only
Readiness level: Proven Required Avista Staff time: Minimal (Conservation staffl
Main Goad Align program rules with energy burden Energy Burden Impact High (primarily improves the
reduction targeting effectiveness of programs by directing more
funding/offerings to high-burden customers)
Description: offerings that are not currently provided through the
federal Weatherization Assistance Program or Avista's
Avista has already piloted a Percentage of Income Low Income Conservation program. These would include
Payment Plan (called the Income Based Payment smart thermostats,washer/dryers,water heaters and
Program). These programs are extremely effective at potentially HVAC tuneups, other appliances or smart
reducing energy burden because they specifically target devices. Or a small portion (20-40%) of the incentive cost
high-burden households. for low-burden customers could be shifted to zero-interest
A natural extension of this idea for conservation programs on-bill loans to free up and prioritize funds for high-
is to use energy burden either as a hard qualifying burden customers.
criterion or as a more gradual adjustment factor in a tiered Another way to use energy burden within the current
incentive model. For example, customers who fall energy efficiency programs is to add high-burden
between 0-50% of the Federal Poverty Limit can be allowed applicants to a priority queue that bypasses the standard
to access higher incentives (up to 100%) for some of the wait times for weatherization and audits (which can be up
measures in Avista's standard residential energy efficiency to 2 years).
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Appendix N
Back to list of actions
IMPLEMENT A TARGETED MARKETING AND Target Customer Segment: High-burden customers
OUTREACH STRATEGY Budget: $40-60k (strategy+ marketing expenses)
Type; Programs - Operations Required Avista Staff time: Moderate (Communications +
Energy Assistance + Conservation staff)
Readiness level: Proven
Energy Burden Impac High (primarily improves the
Main Goal: Improve participation of high-burden targeting effectiveness of programs, so more high burden
customers in current programs
customers participate)
Description: ➢ Initiate a program of energy bill clinics in high-burden
neighborhoods to raise awareness about energy
Program targeting is a catch-all term and it could manifest efficiency and to provide an educational opportunity to
as any of the following: customers about their bills.
➢ Use a consistent, repeatable process for creating ➢ Build relationships with large property managers,
targeted marketing campaigns that are culturally and trade allies and community organizations that serve
demographically relevant. One example is Empower high-burden neighborhoods.
Dataworks Targeting Playbook, but there are other
frameworks that accomplish the same goal. ➢ Test the Whole Neighborhood Approach to energy
efficiency/weatherization, especially in concentrated
➢ Identify high-burden customers and neighborhoods pockets of energy burden in more rural areas.
using data from this Energy Burden Assessment and
(https://www.osti.gov/biblio/1126788)
use these customer lists for targeted informational
campaigns.
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Appendix N
Back to list of actions
DEPLOY A ONE PORTFOLIO MODEL FOR ENERGY Target Customer Segment: Program participants
ASSISTANCE PROGRAMS Budget: Depends on the specific subtasks, but likely on
the moderate to higher end.
Type: Program - Operations
Required Avista Staff Time- High (IT + Communications +
Readiness level: Intermediate Energy Assistance + Conservation staff+ Community
Main Goal,- Integrate all of Avista's energy assistance Action Agencies + Program Implementation Contractors)
programs into one optimized and customizable customer Energy Burden Impac High (Through stacking multiple
offering programs to bring energy burden for all participants below
the 6%/3% threshold)
Description: This coordination might include:
➢ A single, unified intake and application process for all
Given the energy burden characteristics of Avista's high- low-income programs.
burden customers, it is unlikely that participation in one
➢ A unified customer triage system to serve customers an
isolated program at a time would completely eliminate
optimized program mix based on their energy burden
high energy burden for the majority of customers. Instead,
and energy efficiency potential.
most customers would benefit from stacking the energy
burden reduction from multiple relevant programs. This ➢ An energy education/conservation component in all
will necessarily involve closer integration and coordination energy assistance programs.
between the energy assistance and conservation teams, the ➢ Tiered incentives that encourage cross-program
community action agencies and program implementation participation.
contractors, so that customers receive the assistance that ➢ Formal processes for cross-referrals between programs,
is most impactful and cost-effective. customer follow-ups, tracking customer referrals and
cross-program conversion rates.
