20210331Avista Electric IRP Appendices.pdf

2021 Electric
Integrated Resource Plan
Appendices
2021 Electric IRP Appendices
Table of Contents

Appendix A – 2021 IRP Technical Advisory Committee Presentations & Meeting Notes
Technical Advisory Committee Meeting 1 Presentations (Page 2)
Technical Advisory Committee Meeting 1 Minutes (Page 84)
Technical Advisory Committee Meeting 2 (Page 97)
Technical Advisory Committee Meeting 2 Minutes (Page 200)
Technical Advisory Committee Meeting 2.5 (Page 215)
Technical Advisory Committee Meeting 2.5 Minutes (Page 261)
Technical Advisory Committee Meeting 3 (Page 270)
Technical Advisory Committee Meeting 3 Minutes (Page 421)
Technical Advisory Committee Meeting 4 (Page 432)
Technical Advisory Committee Meeting 4 Minutes (Page 517)
Technical Advisory Committee Meeting 4.5 (Page 523)
Technical Advisory Committee Meeting 4.5 Minutes (Page 561)
Technical Advisory Committee Meeting 5 (Page 565)
Technical Advisory Committee Meeting 5 Minutes (Page 637)
Public Participation Meeting 6 (Page 645)

Appendix B – 2021 Electric IRP Work Plan (Page 683)

Appendix C – Public Participation Comments (Page 689)

Appendix D – Confidential Historical Generation Operation Data (Page 833)

Appendix E – AEG Conservation & Demand Response Potential Assessment (Page
835)

Appendix F – Avoided Cost Calculations (Page 979)

Appendix G – Transmission 10- year plan (2020) and 2019-2020 Avista System
Assessment (Page 985)

Appendix H – New Resource Table for Transmission (Page 1065)

Appendix I – Publicly Available Inputs and Models (Page 1067)

Appendix J – Confidential Inputs and Models (Page 1091)

Appendix K – Load Forecast Supplement (Page 1095)