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Appendix N
Back to list of actions
COMMUNITY AND SMALL BUSINESS ENERGY Target Customer Segment: Businesses and community
EFFICIENCY IN HIGH-BURDEN NEIGHBORHOODS buildings in high-burden neighborhoods
Budget: Small increase in CEEP budget
Type: Program - Operations
Required Avista Staff Time: Minimal (Expansion of
Readiness level: Proven current program)
Main Goal: Build rapport with trusted businesses and Energy Burden Impac Minimal (Doesn't directly reduce
institutions in high-burden communities energy burden but builds trust with potential participants)
Description:
Avista is successfully running a Business Partner program
that targets outreach at rural small businesses and
provides free energy assessments. This action would be a
minor modification to the program to include community
organizations (especially religious facilities and
community centers)within the target customer segment.
These organizations are great advocates for energy
efficiency and can help Avista bridge the trust barrier with
customers. In addition,we suggest that Avista expand
outreach from just rural areas to any high-burden
neighborhood, including within Spokane.
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Appendix N
Back to list of actions
LANDLORD-TARGETED ENERGY EFFICIENCY Target Customer Segment- Landlords and property
managers of single family and small multifamily rentals
Type, Program
Budgie, High. Can use staff if done as separate initiative - or
Readiness level: Pilot integrated in Multifamily Direct Install program
Main Goal• Directly reach the energy efficiency decision Required Avista Staff Tim Moderate-High (Conservation
makers in rental housing staff to design and implement program)
Energy Burden Impact: High (Reduces renter energy burden)
Description: This is an extremely opportune moment to engage with
landlords by offering them either low-cost on-bill loans or
Since most of Avista's customer energy assistance need incentives for efficient replacements (provided they agree to
is among renters, conservation programs that prioritize an energy audit, for example).
high-burden customers cannot avoid the split incentive
question. A pilot program could test the potential of Aside from financial incentives, targeted communication to
offering energy efficiency incentives (with increased landlords should always highlight their specific benefits of
incentives up to 90-100% of measure cost), to landlords in energy efficiency (not energy bill reductions). These include
high-burden areas. This would ensure that the homes lower tenant turnover rate and increased property values.
that are likely to house high-burden customers are made Outstanding questions that should be handled during the
more efficient. program design, include disclosure of on-bill loans or the
potential for rent increases after participation in an energy
One of the biggest challenges for smaller "mom and efficiency program.
pop" landlords is unexpected expenses from having to
replace broken appliances or HVAC equipment.
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Appendix N
Back to list of actions
ENERGY AMBASSADOR PROGRAM Target Customer Segment: 30-50 Energy Ambassadors +
their communities
Type, Program
Budget. Moderate (Energy ambassador training/stipends)
Readiness level: Pilot
Required Avista Staff Timi High (Conservation staff to
Main Goal Train community members in energy audits design and implement program)
and the program application process
Energy Burden Impact: High for Energy Ambassadors,
Moderate for their community members who enroll in
programs.
Description: As an extension to the referral portion of the program, the
Energy Ambassadors could be trained to perform quick
A primary barrier to energy efficiency program walkthrough energy audits and submit a simple audit form to
participation by low-income customers is lack of trust. Avista. These "citizen energy auditors"would be empowered
In many communities around Washington, there are through performance-based income while leveraging their
regular customers who assist others in their
trusted connections to encourage participation among their
communities explain the benefits. The Energy neighbors and families. The workforce development
Ambassador program would formalize this process by component would also serve Avista in the long run by
paying a stipend to the "Energy Ambassadors" (usually reducing friction and expense in the intake/audit stage of
low-income high-burden customers themselves) based energy efficiency programs.
on how many applications they bring in to the
conservation programs.
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Appendix N
Back to list of actions
DEMOCRATIZING THE SMART HOME Target Customer Segment- High burden customers
interested in smart devices
Type, Program
Budge. -$500-800/participant
Readiness level: Pilot
Required Avista Staff Tim( Moderate (Conservation staff to
Main Goal Increase access of high-burden customers project manage)
to smart devices. Evaluate savings for future smart
device programs. Set up high-burden customers for Energy Burden Impact: Moderate (expected savings of 800-
future participation in demand response programs.
1000 kWh/year)
Description: Avista can potentially pilot approaches to democratize access .
to smart devices through a smart device pilot to deploy smart
Avista's conservation potential includes smart devices in low-income homes. This would include hardware,
thermostats and Home Energy Management Systems as software, a financing model and a marketing plan to sell the
two of the top 3 measures in the next biennial cycle. benefits of these devices to landlords and tenants.
Smart devices offer convenience to customers and they
usually deliver a fair amount of energy savings when The packaged solution should include line voltage
used correctly. However, low-income households have thermostats, plug load controllers, humidity and leak
been unable to access them, because of a lack of internet detectors, and indoor temperature sensors connected to a 4G
connectivity or their renter status or technical cellular hub. The data from the smart devices would be used
incompatibility(most low-income homes use zonal heat). to develop personalized home energy efficiency diagnostic
In addition, low income customers may not be able to reports that offer personalized behavioral energy-savings tips
afford the purchase cost of these smart devices. and home upgrade recommendations.
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Appendix N
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INCOME SELF-CERTIFICATION Target Customer Segment- High burden customers who are
intimidated by documentation requirements
Type: Pilot
Budget. Internal Staff Only
Readiness level: Intermediate
Required Avista Staff Timi Moderate (mainly Conservation
Main Goal Reduce the paperwork required for staff time for QA/QC or automated processes by IT)
customers to enroll and reduce the administrative
burden of the Community Action Agencies Enerev Burden Impact: Low (Encourages participation by
high burden customers)
Description: documentation to the Community Action Agency before the .
Income self-certification has proven to be an effective application goes through.
way to enroll customers in programs by reducing
administrative hurdles. This potential action would test 2. If more than 10% of customers fail income verification or
a sampling QA/QC approach,where income self- do not go through the process, increase the sampling rate in
certification is accepted from all applicants to one of the 5% increments
conservation programs or pilots, with a small fraction of 3. For measures costing over $50043000, use a 25% sampling
customers sampled for full income verification. rate to do internal data checks (using home values or income
A proposed protocol for QA/QC is presented below: data) and forward another 5% to the relevant Community
Action Agency for manual income verification.
1. For measures costing less than $500, sample 4-5% of
program applicants at random. If their neighborhoods 4. Avista can also pilot an opt-out program design,where
and home values do not align with expectations for a customers are automatically enrolled based on individual
low-income household, request that they provide income demographic data or by enrolling entire high-burden
neighborhoods,with a similar audit protocol.
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Appendix N
Back to list of actions
PRE-WEATHERIZATION INCENTIVES Target Customer Segment- High burden weatherization
participants with deferral issues in home
Type, Funding
Budget. Internal Staff Only
Readiness level: Proven
Required Avista Staff Tim( Low (Conservation staff to set
Main Goad Assist customers who intend to participate up process for CAAs)
in weatherization but whose applications were deferred
for other issues Enerev Burden Impact: Low (Removes a key barrier to
participation for many high burden customers)
Description:
This action involves allocating a portion of the low-
income energy efficiency program budget as grants
towards fixing issues in customer homes that would lead
to deferral of weatherization (e.g. structural and
electrical issues, asbestos). Some experiments with
similar initiatives in Massachusetts have shown promise
in making sure that interested customers are still served
by programs after these issues are mitigated. In Avista's
case, it is recommended that only high-burden
customers (or customers who fall under 50% of the
Federal Poverty Limit) are given access to this pool of
funds.