2021 Electric Integrated
Resource Plan
Appendix A – 2021 Technical
Advisory Committee
Presentations and Meeting
Minutes
Avista Corp.2021 Electric IRP Appendices 1
2021 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 1 Agenda
Thursday, June 18, 2020 Virtual Meeting
Topic Time Staff
Introductions 9:00
TAC Expectations and Process Overview 9:05 Lyons
2020 IRP Acknowledgement 9:45 Lyons
Break 10:15
CETA Rulemaking Update 10:30 Bonfield
Modeling Process Overview 11:00 Gall
Lunch 12:00
Generation Options 1:00 Hermanson
Break 2:00
Highly Impacted Communities Discussion 2:15 Gall
Adjourn 3:30
Avista Corp.2021 Electric IRP Appendices 2
2021 Electric IRP
TAC Expectations and Process Overview
John Lyons, Ph.D.
First Technical Advisory Committee Meeting
June 18, 2020
Avista Corp.2021 Electric IRP Appendices 3
Updated Meeting Guidelines
•IRP team is working remotely, still available by email and
phone for questions and comments
•Some processes are taking longer remotely
•Adding stakeholder feedback form to the IRP website –
posted with responses
•Researching best way to share other IRP data
•Virtual IRP meetings on Skype until back in the office
and able to hold large group meetings
•TAC presentations and notes will still be posted on IRP
page
2 Avista Corp.2021 Electric IRP Appendices 4
Virtual TAC Meeting Reminders
•Please mute mics unless speaking or asking a question
•Use the Skype chat box to write out or let us know you
have a question or comment
•Respect the pause
•Please try not to speak over the presenter or a speaker
who is voicing a question or thought
•Remember to state your name before commenting for
the note taker
•This is a public advisory meeting –presentations and
comments will be recorded and documented
3 Avista Corp.2021 Electric IRP Appendices 5
Integrated Resource Planning
The Integrated Resource Plan (IRP):
•Required by Idaho and Washington* every other year
–Covering timing of 2020 and 2021 IRPs in next presentation
•Guides resource strategy over the next twenty + years
•Current and projected load & resource position
•Resource strategies under different future policies
–Generation resource choices
–Conservation / demand response
–Transmission and distribution integration
–Avoided costs
•Market and portfolio scenarios for uncertain future
events and issues
4 Avista Corp.2021 Electric IRP Appendices 6
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
–Help with soliciting new members
•Open forum while balancing need to get through all of the topics
•Welcome requests for studies or different assumptions.
–Time or resources may limit the number or type of studies
–Earlier study requests allow us to be more accommodating
–August 1, 2020 is the study request deadline
•Planning team is available by email or phone for questions or
comments between the TAC meetings
5 Avista Corp.2021 Electric IRP Appendices 7
2021 Electric IRP TAC Schedule
•TAC 1: Thursday, June 18, 2020
•TAC 2: Thursday, August 6, 2020 (Joint with Natural Gas TAC)
•TAC 3: Tuesday, September 29, 2020
•TAC 4: Tuesday, November 17, 2020
•TAC 5: Thursday, January 21, 2021
•Public Outreach Meeting: February 2021
•TAC agendas, presentations and meeting minutes available at:
https://myavista.com/about-us/integrated-resource-planning
6 Avista Corp.2021 Electric IRP Appendices 8
2021 IRP Key Dates – Work Plan
•Identify Avista’s supply resource options –May 2020
•Finalize natural gas price forecast –June 2020
•Finalize demand response options –July 2020
•Finalize energy efficiency options –July 2020
•Update and finalize energy and peak forecast –July 2020
•Finalize electric price forecast –August 2020
•Transmission and distribution studies due –August 2020
•Determine portfolio and market future studies –August 2020
•Due date for TAC study requests –August 1, 2020
•Finalize PRiSM model assumptions –September 2020
•Simulate market scenarios in Aurora –September 2020
•Portfolio analysis and reliability analysis –October 2020
•Present portfolio analysis to TAC –November 2020
7 Avista Corp.2021 Electric IRP Appendices 9
2021 IRP Public Data Release Schedule
•Supply Side Resource Options –June 2020
•Conservation Potential Study Data –July 2020
•Demand Response Potential Study Data –July 2020
•Peak & energy Load Forecast –July 2020
•Wholesale Natural Gas Price Forecast –August 2020
•Wholesale Electric Price Forecast –September 2020
•Transmission Interconnect Costs –September 2020
•Existing Resource Data –September 2020
•Annual Capacity Needs Assessment –November 2020
8 Avista Corp.2021 Electric IRP Appendices 10
2021 IRP Key Document Dates
•Filed 2021 IRP Work Plan April 1, 2020
•Internal IRP draft released at Avista on December 4, 2020
•External draft released to the TAC on January 4, 2021
•Comments and edits from TAC due on March 1, 2021
•Final editing and printing –March 2020
•Final IRP submission to Commissions and TAC on April 1,
2021
9 Avista Corp.2021 Electric IRP Appendices 11
Today’s TAC Agenda
9:00 –Introductions
9:05 –TAC Expectations and Process Overview, Lyons
9:45 –IRP Acknowledgement, Lyons
10:15 –Break
10:30 –CETA Rulemaking Update, Bonfield
11:00 –Modeling Process Overview, Gall
Noon –Lunch
1:00 –Generation Options, Hermanson
2:00 –Break
2:15 –Highly Impacted Communities Discussion, Gall
3:30 –Adjourn
10 Avista Corp.2021 Electric IRP Appendices 12
2020 Electric IRP
Acknowledgement Update
John Lyons, Ph.D.
First Technical Advisory Committee Meeting
June 18, 2020
Avista Corp.2021 Electric IRP Appendices 13
Normal Acknowledgement Process
•Avista’s electric IRP previously submitted to
Idaho and Washington Commissions every other
August in odd years
•Commissions set periods for public comments
and meetings
•Acknowledgements issued detailing IRP
outcomes, comments and expectations for the
next IRP
•Normally, we provide details about the
acknowledgments in this meeting
2 Avista Corp.2021 Electric IRP Appendices 14
How The IRP Changed
•Expectations and passage of the Clean Energy
Transformation Act (CETA) in 2019 led to six
month IRP extensions
–February 28, 2020 in Idaho in AVU-E-19-01 Order
No. 34312
–Washington further extended until April 1, 2021
–Two IRPs in two years
3 Avista Corp.2021 Electric IRP Appendices 15
Idaho
•AVU-E-19-01 (https://puc.idaho.gov/case/Details/3633)
•Requests from the Mayor of Sandpoint, Idaho, Idaho
Forest Group, Idaho Conservation League and
Embodied Virtue for the IPUC to hold a public hearing in
North Idaho
•IPUC set a deadline of August 19, 2020 for public
comments about the IRP with Avista replies due
September 2, 2020
•Will update the TAC on future comments and
acknowledgement
•Ongoing discussions with Commission Staff and ICL
concerning several aspects about modeling, Colstrip and
the impact of CETA on Idaho customers
4 Avista Corp.2021 Electric IRP Appendices 16
Washington
•Submitted the 2020 IRP to the Washington UTC
•Washington Commission temporarily suspended issuing IRP
acknowledgement letters in UE-180738 Order 02 until
December 31, 2020
•Progress filed report filed on October 25, 2019 to
accommodate CETA rulemaking
–Commission cannot legally acknowledge an IRP without meeting
certain CETA guidelines which still need to have rulemaking
completed
•Next draft electric IRP must be submitted by January 4, 2021
and final 2021 electric IRP must be submitted by April 1,
2021
•No specific requirements or expectations from an
acknowledgment letter from the 2020 IRP
5 Avista Corp.2021 Electric IRP Appendices 17
Washington
•2021 IRP expectations are going to focus on the results of
CETA rulemaking
Some Washington UTC requests on the work plan include:
•Provide opportunity for stakeholder input on the CPA before
finalizing the options
•How equity issues required under CETA will be incorporated in the
IRP (TAC 1 and TAC 2)
•Extending participation beyond the TAC through some form of public
outreach at a higher level before the end of the IRP process
(February 2021)
•Concerns over draft CEIP being included in the IRP
•Provide a general outline of when Avista will provide data or files for
stakeholder review and comment deadlines (first presentation today)
6 Avista Corp.2021 Electric IRP Appendices 18
Clean Energy Transformation Act (CETA)
Overview and Implementation Status
Shawn Bonfield, Sr. Manager Regulatory Policy & Strategy
First Technical Advisory Committee Meeting
June 18, 2020
DRAFT
Avista Corp.2021 Electric IRP Appendices 19
CETA: A Brief Overview
•Senate Bill 5116 –passed by legislature in 2019
•Applies to all electric utilities in WA and sets specific milestones to
reach required 100% clean electric supply
•By 2025 –eliminate coal-fired resources from serving WA customers
•By 2030 –electric supply must be greenhouse gas neutral,
•By 2045 –electric supply must be 100% renewable or be generated
from zero-carbon resources
Source: WA Department of Commerce2Avista Corp.2021 Electric IRP Appendices 20
CETA: Additional Details
Utilities must:
–Ensure the equitable distribution of energy and nonenergy
benefits and reduction of burdens to vulnerable populations and
highly impacted communities
–Ensure long-term and short-term public health and
environmental benefits and reduction of costs and risks
–Ensure energy security and resiliency
–Make progress toward and meet the standards of the law:
•While maintaining and protecting the safety, reliable operation, and
balancing of the electric system
•At the lowest reasonable cost
3 Avista Corp.2021 Electric IRP Appendices 21
Source: WA
Department of
Commerce
4 Avista Corp.2021 Electric IRP Appendices 22
Source: WA Department of Commerce
5 Avista Corp.2021 Electric IRP Appendices 23
UTC CETA Implementation Plan
UE-190485 (Closed)
•Phase 0 –overall implementation plan
–Process timeline and scope of issues
•Phase I -August 2019 to January 1, 2021
–Elements that must be complete by January 1, 2021 as required by
Section 10 of SB 5116
–Publish the social cost of carbon on UTC’s website by September 15,
2019
–Initiate dockets for various rulemakings relating to CETA implementation
•Phase II –January 1, 2021 to June 30, 2022
–Rulemakings with deadlines after January 1, 2021
–Amend IRP rules to incorporate Cumulative Impact Analysis
–Carbon and Electricity Markets Rulemaking
6 Avista Corp.2021 Electric IRP Appendices 24
Social Cost of Carbon
U-190730 (Closed)
•New section added to chapter 80.28 RCW, outlining cost
of greenhouse gas emissions resulting from the
generation of electricity and use of natural gas, the UTC
must adjust the social cost of carbon to reflect the effect of
inflation.
•Social Cost of Carbon published on UTC website in
September 2019:
–https://www.utc.wa.gov/regulatedIndustries/utilities/Pages/SocialC
ostofCarbon.aspx
7 Avista Corp.2021 Electric IRP Appendices 25
Energy Independence Act (EIA)
Rulemaking – UE-190652
•E2SSB 5116: Amending WAC 480-109, Energy Independence Act
(EIA) rules
a.Streamline E2SSB 5116 with EIA rules. (§10(3))
b.Discuss equitable distribution of benefits.
c.Discuss low-income definition, if needed. (§2(25))
d.Discuss energy assistance need definition, if needed. (§2(16))
e.Consider incorporating low-income energy efficiency target.
f.Incorporate updates to hydro eligibility and tracking. (§§28 and 29)
Status: Written comments due on draft rules July 6th. Rule adoption
hearing set for July 28th.
8 Avista Corp.2021 Electric IRP Appendices 26
Clean Energy Implementation Plan (CEIP)
Rulemaking UE-191023
•E2SSB 5116: New Chapter, Clean Energy Implementation Plans
(CEIPs)
a.Provide guidelines for Clean Energy Implementation Plans. (§6)
b.Discuss equitable distribution of benefits. (§4(8))
c.Develop incremental cost methodology at the beginning of the
rulemaking. (§6)
d.Address reporting and compliance, and the penalty process. (§9(1)(a))
Status: First draft of rules released May 5, 2020 with comments due June
2, 2020. Second set of draft rules to be released in July timeframe.
9 Avista Corp.2021 Electric IRP Appendices 27
Electric IRP Updates Rulemaking
UE-190698
•E2SSB 5116 and EHB 1126: Amending WAC 480-100-238, Electric Integrated
Resource Plans (IRP)
a.Update inputs to IRPs (e.g., hydro eligibility and tracking;4 resource adequacy; distributed energy resources
principles from EHB 1126; and demand response).
b.Update structure of IRPs.
c.Update public involvement process.
d.Update outputs of IRP Clean Energy Action Plans. (§14(2))
e.Incorporate the social cost of carbon into IRPs. (§14(3)(a))
f.Refine the development of avoided costs to reflect E2SSB 5116 and social cost of carbon.
g.Develop resource value test based on review of E2SSB 5116 and social cost of carbon.
h.Discuss equitable distribution of benefits. (§4(8))
i.Discuss assessment informed by cumulative impact analysis, as needed. (§14(1)(k))
j.Amend IRP rules to incorporate the Cumulative Impact Analysis complete by Department of Health
workgroup. (ch. 288, §14(11))
k.Incorporate distributed energy resources elements from EHB 1126. (ch. 205, §1)
Status: Development and preparation of draft rules ongoing.
10 Avista Corp.2021 Electric IRP Appendices 28
Purchase of Electricity (PoE) Rulemaking
UE-190837
•E2SSB 5116: Amending WAC 480-107, Resource Acquisition
(Requests for Proposals, or RFP)
a.Incorporate existing work on RFPs from Docket U-161024.
b.Ensure that the E2SSB 5116 standard is met in construction and
acquisition of property and the provision of electric service. (§5)
c.Incorporate resource adequacy considerations. (§6(2)(a)(iv))
d.Discuss equitable distribution of benefits. (§6(1)(c)(iii))
Status: Second round of draft rules issued June 1, 2020 with
comments due June 29, 2020.
11 Avista Corp.2021 Electric IRP Appendices 29
Carbon & Electricity Markets Workgroup
UE-190760
•E2SSB 5116: With the Department of Commerce, initiate
a Carbon and Electricity Markets Workgroup for regular
discussions to inform Phase II rulemaking.
•Define requirements for load met with market purchases.
(ch. 288, §13)
Status: Workgroup to hold four educational workshops
to set a base of understanding. Second workshop
scheduled for June 10, 2020. Public work sessions to
begin in Fall 2020 with rulemaking complete June 30,
2021.
12 Avista Corp.2021 Electric IRP Appendices 30
Department of Commerce Rulemakings
•Thermal Renewable Energy Credits –applies to all
utilities
•Reporting and demonstration of compliance –applies to
all utilities
•CEIP for consumer-owned utilities –ensure alignment
with UTC rules
•Cost methodology for rate impact –applies to all utilities
Rules effective January 1, 2021
13 Avista Corp.2021 Electric IRP Appendices 31
Department of Ecology Rulemakings
•Ecology is starting rulemaking for Chapter 173-444 WAC, Clean
Energy Transformation Rule to implement parts of the Clean Energy
Transformation Act assigned to Ecology. The rulemaking will:
–Establish a process to determine what types of energy transformation
projects may be eligible to meet the Clean Energy Transformation Act.
–Establish a process and requirements to develop standards,
methodologies, and procedures to evaluate energy transformation
projects.
–Provide greenhouse gas emission factors for electricity.
•Timeline
–Spring 2020 –develop and prepare rule language
–Summer 2020 –public hearing and comment
–December 2020 –adopt rule
–January 2021 –rule effective
14 Avista Corp.2021 Electric IRP Appendices 32
2021 Electric IRP
Modeling Process Overview
James Gall, IRP Manager
First Technical Advisory Committee Meeting
June 18, 2020
Avista Corp.2021 Electric IRP Appendices 33
IRP Planning Models
Aurora
PRiSM
“Reliability”
Model
PowerWorld Synergi
Load
Forecast
Resource
Options