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Back to list of actions
REVIEW REGIONAL AND PROGRAM-LEVEL Target Customer Segment: Program participants
FUNDING ALLOCATIONS Budget Internal Staff Only
Type: Funding Required Avista Staff Tim, Low
Readiness level: Proven Energy Burden Impact: Low
Main Goal- Ensure that budgets are sufficient to meet
current program needs across different community
action agencies. Ensure that the current program mix
will meet long term energy burden goals.
Description:
This energy burden assessment has found no need for
additional program funding at this time, aside from
potential new pilot budgets. However, it would be useful
to regularly review budget utilization across the different
community action agencies and identify any that might
need additional funds or a funding reallocation.
Optionally, if Avista undertakes an energy burden
potential study, it will be possible to review the allocation
of funding among programs and to judge whether the
current allocation serves Avista's long-term energy
burden reduction goals under CETA.
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2.2 NEXT STEPS
The actions proposed in this strategy document have different readiness levels and
will require different levels of effort. Realistically, it is unlikely that everything can
be tested in the coming biennium. Therefore, we suggest that Avista consider
these actions and then prioritize the most impactful or compelling ones for actual
implementation.
Our recommended workflow for implementing these actions is:
In the next 12-18 months (by the end of Q4 2022),we would recommend that
Avista complete the two foundational planning actions (internal adoption of
energy burden metrics and the energy equity monitoring plan). Another low
hanging fruit that can be started in tandem is to begin identifying high-burden
customers and neighborhoods and implementing a targeted marketing and
outreach strategy. Strategic initiatives like the One Portfolio Model should be
assessed for feasibility before implementation and this will take some time.
Finally, depending on the Conservation and Energy Assistance team capacity,
it is likely that between 1-3 pilot ideas can be tested annually. The activities
that show potential can then be integrated into Avista's programs.
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Appendix N
2.3 ADDITIONAL RESOURCES
POTENTIAL ACTION RESOURCES
Adopt energy burden reduction as Roger Colton,January 28,2020. Presentation can be requested from WA Dept. of Commerce.
a metric for all conservation Energy Trust of Oregon, Diversity,Equity and Inclusion Operations Plan.
programs https://energytrust.org/about/explore-energy-trust/diversity-equity-and-inclusion/
Implement an energy equity
Refer to Energy Equity Monitoring Plan attachment in this energy burden assessment.
monitoring plan
Implement a targeted marketing Empower Dataworks (hellogempowerdataworks.com)can share a Targeting Playbook and
and outreach strategy request a utility presenter to share their experiences.
Deploy a One Portfolio Model for D. Hernandez and S. Bird, Energy Burden and the Need for Integrated Low-Income Housing
energy assistance programs and Energy Policy, https://www.ncbi.nlm.nih.gov/pmc/articles/PMC4819257/
Landlord-targeted energy Energy Trust of Oregon enhanced incentives for landlords:
efficiency https://energytrust.org/incentives/landlords-property-managers-single-family-homes/
Energy Ambassador program Can borrow some design elements from HVAC contractor training programs:
https://www.aceee.or /fg iles/proceedings/2012/data/papers/0193-000210.pdf
Democratizing the smart home Empower Dataworks (hello(&empowerdataworks.com)can share a concept paper upon request.
Low-income/hard-to-reach energy efficiency programs in Texas use self-certification for income
Income self-certification qualification-as an example:
http://www.swepcogridsmart.com/texas/downloads/HTR%20Program%20Manual.pdf
Pre-weatherization incentives Mass Save's Barrier incentive: https://www.masssave.com/save/barrier-incentive
ENERGY BURDEN ASSESSMENT empower dataworks ENERGY BURDEN REDUCTION STRATEGY• 43

empchwer dataworks
www.empowerdataworks.com

Appendix N
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