Transmission & Distribution Models will be discussed in TAC 3
Discuss in TAC 2
Supply-side: Today
Demand Side: TAC 2
2 Avista Corp.2021 Electric IRP Appendices 34
Aurora
•Electric Market-Production Cost Model
•Developed by Energy Exemplar
•Industry standard and widely used in the Pacific Northwest
•Avista started using software for the 2003 IRP
•Simulates generation dispatch to meet load allowing for system
constraints
Inputs:
–Regional loads*
–Fuel prices*
–Fuel availability*
–Resources (availability*)
–New resources costs
–Transmission
–System Constraints
Outputs:
–Market prices
–Energy mix
–Transmission usage
–Emissions
–Power plant margins,
generation levels, fuel costs
–Avista’s variable power supply
costs
*Stochastic input
3 Avista Corp.2021 Electric IRP Appendices 35
Aurora Pricing Methodology
•Each area contains a load and
resources.
•Aurora dispatches resources to meet
the load for each hour.
•Resource dispatch is dependent on
fuel availability (wind, solar, hydro)
and economic dispatch of the
resource (fuel price).
•The model includes resource
outages for maintenance and forced
outage.
•For each location and hour, the
model estimate a wholesale electric
price using the marginal resource to
serve the load.
4 Avista Corp.2021 Electric IRP Appendices 36
Stochastic vs. Deterministic Analysis
•Deterministic analysis forecasts for a specific set of inputs.
–Easier to understand
–Works great for sensitivity analysis of specific changes
•Stochastic analysis forecasts for a range of inputs.
–Range (or distribution) of results
–Works great to understand risks of the inputs with variation
•Avista uses mean value of stochastic analysis for its Expected
Case scenario.
5 Avista Corp.2021 Electric IRP Appendices 37
Aurora Model Assumptions
•Forecast will start with the 2020 IRP
–Uses latest available database from Energy Exemplar
•Proposed database changes
–Natural gas prices (TAC 2)
–Include new resource additions and announced retirements
–Include known state/province environmental laws; including adjustments for
oversupply events
–Review inputs for load and new resources options
•EV/rooftop solar forecast
•New resources cost
–Add proprietary Avista system information
–Add stochastic distribution of regional hydro, natural gas, wind, and loads
•Avista will discuss non-confidential modeling changes in TAC 3
•All other Aurora assumptions are default values
6 Avista Corp.2021 Electric IRP Appendices 38
Aurora Run Process
•Once inputs are finalized (July 2020)
•Run Long Term “LT” study to estimate new resource additions for the
full hourly study
•Test reliability under 500 simulations of varying hydro, load, forced
outage, and wind conditions for future year (i.e. 2035)
•Update LT study to reflect any “need” for new resources and validate
regional reliability
•Run deterministic study
•Run stochastic study (500 simulations, each hour for 2022-45)
•Run scenarios
7 Avista Corp.2021 Electric IRP Appendices 39
What Aurora Outputs are used?
•Resource dispatch for Avista existing resources and resource
options
–Estimate profitability of each supply and demand side resource
–Estimate dispatch for REC calculation for CETA
•Value the cost to serve Avista’s load
•Estimate the emissions associated with supply side and storage
resources
•Estimate regional emission rates for savings for energy efficiency
resources
•Gain understanding of the region market
•Data is used to populate PRiSM Model
8 Avista Corp.2021 Electric IRP Appendices 40
PRiSM- Preferred Resource Strategy
Model
Internally developed using Excel based linear/mixed integer program
model (What’s Best & Gurobi)
Selects new resources to meet Avista’s capacity, energy, and
renewable energy requirements
Outputs:
–Power supply costs (variable and fixed)
–Power supply costs variation
–New resource selection (generation/conservation)
–Emissions
–Capital requirements
9 Avista Corp.2021 Electric IRP Appendices 41
What’s new with PRiSM for this IRP
New resources may be added to either WA, ID, or combined
customer requirements.
Existing resources will be allocated to each state using the PT ratio
(~65% WA and ~35% ID).
States may sell RECs between states.
Washington’s former share of Colstrip units will be assigned to new
“shareholder” portfolio after 2025.
10 Avista Corp.2021 Electric IRP Appendices 42
Social Cost of Carbon (SCC)
•Social cost of carbon will be applied for new resource options for
Washington customers; including
–“Resulting” dispatch of natural gas resources from Aurora forecast of
future real-time operations.
–upstream emissions associated with natural gas drilling and
transportation used to run facility.
–manufacturing, construction, and operation of all resources (using NREL
study).
–storage and market resources will include estimate based on the
average emissions rate of the region.
–energy efficiency resources will use the hourly marginal emission rate of
the region and reduction.
–SCC will not be used for biomass/geothermal resources
•SSC prices will not be included for Idaho customers; although Avista
could study this as a scenario
11 Avista Corp.2021 Electric IRP Appendices 43
Social Cost of Carbon Prices
SCC (2007$)SCC (2019$)Nominal $
Social cost of carbon dioxide in 2007 dollars using the 2.5% discount rate, listed in table 2, technical support
document: Technical update of the social cost of carbon for regulatory impact analysis under Executive Order No.
12866, published by the interagency working group on social cost of greenhouse gases of the United States
government, August 2016.
Adjust to 2019$ using Bureau of Economics GDP
Adjust to Nominal $ using 2.11% annual inflation rate
Levelized Price: $114.63 per Metric Ton
Avista Corp.2021 Electric IRP Appendices 44
Issues not finalized
•Prices of REC transfer between states
–Avista acquires new qualifying resources to meet Washington’s portion
of the law, although it may transfer RECs between Idaho and
Washington for the 20% portion of CETA
•How to count REC’s toward meet the “80%” portion of CETA
–Must bundled RECs only qualify if meeting Avista WA state load each
hour?
–Serve any WA state load or any utility load?
–Avista needs clarification from WUTC
13 Avista Corp.2021 Electric IRP Appendices 45
What is Reliability Planning
•Estimate the probability of failure to serve all load
–Avista’s reliability target is 95% of all simulations serve 100% of load and reserve
requirments
•Model randomizes events
–Hydro, weather (load, wind, resource capacity), forced outages
•Typically large sample size 1,000 simulations
•Can be used to validate if a portfolio is reliable
–Estimate the required planning reserve margin (PRM)
–May be used to estimate peak credits for new resources (ELCC)
•Gold standard: regional wide program with enforced requirements to
each utility
–Set required methodology, planning margin, and resource contribution
based on regional model
14 Avista Corp.2021 Electric IRP Appendices 46
Reliability Modeling
•2020 IRP included ELCC analysis for a new resource alternatives
and Avista Preferred Resource Portfolio for the year 2030
•Avista sees areas to improve in reliability modeling
–Quantity of future years
–Create ELCC curve for new resources
–Study all portfolio’s reliability requirements
–Improve model speed
•Single year study takes 3 days
–Create dynamic capability with PRiSM
15 Avista Corp.2021 Electric IRP Appendices 47
Options to Address Reliability Modeling
Option Pros Cons
Continue using existing model
(ARAM-excel model with solver)
•Results reliable for Avista system
•Fully developed
•Potential for modest speed improvements
•Control intellectual property
•Slow
•Limited to two processes
•User data/knowledge intensive
Build custom professional software •Likely faster speed
•Reliable results
•Potential to integrate with PRiSM
•Time to implement
•Cost
Adapt Aurora •User knowledge
•Cost
•Flexibility
•Data management
•Parallel processing limit by machines
•Slow (cost to speed up-Gurobi)
•Hydro logic-results in higher LOLP
•May only work for LOLH
•Storage logic is slow
New Genesis Model
(Power Council)
•Regional standard
•Addresses regional market availability
issues
•Strong hydro logic
•New technology
•Regional focus
•Model in progress; not available for
this IRP
Purchase Software/Hire Consultant •Flexibility
•Data management
•Reliable results ?
•Cost
•Implementation time
•Risk
Regional Resource Adequacy Market •Clear requirements for load and resources
on a regional basis
•Best case scenario
•Market in development not ready for
this IRP
•May have to make estimates for
future years
16 Avista Corp.2021 Electric IRP Appendices 48
Reliability Next Steps
•Continue testing Aurora application with Gurobi to understand speed
improvements and result improvements
•If we use ARAM
–Remain with single year study (2030 or 2035)
–Use 2020 IRP ELCC estimates
–Estimate ELCC curves for key resources (wind/ storage)
–Conduct study for each portfolio-may result in different planning
margins
–Move to using RA logic for next IRP if a regional program is developed
•Aurora option may expand options to additional forecast years and
ELCC studies
•Update progress with TAC once solution is finalized
17 Avista Corp.2021 Electric IRP Appendices 49
Data Availability Proposal
•Aurora
–Model requires licensing agreement with Energy Exemplar
–Avista specific data is confidential
–Model results will be retained by Avista
–Avista will provide summary level results for all studies (i.e. regional prices, regional emissions, regional dispatch)
•PRiSM
–All files will be available, includes annual data for each of 500 simulations for Avista resources and load
–Requires What’s Best and Gurobi license to solve, but results are fully visible
•Load Forecast
–Models are confidential; models includes specific customer information and confidential data
–Monthly energy and peak data will be available by state, along with break down between new +/-loads (i.e. rooftop
solar, electric vehicles, and natural gas)
–Full discussion of process will be covered in TAC 2
•Resource Costs
–Supply-side resources spreadsheet will be available with all calculations
–Demand-side resources; measure list and costs will be public for energy efficiency and demand response.
•Transmission & Distribution
–All models and data are confidential
–Avista will provide cost and requirements for resource integration as provided in prior IRPs
–Full discussion of process will be covered in TAC 3
•Reliability Planning
–Availability will depend on modeling solution
–Results will be retained and available
Avista Corp.2021 Electric IRP Appendices 50
2021 Electric IRP
Generation Resource Options
Lori Hermanson, Senior Power Supply Analyst
First Technical Advisory Committee Meeting
June 18, 2020
Avista Corp.2021 Electric IRP Appendices 51
Overview & Considerations
•The assumptions discussed are “today’s” estimates –likely to be
periodically revised
•IRP supply-side resources are commercially available technologies with
potential for development within or near Avista 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.
•Natural gas prices are 2020 IRP prices and will be revised with the “final”
assumptions
•An Excel file will be distributed with all resources, assumptions and cost
calculations for TAC members to review and provide feedback.
2 Avista Corp.2021 Electric IRP Appendices 52
Outlook Since Last IRP
•Natural gas small CT –4.4%
•Natural gas CCCT -5.8%
•Solar –8%
•Wind –0.3%
•Lithium Ion Storage –8%
3
Gas turbines 2022 vs 2020; others are 2022 vs 2022
Avista Corp.2021 Electric IRP Appendices 53
Proposed Natural Gas Resource Options
Peakers
•Simple Cycle Combustion Turbine
(CT)
–Aero and frame units
–Smaller units 44 MW to 84 MW
•Hybrid CT
–92 MW
•Reciprocating Engines
–9 MW to 18 MW units with up
to 10 engines
Baseload
•Both modern and advanced
Combined Cycle CT (CCCT) will
be evaluated
–Smaller option 249 MW (3x2)
–Larger options 311 MW to 587
MW (1x1)
•Large 2x1 technology not modeled
Natural gas turbines are modeled using a 30-year life with Avista ownership
4 Avista Corp.2021 Electric IRP Appendices 54
Renewable Resource Options
All Purchase Power Agreement (PPA) Options
Wind
•On-system wind (100 MW)
•Off-system wind (100 MW)
•Montana wind (100 MW)
•Offshore wind (100 MW)
–Share of a larger project
Solar
•Fixed PV Array (5 MW AC)
•On-System Single Axis
Tracking Array (100 MW AC)
•Off-system Single Axis
Tracking Array (100 MW AC)
located in southern PNW
•On-System Single Axis
Tracking Array (100 MW AC)
with 25 MW 4 hour lithium-ion
storage resource
•May model alternative solar
with smaller battery
configurations
5 Avista Corp.2021 Electric IRP Appendices 55
Other “Clean” Resource Options
•Geothermal (25 MW)
–Off-system PPA
•Biomass (25 MW)
–i.e. Kettle Falls 3 or other
•Nuclear (100 MW)
–Off-system PPA share of a mid-size facility
•Renewable Hydrogen
–Fuel Cell (25 MW)
–Natural Gas Turbine Retrofit
6 Avista Corp.2021 Electric IRP Appendices 56
Storage Technologies
Lithium-Ion
•Assumes: 88% round trip
efficiency (RTE), 10-year
operating life
•Assumes Avista ownership
•5 MW Distribution Level
–6 hours (30 MWh)
•25 MW Transmission Level
–4 hours (100 MWh)
–8 hours (200 MWh)
–16 hours (400 MWh)
Other Storage Options
•Assumes 20 to 30-year life and Avista
ownership
•25 MW Vanadium Flow (70% RTE)
–4 hours (100 MWh)
•25 MW Zinc Bromide Flow (67% RTE)
–4 hours (100 MWh)
•25 MW Liquid Air (60-70% RTE)
•100 MW Pumped Hydro
–Share of larger project
–PPA assumption
Updates to storage costs are
likely as additional information
becomes available7Avista Corp.2021 Electric IRP Appendices 57
Resource Upgrades
•Rathdrum CT [natural gas peaker]
–5 MW by 2055 uprates
–24 MW add supplemental compression
–17 MW (summer), 0 MW (winter) Inlet Evaporation
•Kettle Falls [biomass]
–12 MW by repowering with larger turbine during replacement
•Long Lake 2nd Powerhouse [hydroelectric]
–68 MW, 12 aMW with additional powerhouse located at the
current “cutoff” dam
•Cabinet Gorge [hydroelectric]
–110 MW, 18 aMW using the “bypass” tunnels to capture runoff
spill
8 Avista Corp.2021 Electric IRP Appendices 58
Adv Small Frame CT
Frame/Aero Hybrid CT
Lg Recip
Sm Recip
Modern SmFrame CT
Aero CT
$0
$5
$10
$15
$20
$25
$30
$35
$40
$45
$50
$0 $50 $100 $150 $200 $250 $300
Fixed Cost 2022 $ per kW-yr at Busbar
Natural Gas Fixed & Variable Costs
9
Green: Reciprocating Engines
Blue: SCCT
Red: CCCT
Avista Corp.2021 Electric IRP Appendices 59
PPA Resource Cost Analysis
10 Prices include utility loading such as variability integration and revenue taxes
$0 $20 $40 $60 $80 $100 $120 $140 $160
On-System Wind
Off-System Wind
MT Wind
Off Shore Wind
On-System Solar
Southern NWSolar
Small Solar
Nuclear
Geothermal
2042
2032
2022
Avista Corp.2021 Electric IRP Appendices 60
Storage Costs
Capacity based cost analysis
11
$0 $200 $400 $600 $800
Distribution Scale 6hr Lithium-Ion
4hr Lithium-Ion
8hr Lithium-Ion
16hr Lithium-Ion
4 hr Vanadium Flow Battery
4 hr Zinc Bromide Flow Battery
Liquid Air
Pumped Hydro (16 hr/ 100 MW share)
$ per kW-Year
2042
2032
2022
Avista Corp.2021 Electric IRP Appendices 61
Storage Costs
Energy based cost analysis
12
$0 $20 $40 $60 $80 $100 $120
Distribution Scale 6hr Lithium-Ion
4hr Lithium-Ion
8hr Lithium-Ion
16hr Lithium-Ion
4 hr Vanadium Flow Battery
4 hr Zinc Bromide Flow Battery
Liquid Air
Pumped Hydro (16 hr/ 100 MW share)
$ per kWh-Yr
2042
2032
2022
Avista Corp.2021 Electric IRP Appendices 62
Rath Supp Compression
Rath CT 2055 Uprate
Rath CT Inlet Evap
KF Turbine Gen Update
LL 2nd
PowerhouseCG 2nd
Powerhouse
Biomass
$0
$10
$20
$30
$40
$50
$60
$0 $50 $100 $150 $200 $250 $300 $350
20
2
2

$

p
e
r

M
W
h
2022 $ per kW-yr at Busbar
Facility Upgrade Cost Analysis
13
Green: Biomass
Blue: Hydro
Red: Natural Gas
Avista Corp.2021 Electric IRP Appendices 63
Other Power Purchase Options
•Market Power Purchases
–Firm purchases
–Real-time
•Mid-Columbia Hydro
–Renegotiate slice contracts from Mid-C PUDs
•Acquire existing resources from IPPs
•Renegotiate Lancaster PPA
•BPA
–Block surplus contract: up to 7-year term at BPA “cost”
–NR Energy Sales: $78.94 MWh
–After 2028, other potential options when current Regional
Dialogue contracts expire
14 Avista Corp.2021 Electric IRP Appendices 64
Other Items for TAC Input
•Pumped hydro
–Model specific projects vs.
generic options
•Hydrogen Technologies
(still researching)
–Fuel cell
–Gas turbine retrofit
•Will consider other
resource options subject to
TAC input
14 Avista Corp.2021 Electric IRP Appendices 65
Review Excel Sheet
16 Avista Corp.2021 Electric IRP Appendices 66
2021 Electric IRP
Washington Vulnerable Populations &
Highly Impacted Communities
James Gall, IRP Manager
First Technical Advisory Committee Meeting
June 18, 2020
Avista Corp.2021 Electric IRP Appendices 67
CETA: Section 1
(6) The legislature recognizes and finds that the public interest
includes, but is not limited to:
•The equitable distribution of energy benefits and reduction of
burdens to vulnerable populations and highly impacted
communities;
•long-term and short-term public health, economic, and
environmental benefits and the reduction of costs and risks;
•and energy security and resiliency.
It is the intent of the legislature that in achieving this policy for
Washington, there should not be an increase in environmental health
impacts to highly impacted communities.
2 Avista Corp.2021 Electric IRP Appendices 68
Definitions
(23) "Highly impacted community" means a community designated by
the department of health based on cumulative impact analyses in
section 24 of this act or a community located in census tracts that are
fully or partially on "Indian country" as defined in 18 U.S.C. Sec. 1151
(40) "Vulnerable populations" means communities that experience a
disproportionate cumulative risk from environmental burdens due to:
(a) Adverse socioeconomic factors, including unemployment, high housing
and transportation costs relative to income, access to food and health
care, and linguistic isolation; and
(b) Sensitivity factors, such as low birth weight and higher rates of
hospitalization.
3 Avista Corp.2021 Electric IRP Appendices 69
How Avista Reaches These Communities
Today
•Low income assistance
•Senior/disability rate discount
•Project share
•Energy efficiency programs
•Energy fairs and workshops
•Corporate and Avista Foundation
giving
•Energy home audits
•Prevention of wood smoke part of
energy efficiency analysis
•Wildfire mitigation program
•Public access to hydro facilities
•Park development
•Neighborhood engagement when
developing projects
•Tribal hiring
•Energy pathways program
•Tribal settlements
•Hydro relicensing outreach
•Wildlife land purchases
4 Avista Corp.2021 Electric IRP Appendices 70
IRP Requirements (Section 14)
(k) An assessment, informed by the cumulative impact
analysis conducted under section 24 of this act, of: Energy
and nonenergy benefits and reductions of burdens to
vulnerable populations and highly impacted communities;
long-term and short-term public health and environmental
benefits, costs, and risks; and energy security and risk;
Sec. 24. By December 31, 2020, the department of health must develop a cumulative
impact analysis to designate the communities highly impacted by fossil fuel pollution and
climate change in Washington. The cumulative impact analysis may integrate with and
build upon other concurrent cross-agency efforts in developing a cumulative impact
analysis and population tracking resources used by the department of health and
analysis performed by the University of Washington department of environmental and
occupational health sciences. [https://www.doh.wa.gov/CETA/CIA]
5 Avista Corp.2021 Electric IRP Appendices 71
How Will Avista Address These New
Requirements?
•Gain perspectives from advisory group(s) for additional
requirements or from new rules
•Identify and engage highly impacted communities &
vulnerable populations
–Advisory groups
–Encourage representatives to either participate in existing advisory
groups or potentially create a new advisory group to address the
community impacts.
•Create baseline data
•Estimate benefits/impacts from IRP
6 Avista Corp.2021 Electric IRP Appendices 72
Identifying Communities or “Customers”
Highly Impacted
Communities
–Cumulative Impact Analysis
–Tribal lands
•Spokane
•Colville
–Locations should be available
by end of 2020
•State held workshops in
August & September 2019
Vulnerable
Populations
–Use Washington State Health
Disparities map
•What is disproportionate on a
scale of 1 to 10?
•Avista proposes areas with a
score 8 or higher in either
Socioeconomic factors or
Sensitive population metrics
–Should we include other
metrics to identify these
communities?
7 Avista Corp.2021 Electric IRP Appendices 73
Environmental Health Disparities Map
https://fortress.wa.gov/doh/wtn/wtnibl/
Data by FIPS Code
8 Avista Corp.2021 Electric IRP Appendices 74
Environmental Health Scoring
Circle areas match definition of
vulnerable population,
although access to food &
health care, higher rates of
hospitalization are not
expressively included but are
an indication of poverty
9 Avista Corp.2021 Electric IRP Appendices 75
Eastern Washington Communities
Socioeconomic Factors Sensitive Populations
10 Avista Corp.2021 Electric IRP Appendices 76
Avista Electric Service Territory
11 Avista Corp.2021 Electric IRP Appendices 77
Data Analysis of Vulnerable Populations
Socioeconomic Sensitive
Avista (Mean)5.1 (5 median)6.0 (6 median)
State (Mean)5.4 (5 median)5.2 (5 median)
Avista (Stdev)2.67 2.83
State (Stdev)2.88 2.8812
Avista has 145 communities identified
•35 (24%) have an 8 or higher for Socioeconomic Factors
•55 (38%) have an 8 or higher for Sensitive Populations
•67 (46%) are considered vulnerable
Avista Corp.2021 Electric IRP Appendices 78
Selected Vulnerable Populations
13
Data is shown
by combined
score
Avista Corp.2021 Electric IRP Appendices 79
Spokane Area “Avista” Vulnerable
Populations
14
Data is shown
by combined
score
Avista Corp.2021 Electric IRP Appendices 80
IRP Metrics
Metric IRP Relationship
Energy Usage per Customer •Expected change taking into account selected energy
efficiency then compare to remaining population.
•EE includes low income programs and TRC based
analysis which includes non-economic benefits.
Cost per Customer •Estimate cost per customer then compare to
remaining population.
•How do IRP results compare to above 6% of income?
Preference •Should the IRP have a monetary preference?
•For example-should all customers pay more to
locate assets (or programs) in areas with
vulnerable populations or highly impacted
communities?
•If so, how much more?
15 Avista Corp.2021 Electric IRP Appendices 81
IRP Metrics
Metric IRP Relationship
Reliability
•SAIFI: System Average Interruption
Frequency Index
•MAIFI: Momentary Average Interruption
Frequency Index
•Calculate baseline for each distribution feeder and
match with communities
•Estimate benefits for area with potential IRP
distribution projects
•Compare to other communities as baseline
•May be more appropriate in Distribution plan rather
than IRP
Resiliency:
•SAIDI: System Average Interruption Duration
Index
•CAIDI: Customer Average Interruption
Duration Index
•CELID: Customer’s Experiencing Long
Duration Outages
Resource Analysis •Estimate emissions (NOX,SO2, PM2.5, Hg) from
power projects located in/near identified communities
•Identify new resource or infrastructure project
candidates with benefit to communities; i.e. economic
benefit, reliability benefit
•Identify how resource can benefit energy security
16 Avista Corp.2021 Electric IRP Appendices 82
TAC Input
•What other metrics can we provide in an IRP to
show vulnerable populations and highly
impacted communities are not harmed by the
transition to clean energy
17 Avista Corp.2021 Electric IRP Appendices 83
1

Attendees: TAC 1, Thursday, June 18, 2020 Virtual Meeting on Skype:
Shawn Bonfield (Avista), Terrance Browne (Avista), Logan Callan (City of Spokane),
Teri Carlock (IPUC), John Chatburn (Idaho Governor’s Office of Energy and Mineral
Resources), Corey Dahl (Washington State Office of the Attorney General), Thomas
Dempsey (Avista), Chris Drake (Avista), Annabel Drayton (NW Energy Coalition),
Michael Eldred (IPUC), Nancy Esteb (Renewable Energy Coalition), Chip Estes, Rachelle Farnsworth (IPUC), Ryan Finesilver (Avista), Damon Fisher (Avista), Grant
Forsyth (Avista), James Gall (Avista), Annie Gannon (Avista), Amanda Ghering (Avista),
Dainee Gibson (Idaho Conservation League), Kate Griffith (Washington UTC), Vlad
Gutman-Britten (Climate Solutions), Leona Haley (Avista), Jared Hansen (Idaho Power), Lori Hermanson (Avista), Kevin Holland (Avista), Kristine Holmberg (Avista), Tina
Jayaweera (Northwest Power and Conservation Council), Clint Kalich (Avista), Kevin
Keyt (IPUC), Kathleen Kinney (Biomethane, LLC), Scott Kinney (Avista), Dean Kinzer
(Whitman Co. Commissioner’s Office), Erik Lee (Avista), John Lyons (Avista), James
McDougal (Avista), Matt Nykiel (Idaho Conservation League), Tom Pardee (Avista),
Jørgen Rasmussen (Solar Acres Farm), John Ross, John Rothlin (Avista), Jennifer Snyder (Washington UTC), Dean Spratt (Avista), Jason Thackston (Avista), Marissa
Warren (Idaho Governor’s Office of Energy and Mineral Resources), Amy Wheeless
(NW Energy Coalition), and 13 Guests who did not identify themselves.

Questions and comments are identified by speaker when possible and text in italics
records the responses by the presenters.

TAC Expectations & Process Overview
John Lyons: A new stakeholder feedback form will be added to the IRP website. Slides
from this meeting will be posted on the IRP website next week. The generation resource
options spreadsheet was emailed earlier this week. Avista is also considering different
options for meetings and sharing of TAC materials, but we will continue to post meeting
notes on the website. We will attempt to record these meetings.
John Lyons: Washington now requires an IRP every 4 years with an update after two
years. Washington law (Clean Energy Transformation Act or CETA) does not allow for
the Commission to acknowledge an IRP without all of the CETA requirements and
rulemaking in place, moving the next IRP out until 4/1/21. The 2021 IRP will be
modeling 2021 through 2045 (for CETA). Avista welcomes requests for additional
studies by August 1, 2010, but earlier is better for accommodating any requests. The
dates of future TAC meetings are in the presentation and posted on the IRP web site.

Avista Corp.2021 Electric IRP Appendices 84
2

2020 IRP Acknowledgement – John Lyons
IRP acknowledgement means the filing has met the rules for IRPs in both states. It
includes comments about topics to include or build upon in the next IRP.
Acknowledgement does not provide rate recovery, but is a component of rate recovery.
If a new resource wasn’t chosen in the IRP, we have more explanation required what it
was not identified in the IRP. Because of the extension for the 2020 IRP, we do not
have acknowledgements to review in this meeting. The Idaho Commission is accepting
comments from the public through August 19, 2020 with replies due from the Company
by September 2, 2020. A key area of expected concern is how Avista will develop an
IRP that accommodates Washington’s CETA requirements, but not adversely impact
Idaho customers. Washington suspended acknowledgement letter through December
31, 2020, but provided some comments on the work plan including providing an
opportunity for stakeholder input on the conservation potential assessment (CPA)
before finalization, extending participation to a broader public audience, and providing a
timeline of IRP data and when it will become available.

CETA Rulemaking Update – Shawn Bonfield
CETA applies to all electric utilities in Washington. It requires 100% clean energy, the
elimination of coal from serving Washington customers by 2025, greenhouse gas
neutral by 2030 and at least 80% clean, and 100% renewable or generated from zero-
carbon resources by 2045. CETA also requires equitable distribution of energy and non-
energy benefits and to ensure public health and environmental benefits. Avista is well
above the 15% renewable standard required under the Energy Independence Act (I-
937). Avista is about 60% clean/renewable today. 2020 is a big year for CETA
rulemaking: Phase 0 included the overall implementation plan. Phase 1 (August 2019 –
January 1, 2021) includes the already published the Social Cost of Carbon
(https://www.utc.wa.gov/regulatedIndustries/utilities/Pages/SocialCostofCarbon.aspx)
for use in resource planning and the CPA, and the initiation of other required rulemaking
dockets. Concurrent EIA draft rules are about done and hopefully will be adopted next
month. Other areas include the CEIP – how utilities will look at compliance and penalty
processes; IRP updated rulemaking – July timeframe; Purchase of Electric (impacts
RFPs) draft rules June 1 with comments due end of June with a workshop mid-July;
Department of Ecology rulemakings will identify greenhouse gas emission factors; and
plenty of other rulemaking activity at the Department of Commerce, the UTC and other
agencies.
Jennifer Snyder: Thank you. You covered it well. We (Washington UTC) appreciate
any comments and participation in the CETA rulemaking process.

Avista Corp.2021 Electric IRP Appendices 85
3

Modeling Process Overview – James Gall
James Gall: Aurora in an electric market cost model that is used to simulate the
Western Interconnect. It is the industry standard model in the Northwest. Avista
implemented Aurora in 2003 and uses it for IRP and rate cases. The inputs include
regional loads, fuel prices, resource availability, new resource costs, transmission, and
system constraints. Outputs include market prices, energy mix, transmission usage,
emissions, power plant margins, generation levels, fuel costs and variable power supply
costs to serve loads by year. Market price forecast helps us develop a purchase/sales
strategy. The model dispatches to meet hourly loads in each area and tries to match
supply with demand or loads and resources. Market price is based on the price for the
last, or marginal, plant to turn on for that hour.
Matt Nykiel (Slide 3): I have a better understanding of Aurora after participating in the
last IRP. For slide 3 inputs and following, I’d like a general understanding of what inputs
are public and private in Aurora. We’ll cover some here and there is a slide later that
cover more. The database from EPIS is proprietary and they use it for all of their clients
who are Aurora license holders. It is largely based on publically available information
from EIA, EPA, etcetera, but we can’t release it per our license. There are adjustments
for Avista including data that will be changed to reflect our contracts, pricing, and
operational requirements and how we operate our resource which are proprietary. We’ll
describe more alter in the presentation. Thank you.
James Gall: Deterministic studies are single point estimates with median hydro and
expected loads. They are easy for scenario analyses. Stochastic studies use the
expected case or preferred portfolio providing a range of results. The model runs 500
times with different inputs in order to understand risk or volatility. Avista uses the mean
value of stochastic analysis for its expected case. Stochastic studies provide better
representation of expected value of resources. The model assumptions start from 2020
IRP. We use the same database available from Energy Examplar today; then update
natural gas prices, new resources and retirements, include new laws, review
load/resource assumptions for EVs, rooftop solar, new resource costs, add Avista
proprietary system info and stochastic distribution of regional hydro, natural gas, wind
and loads. We will provide what’s not confidential. The Aurora run process-request input
will need to be done ASAP, finalize inputs, run long term studies to estimate new
resource additions and will show results at next TAC. We will test under 500 simulations
and test a future year – 2035. The deterministic run tests reasonableness. The
stochastic run takes 3 weeks to run the scenarios. It is a very tight timeline. The outputs
will show how profitable each of the resources are to understand dispatch under CETA.
This helps us value the cost to serve, estimate emissions, understand changes to the
regional market such as volatility, emissions, etc., and the data used for PRiSM.
Matt Nykiel (Slide 7): You mentioned long-term study. Is this what Avista thinks how
the region will meet demand? Is this Avista’s interpretation or is it based on other
utilities that have their own IRPs? That’s a good question. It’s multiple ways. We
Avista Corp.2021 Electric IRP Appendices 86
4

typically have not utilized other utility’s IRPs since they only cover a portion of the area
and could be dated. Some utilities don’t do IRPs. We look at the region of load
obligations, the current resource mix, and state requirements. The model selects new
resources for most cost effective for those load areas given our cost assumptions. We
have also looked at other studies, consultant data for storage and small renewables.
This is a fairly industry standard approach.
James Gall: PRiSM is where all of the models come together from an input perspective
to make resource decisions. It is internally developed. We input resource needs and
options. The model will select resources that meet needs based on constraints. ‘What’s
Best’ is the solver function – min/max of a variable to optimize the value with unlimited
variables/constraints. What’s Best plus Gurobi speeds up optimization especially when
considering so many inputs such as energy efficiency. The outputs include the power
supply costs (fixed + variable) and variation; selection of new resources, etc. We design
the model to add new resources to serve Washington, Idaho or combined customer
requirements. We will split our resource cost using the P/T ratio [35% Idaho and 65%
Washington]. States may sell RECs to help recover customer costs.
James Gall (Slide 10): The last IRP showed that Colstrip was not cost-effective past
2025. We will reevaluate Colstrip in this plan as no decision has been made. After 2025,
since we’re splitting by state in PRiSM for the resource balance, Idaho will still receive
its 35% share of Colstrip unless it’s determined that it will be retired. There is an option
to retire in Colstrip in 2025 or in the future.
Vlad Gutman-Britten: Does the future year on the chart incorporate potential climate
change? Typically impacts include from climate change include load and hydro. We are
open to for 2045 about how climate change impacts these forecasts
John Lyons: Grant [Forsyth] picks these changes up in his load forecast.
Grant Forsyth: I try to look at how temperatures change. The approach is a moving
average for weather. People can ask more about that during my presentation in the next
TAC meeting [August TAC].
James Gall (Slide 11): The Social Cost of Carbon (SCC) is required for Washington
under CETA. We will run the model to get the expected amount of emissions for each
resource. This is for long-term not short-term resources. We will calculate emissions
from short-term resources and may cover those at a future TAC. We will not include
SCC for biomass or geothermal since those resources are specifically outlined in law, or
for Idaho, but we could consider including for Idaho as a scenario if the TAC wants.
James Gall (Slide 12): SCC pricing – 2007 $ and discounted 2.5% (on the lower
range). Will use the green line in the chart which starts at $80 per ton. We move prices
from 2007 to 2019 and inflate based on our annual inflation rate of 2.11%.
James Gall: (Slide 13): Issues Not Finalized. We may transfer RECs between states,
but must determine the price to transfer RECs at. We will need input on if we need to
Avista Corp.2021 Electric IRP Appendices 87
5

consider transferring more than 20% if there is an economic benefit. How do we count
RECs toward the 80%? Will this be hourly or over the four-year compliance period? If
we receive no clarification, we will need to make assumptions to model the IRP. This
may be the biggest rulemaking from CETA that the UTC needs to resolve, hopefully in
early fall, so it can be modeled correctly for this IRP.
James Gall (Slide 14): Reliability planning. We estimate probability of failure to serve
all load to a regional standard of 5%. To evaluate whether a portfolio is reliable – PRM
(planning reserve margin) is the percentage above the expected load measured by the
coldest day of each month averaged by that temperature, load requirement, plus
planning margin. This helps us understand how much we can rely on certain resources.
The gold standard would be a region wide program with enforced requirements for each
utility. Currently, the region is looking at moving toward this model, but probably not in
time for this IRP. So, we need to decide how much time we invest in this issue now.
ELCC (Electric Load Carrying Capability) – improvement by focusing on additional
years, sampling every 5 years, peak credits or peak types. As you add intermittent
resources peak value declines. We haven’t ran an ELCC for each resource to determine
how much the peak contribution reduces over time.
James Gall (Slides 15 – 17): Reliability study models to consider. ARAM model is used
currently and is customized (not for this IRP). Aurora has ability to dispatch hydro – not
as good when the system is stressed leading to over acquisition. Genesis is an option
for the future. We can purchase software/hire consultant – this is costly and not
currently being looked at. Regional Resource Adequacy Market – could be used for a
future option. Two areas of focus are ARAM and Aurora – likely our current model with
a single year and possibly scenarios, but we can’t commit to every year, use 2020
ELCC (peak credits) scenario on resource adequacy. We will keep the TAC updated
throughout the process.
James Gall (Slide 18): Data availability – proposal, we are interested in feedback for.
Avista-specific data and Energy Exemplar database is proprietary, prices, regional
emissions, not dispatch (confidential), high level results including PRiSM, won’t be able
to make inputs and resolve (requires license), big change from prior IRPs, load forecast
models are confidential because of customer-specific information. We will provide
monthly energy/peak results by state, resource costs (you already received); demand-
side data will include a list of energy efficiency programs available, may not be fully
available in July/August so we may have a short, 1-hour workshop when that data
becomes available. DR programs and their potential. Transmission/distribution models
are confidential and will be a TAC 3 discussion. Reliability – ARAM requires a license so
you can’t input and resolve, but we are researching to ensure we can make it available.
Michael Eldred: I have a question of how you are testing for reliability. LOLP in 2035,
500 times in that year. The percent probability load not met. The goal is 95% meeting in
all times. In most cases it does. If results are grossly inadequate and outside the margin
of error, we rerun the study. Does that help? Yes, thank you.
Avista Corp.2021 Electric IRP Appendices 88
6

Matt Nykiel: LT study, when Avista is looking over a range of resources is it taking into
account things like customer owned generation over time as roof top solar reduces
demand on IOUs? Good question. Slide 6 specific adjustment made to model. We will
present assumptions in the market price meeting. Definitely an area we will have to
consider.
Matt Nykiel: Recall that was an analysis for Avista, but how meeting regional WECC
loads but in area. Yes, we look at both inside Avista and outside the service territory.
Looking to point to the right spot in the last IRP. Typically not a lot of discussion. It is a
small but important input. Will definitely talk about it in the next TAC.
James Gall: I appreciate the better interaction on these questions.
Tina Jayaweera: I’m interested in more about emissions savings in energy efficiency
and demand response. DR is challenging and depends on program – some reduce and
some shift loads, and the likelihood of a DR program being called on based on program
design could be a challenge. Energy efficiency typically uses an hourly profile of savings
compared to hourly emissions from Aurora – possibly could run a scenario to see how
emissions change by the hour. We can do this for the deterministic but not all 500 runs.
Could show incremental savings.
Dainee Gibson: A lot of CETA requires the model to be able to split differences
geographically. Can Aurora split it by state or does it apply to the entire service
territory? Sure. We could split it by state, but it doesn’t model the physics well. Now we
talk about region as a whole. The OWI bubble in Aurora can’t split by state really well,
since the system doesn’t recognize state boundaries. Avista in PRiSM is where we talk
about how we split resources by state from a resource planning perspective.
Kevin Keyt (Slide 10): I understand the 65/35 split historically, but it appears
incremental legislation in Washington may split differently. Maybe the model equals
65/35 for existing resources and the split of new resources are an output of the model. I
don’t want to volunteer you for a bunch of runs, but want to understand how it might
change. We may shift from a cost to a load balance.
Vlad Gutman-Britten: CETA requires 100% in 2045, but Avista corporate goal is 100%
by 2027. How do you account for that? Excellent question. If cost effective, we will do it.
Will run a scenario to meet the goal and it becomes a management decision on
reaching 2027 and 2045 goals to set the strategy going forward based on the cost to
customers. Last IRP, we were 90% clean without additional costs beyond CETA. At that
time, management was not willing to put that additional cost on customers for the
remaining 10 percent.
Matt Nykiel: In PRiSM, are there parameters that require Avista service territory to
meet the goal in 2027 and 2045 for the entire service territory? Carbon neutral by 2027
and 2045 is not meaningful if not cost effective from the get go. I don’t understand the
goal if it doesn’t have an impact
Avista Corp.2021 Electric IRP Appendices 89
7

Jason Thackston: Good question and the point is appreciated. I appreciated the way
James answered. What we said, and are still committed to, is affordability and reliability.
We are still committed to those goals, but reliability will not be sacrificed and the goal is
subject to affordability by the impact on customers’ bills. We always look at cost-
effective, but trying to be more holistic. Does that help?
Matt Nykiel: I’d like to learn more.
Terri Carlock: To clarify, you will run the full system to meet that commitment and
looking at the costs separately for both states to decide whether you implement in both
states and the Commissions will each review. That is a fair and correct summary. Still
need guidance by states before we can fully state how we model.
Vlad Gutman-Britten – Are you selling REC between states? About ready to talk about
that. If 20% REC only or bundled. Idaho to Washington for Rulemaking is still being
considered relative to this and bundling so I can’t answer specific questions on how
we’ll be modeling until the rulemaking is more final. We will likely try to simulate REC
sales similar to our last plan.
Vlad Gutman-Britten: So Idaho would have a higher fossil fuel content than
Washington? Correct.
Matt Nykiel (Colstrip): What does it mean to have a shareholder portfolio? One
question, I don’t understand why if Units 3 and 4 are uneconomic, why is the
Washington share only going to shareholders? Need to model it to decide where it
goes. We are redoing same analysis so the Idaho portion only serves their load. If the
model chooses 2025, or another date, to close for economics. The shareholder portfolio
is because it can’t be in Washington rates after 2025 under CETA, but if it is still
operating, we still have to sell off or consume those megawatt-hours.
Jason Thackston: Correct me if what I say is incorrect. There are two outcomes. One.
Assume all same as last IRP, after 2025 Colstrip is not in the portfolio because it is not
economic. Two. Very extreme. Everything doubles and Colstrip is way in the money, it
should still be in the portfolio beyond 2025, but it is not viable in Washington. It would
still be, absent a decision to shut down the plant. Nuance in Washington State the
model has to reflect.
Matt Nykiel: That’s helpful. Thank you.
Terri Carlock: What shareholder portfolio costs would be associated for any costs
extending the life of the plant? Washington depreciation done in 2025 for Colstrip. Any
other O&M, capital, or fuel at that time will be on shareholders. Washington will still
cover their shutdown costs for the time it was on their system.
Matt Nykiel (Slide 10 – PRiSM): I don’t mean to belabor the point, first bullet point,
does it respect state guidelines? How will the model in practice split up new resource?
We don’t have all the answers regarding specific actual operations. From a modeling
Avista Corp.2021 Electric IRP Appendices 90
8

perspective for adding or subtracting resources we continue to operate as a whole
system. Operations is as a single system. From a clean energy perspective, we can
assign whether or not power is clean, etcetera on an accounting basis not a physics
basis. Accounting rather than an engineering basis. Appreciate more discussion in the
future.
Terri Carlock: Same for market purchases? Still rules to come. I hope regulating
bodies don’t rush it because of lasting impacts of the decision.
Jennifer Snyder: Are you including social cost of carbon on new construction and
operation of new or existing resources? Just new, but there are there processes at the
generation site that add to emissions. Trucks for hauling fuel at Kettle Falls and other
equipment, trucks to maintain wind farms. NREL has some older studies estimating
these types of emissions as well.
Matt Nykiel: SCC is a reflection of the understanding of GHG cost not being
internalized by facilities that emit them. Is Avista incorporating this cost due to the legal
requirements not because Avista is acknowledging that GHG have a cost that’s not
being internalized? Its Avista’s understanding of a cost just as a legal operation, not as
a corporate entity. Makes sense. One way to interpret it.
Jason Thackston: I’m not sure I’m the best one to answer, but generally speaking you
have captured it for Washington legislation and Washington feedback.
Tina Jayaweera: Upstream value for emissions? Next TAC meeting, but Avista gas line
rights are very different than the distribution side. We source our gas mostly from
Canadian sources so we’re focusing on the emission for the gas we’re sourcing.
Jennifer Snyder: Issues not finalized, what date do you need clarification by for
RECs/CETA? REC transfers by September [2020] at the latest. Earlier is better. If not
clarified by then, we would run multiple scenarios or possible outcomes.
Matt Nykiel: Bundled RECs, can Avista transfer energy plus RECs associated with
that? Multiple interpretations of the options. Power, REC, power plus REC or separate
the two and combine with others. The way bundled or not is the difference for
Washington CETA in different contexts. Depending on how WUTC rules, we could have
to way overbuild because of REC needs. Treat as I-937 or actually serve
instantaneously.
Rachelle Farnsworth: So can you tell more on how and why it is Washington
establishing the price of REC transfers between states? Hopefully I didn’t say that.
Washington sets the requirement for how many RECS are required. Then it is a
question of what price is needed to meet Washington law. I.e., the price is $20 so the
model says build for Idaho to sell to Washington. Price matters depending on outcome
in model. Much as last time, if economic to build for state and take advantage of the
market if available. Three examples at different prices: example price of a REC at $20,
Idaho should build a project to sell to Washington. If valued at $0, Idaho wouldn’t build.
Avista Corp.2021 Electric IRP Appendices 91
9

We wouldn’t want to see the model build based on resources to sell to Washington, but
would build the least cost to take advantage of the market.
Kevin (IPUC) – have you defined requirements for Reliability modeling (document would
be helpful)? James - slide 14 95% of simulations serve 100% load and reserve
requirements; don’t want to start down the path of buying new software if the regional
market is coming soon
Kevin Keyt (Slide 14): Have you defined requirements for reliability models and
decision making? 95% LOLP of simulations serve 100% of load requirements and we
look at other metrics too. In terms of software development and modeling tool, we want
to produce some confident results. There is a cost to maintain/operate a reliability
model. Timeline is short for this plan, so we don’t want to go too far if a resource market
overseer is coming. Maybe the new Genesis model. Maybe a new overseer. Don’t want
to have to scrap a new model in a year or two.
Modeling Process Overview Continued After Lunch Break – James Gall
Matt Nykiel: I appreciate the transparency. I notice it in the slides already. For Aurora,
I’d like to understand Colstrip inputs better. If Units 3 or 4 continues to be uneconomic
for Idaho from modeling, how would the Idaho share go into a shareholder portfolio?
Aurora gives a price forecast valuing resources not by ownership. Dispatch the plant
with a heat rate and fuel costs that influence market price if economic to run. If PRiSM is
not cost effective, do we retire or close the plant? If it goes out, need to decide how – if
closed or sold. PRiSM more utility based.
Matt Nykiel: Make sure the model is looking at price to meet minimum take obligations.
If it becomes uneconomic for Idaho, does the IRP consider where that minimum energy
goes? If it goes out of the Idaho portfolio, it jumps from planning to action. If we remove
it from Idaho, Idaho no longer bears the expense. We reevaluate it at every IRP cycle.
Nothing changes here from how we model in last IRP
Matt Nykiel: Mentioned earlier it accounts for shut down, forced outages and needed
repairs. Unit 4 is expected to need repairs to the super heater. Does the model account
for those expected repairs? This can affect ownership issues not agreed to under
sections of the contract. I can’t and maybe shouldn’t comment on a contract. It includes
expected and potential repairs.
Generation Resource Options – Lori Hermanson
James Gall: We are seeking feedback from the TAC about if we should model generic
or specific resources regarding pumped hydro storage.
Jennifer Snyder: Don’t have rates impact now. But lean towards specific projects if
data available.
Terri Carlock: Doesn’t pumped hydro storage depend on scale?
Avista Corp.2021 Electric IRP Appendices 92
10

James Gall: A generic resource would need an assumption for duration and cost.
Hybrid concept we used last time. But some projects have attributes with lower or
higher costs. We got comments last time from some TAC members. We modeled one
specific pumped hydro resource and some TAC members thought we should have
modeled others. Then what about specific wind and solar projects? That means we are
doing an RFP in an IRP.
Kathleen Kinney: I have some sources on renewable hydrogen gas you can email me
about. We will email you. Renewable natural gas will be discussed in the next TAC
meeting.
Amy Wheeless: I acknowledge the conundrum. Did you reach out to the renewable
hydrogen alliance? We did not. We used Black & Veatch last time. Also had comments
from a vendor on gas turbine retrofits for hydrogen gas.
Matt Nykiel (Slide 3): Can you explain what in the analysis that caused gas prices to
increase. 2020 is an estimate of 2022. Mostly inflation and the price of gas. They are
effectively the same.
Matt Nykiel (Slide 10): What is the northwest for solar? Southern Idaho? Are we
looking at Idaho? Southern Idaho or Oregon with a BPA wheel to get to Avista. We are
indifferent on location, this is showing the costs and benefits of solar in a better location.
Jørgen Rasmussen: Is liquid air storage included? Yes, see slide 7, we are modeling it
again. It was selected in the last plan.
Thomas Dempsey: We will be reviewing the liquid air energy storage costs further in
this plan.
Review of spreadsheet with resource costs and operating characteristics:
James Gall: I’ve been involved with half a dozen RFPs. Prices vary widely and will be
different than the generic modeled prices. We are really seeking input on these costs
and assumptions.
Vlad Gutman-Britten: Environmental burdens are a wider scope, not just greenhouse
gas emissions.

Washington Vulnerable Populations and Highly Impacted Communities – James
Gall
James Gall: Vulnerable populations consider socioeconomic factors and income
sensitivity factors. Avista already recognizes that nearly half of our territory is low
income and we are economically involved in our communities. This part of CETA is
currently in the rule-making process. We hope the TAC and other advisory groups will
help guide us in how to address these new requirements. It is possible a new advisory
group is needed or we may get more participants in the current TAC or another group.
Avista Corp.2021 Electric IRP Appendices 93
11

We need to gather more data and better understand our baseline – where are they at
today? The Washington State disparities map rates each census tract between 1 and
10 for socioeconomic factors which seems to align with the proposed rules. We are
proposing score of 8 or higher to be considered vulnerable or impacted. We will overlay
this on our service territory, noting that Idaho is not subject to CETA. There are
overlapping service territories with other utilities in some of the vulnerable areas.
Average use per customer – two sets and compare how they change over time. We use
that information to estimate how costs can change over time. Whether or not customers
have more than 6% of their income goes toward energy. Should the IRP have a
monetary preference for these areas, no preference, or no additional preferences?
Reliability/Resiliency metrics are available by feeder. We can show this at a future TAC
meeting and compare to the remaining areas. There is a challenge for how this relates
to the IRP. For Resource analysis, we can estimate emissions from our facilities located
near or removed from these areas. If a new resource, we can discuss how those may
change in those areas. Energy security is challenging. The grid works together for the
benefit of all customers, not necessarily for certain populations.
Kate Griffith: Regarding DOH map. The state Environmental Justice Taskforce is
working on guidance as the mapping tool is being developed among other tasks. They have regular meetings. More info is here:
https://healthequity.wa.gov/TheCouncilsWork/EnvironmentalJusticeTaskForceInformatio
n.

Vlad Gutman-Britten: Note that the tracts aren't categorized in a population weighted
way, so the three most impacted deciles of tracts may not correspond to the three most
impacted deciles of people.

Jennifer Snyder (Slide 7): No good updates to add [concerning the identification of highly impacted communities or vulnerable populations].

Amy Wheeless: How do you define community? Identified by census tract, so each
colored area in Slide 10 is a community.
Vlad Gutman-Britten: It would be helpful to understand how community compares to
population and customer share and load share. Excellent questions. We’re going to get
to that in metrics.

Shawn Bonfield (Slide 14): What do the figures on the map represent? The numbers
are census tracts and the darker shaded areas are more vulnerable.

Kate Griffith: Do you have a sense for the particular sensitivity factors in Spokane? I
apologize, I mean the issues they face such as low birth rates, etc. I don’t know that
information.

Avista Corp.2021 Electric IRP Appendices 94
12

Vlad Gutman-Britten: The Department of Health map provides component scores, in
addition to the rolled up score. Thank you.

Amy Wheeless: Some of the CAP [Community Action Partnership] agencies may be
able to provide more qualitative information.

Vlad Gutman-Britten: Yes, monetary preference and extra inducements are important
and would go toward equalizing going forward since they haven’t received these
resources in the past. Equity is worthwhile to perform and pursue. How much is
required? Think about what will be necessary for success.
Kate Griffith: How is Avista working to contact and engage with these communities
around planning? Have you started reaching out to these groups or communities? We
need direction. Are these separate advisory groups. We have had some participation in
the past on the TAC from tribes and SNAP. They are not always able to attend. We
need to reach out to public officials in these areas and need more outreach and
opportunities to include these groups. More to come on this.
Jennifer Snyder: What metrics make sense? It would be helpful to have more
representation from these groups for these particular committees to understand what
issues to address.
Corey Dahl: I’ll second conducting outreach. What does it look like? How to address equity? The company has both an obligation to select the lowest cost resource, but a
need to comply. Example off the top of my head not sure if real. Natural gas generation
facility goes offline and is replaced with solar benefits to the surrounding community, but
also benefits of transmission. But jobs are lost.
Jennifer Snyder: What type of long- and short-term public health benefits have you
looked at? Potentially for DSM and supply-side resources? Example, wood smoke in
energy efficiency. Including things from a TRC point of view. Concentrate on emissions
with existing generation. Are there others?
Jennifer Snyder: There are things we didn’t take into consideration prior to CETA, but
we should. There are a lot of health benefits in some jurisdictions. Not in Washington
yet, but new things not taken into account before CETA.
James Gall: One other is interplay of gas and electric service territory.
Amy Wheeless: The past few slides spurred a lot of thoughts. I’m not really involved
with the CETA rulemaking. Great questions to bring forward. Seek potential future and
get cost benefits.

Avista Corp.2021 Electric IRP Appendices 95
13

James Gall: Can look at distribution or opportunities that might be higher cost, but see
what those costs might be. The topic will come up again to show some of these metrics.
Let John [Lyons] or myself know of any thoughts you have.

Kate Griffith: Are these the metrics you’re planning to bring into the CEIP? So far. We
may have additional metrics later with input. Meaningful and calculable metrics for a
more useful set of data.
Kate Griffith: You mentioned quantifiable, but non quantifiable is also a big piece of this
so I’d be interested to hear more about incorporation of less measurable equity
measures. We are looking for any ideas we can look at.

Meeting adjourned.

Avista Corp.2021 Electric IRP Appendices 96

2021 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 2 Agenda
Thursday, August 6, 2020 Virtual Meeting- 9:00 AM PST

Topic Time Staff
Introductions & IRP Process Updates 9:00 Lyons
Natural Gas & RNG Market Overview 9:30 Pardee
Break 10:45
Natural Gas Price Forecast 11:00 Brutocao
Lunch 11:30
Upstream Natural Gas Emissions 12:30 Pardee
Break 1:30

Regional Energy Policy Update 1:45 Lyons
Natural Gas and Electric Coordinated 2:15 Gall/Pardee
Study
Highly Impacted & Vulnerable Populations 3:00 Gall
Baseline Analysis
Adjourn 3:45
Avista Corp.2021 Electric IRP Appendices 97
2021 Electric and Natural Gas IRPs
TAC Introductions and IRP Process
Updates
John Lyons, Ph.D.
Second Technical Advisory Committee Meeting
August 6, 2020
Avista Corp.2021 Electric IRP Appendices 98
Updated Meeting Guidelines
•Gas and electric IRP teams working remotely, but still
available by email and phone for questions and
comments
•Some processes are taking longer remotely
•Virtual IRP meetings until back in the office and able to
hold large group meetings
•TAC presentations, notes, work plans and past IRPs are
posted on joint IRP page for gas and electric:
https://www.myavista.com/about-us/integrated-resource-
planning
2 Avista Corp.2021 Electric IRP Appendices 99
Virtual TAC Meeting Reminders
•Please mute mics unless speaking or asking a question
•Use the Skype chat box to write questions or comments
or let us know you would like to say something
•Respect the pause
•Please try not to speak over the presenter or a speaker
who is voicing a question or thought
•Remember to state your name before speaking for the
note taker
•This is a public advisory meeting –presentations and
comments will be recorded and documented
3 Avista Corp.2021 Electric IRP Appendices 100
Integrated Resource Planning
•Required by Idaho, Oregon and Washington* every other
year
•Guides resource strategy over the next twenty + years
•Current and projected load & resource position
•Resource strategies under different future policies
–Resource choices
–Conservation measures and programs
–Transmission and distribution integration for electric
–Gas distribution planning
–Gas and electric market price forecasts
•Scenarios for uncertain future events and issues
•Key dates for modeling and IRP development are
available in the Work Plans
4 Avista Corp.2021 Electric IRP Appendices 101
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
–Help with soliciting new members
•Open forum while balancing need to get through all of the topics
•Welcome requests for studies or different assumptions.
–Time or resources may limit the number or type of studies
–Earlier study requests allow us to be more accommodating
–August 1, 2020 was the electric study request deadline
•Planning teams are available by email or phone for questions or
comments between the TAC meetings
5 Avista Corp.2021 Electric IRP Appendices 102
2020 Electric IRP Meetings – IPUC
•AVU-E-19-01 https://puc.idaho.gov/case/Details/3633
•Telephonic public hearing on August 5, 2020
•August 19, 2020 comment deadline, September 2, 2020 response
•Overview of topics discussed at July 9, 2020 virtual public workshop:
–Moving away from coal
–Cost impacts for Idaho customers from Washington laws
–IRP procedural questions about acknowledgment of the IRP
–Climate change questions and timing of actions
–Colstrip: decommissioning, other owners, cost sharing with Washington
–Consideration of social costs/externalities and public health
–Support for clean energy and Commission authority to require it
–Resource timing
–Risks considered in the IRP: economic, qualitative and climate
–Idaho versus Montana wind locations
–Maintaining Idaho RECs
–Climate change law applicability and lawsuits6Avista Corp.2021 Electric IRP Appendices 103
2021 Natural Gas IRP TAC Schedule
•TAC 1: Wednesday, June 17, 2020
•TAC 2: Thursday, August 6, 2020 (Joint with Electric TAC)
•TAC 3: Wednesday, September 30, 2020
•TAC 4: Wednesday, November 18, 2020
•TAC 5: February 2021 –TAC final review meeting if necessary
•Natural Gas TAC agendas, presentations and meeting minutes
available at: https://myavista.com/about-us/integrated-resource-
planning
7 Avista Corp.2021 Electric IRP Appendices 104
2021 Electric IRP TAC Schedule
•TAC 1: Thursday, June 18, 2020
•TAC 2: Thursday, August 6, 2020 (Joint with Natural Gas TAC)
•Economic and Load Forecast, August 2020
•TAC 3: Tuesday, September 29, 2020
•TAC 4: Tuesday, November 17, 2020
•TAC 5: Thursday, January 21, 2021
•Public Outreach Meeting: February 2021
•TAC agendas, presentations and meeting minutes available at:
https://myavista.com/about-us/integrated-resource-planning
8 Avista Corp.2021 Electric IRP Appendices 105
Process Updates
Economic and load forecast delay
•Special meeting 1:00 –3:30 pm PST on Tuesday, August 18 or
Wednesday, August 19, 2020 to cover the forecasts
AEG Conservation Potential Assessment and Demand
Response Studies –delayed from TAC 2
•AEG has developed baseline assumptions, market profiles and
energy/gas use per customer
•Market data has been collected and compiled
•Measure Assumption development is complete
•Compiled 2021 Power Plan Assumptions
•Measure List is in-process and is expected to be available mid-
September
•CPA discussion with TAC –September TAC meeting.
9 Avista Corp.2021 Electric IRP Appendices 106
Today’s TAC Agenda
9:00 –Introductions & IRP Process Updates, Lyons
9:30 –Natural Gas & RNG Market Overview, Pardee
10:45 –Break
11:00 –Natural Gas Price Forecast, Brutocao
11:30 –Lunch
12:30 –Upstream Natural Gas Emissions, Pardee
1:30 –Break
1:45 –Regional Energy Policy Update, Lyons
2:15 –Natural Gas and Electric Coordinated Study, Gall/Pardee
3:00 –Highly Impacted & Vulnerable Populations Baseline
Analysis, Gall
3:45 –Adjourn
10 Avista Corp.2021 Electric IRP Appendices 107
Natural Gas Market Overview
Tom Pardee, Natural Gas Planning Manager
Second Technical Advisory Committee Meeting
August 6, 2020
Avista Corp.2021 Electric IRP Appendices 108
Units
Common Gas Units
1 Bcf 1 Dth 1 Therm
kWh 302,062,888 293.001 29.300
MWh 302,063 0.293 0.029
2 Avista Corp.2021 Electric IRP Appendices 109
Avista Electric Territory
Avista Natural Gas Territory
Station 2
AECO
Sumas
Malin
Electric Power Plants
Northwest Pipeline
Gas Transmission NetworkKingsgate
Receipt Point
Jackson Prairie Storage (LDC Owned)
Stanfield
NGTL System
(Production and
Gathering
Systems)
2 Avista Corp.2021 Electric IRP Appendices 110
Avista’s Supply
•Natural Gas LDC Side
–10% contracted from US supply basins
–90% contracted from Canadian supply basins
•Electric Side
–100% contracted from Canadian supply basins
2 Avista Corp.2021 Electric IRP Appendices 111
US Demand
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040
%
o
f

D
e
m
a
n
d
% US Gas Demand
Residential Commercial Industrial Power LNG Exports Net Mexican Exports Transport Other
0
20
40
60
80
100
120
140
2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040
bc
f
d
US Gas Demand
Residential Commercial Industrial Power LNG Exports Net Mexican Exports Transport Other
Source: Wood Mackenzie2Avista Corp.2021 Electric IRP Appendices 112
US Supply
0
20
40
60
80
100
120
140
2010 2013 2016 2019 2022 2025 2028 2031 2034 2037 2040
bc
f
d
US Gas Supply
Production Canadian Net Imports LNG Imports
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
bc
f
d
Rockies San Juan Gulf Coast Gulf of Mexico
Permian Fort Worth Northeast West Coast
Alaska Mid-Continent
Source: Wood Mackenzie2Avista Corp.2021 Electric IRP Appendices 113
Canadian Supply and Demand
0
5
10
15
20
25
30
2010 2013 2016 2019 2022 2025 2028 2031 2034 2037 2040
bc
f
d
Canadian Gas Demand
Residential Commercial Industrial Power
LNG Exports Piped exports Transport Other
88%
90%
92%
94%
96%
98%
100%
2011 2014 2017 2020 2023 2026 2029 2032 2035 2038
bc
f
d
Canadian Supply
WCSB Eastern Canada
Source: Wood Mackenzie2Avista Corp.2021 Electric IRP Appendices 114
2 Avista Corp.2021 Electric IRP Appendices 115
-
5
10
15
20
25
30
35
Bc
f
pe
r

D
a
y
North American LNG Exports
Cove Point Elba Island Sabine Pass Cameron
Freeport Corpus Christi Golden Pass Calcasieu Pass
Kenai Woodfibre LNG LNG ELA Generic LNG ETX Generic
LNG WLA Generic Costa Azul LNG Canada LNG Western Canada Generic9
*WM does not assume Jordan Cove will enter service within forecasted period Source: Wood Mackenzie
Avista Corp.2021 Electric IRP Appendices 116
West
2020 H1
Census Region Map
Note: Pacific does not include Alaska or Hawaii
-
2.00
4.00
6.00
8.00
10.00
12.00
14.00
16.00
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
Bc
f
pe
r

D
a
y
Total Demand by Census Region
Mountain Pacific
Source: Wood Mackenzie2Avista Corp.2021 Electric IRP Appendices 117
-
0.05
0.10
0.15
0.20
0.25
0.30
0.35
0.40
0.45
0.50
Bc
f

p
e
r

D
a
y
Transport
Mountain Pacific
-
0.50
1.00
1.50
2.00
2.50
3.00
Bc
f
pe
r

D
a
y
Power Generation
Mountain Pacific
Power Generation and Transport demand
Source: Wood Mackenzie2Avista Corp.2021 Electric IRP Appendices 118
-
0.20
0.40
0.60
0.80
1.00
1.20
1.40
1.60
1.80
2.00
Bc
f

p
e
r

D
a
y
Residential
Pacific Mountain
-
0.50
1.00
1.50
2.00
2.50
3.00
3.50
Bc
f

p
e
r

D
a
y
Industrial
Pacific Mountain
West demand of Res-Com-Ind
-
0.20
0.40
0.60
0.80
1.00
1.20
Bc
f

p
e
r

D
a
y
Commercial
Pacific Mountain
Port of Kalama –NW
Innovation Works
Source: Wood Mackenzie
Source: Wood Mackenzie2Avista Corp.2021 Electric IRP Appendices 119
Wood Mackenzie Disclaimer
•The foregoing [chart/graph/table/information] was obtained from the [North America Gas Service]™, a product of Wood Mackenzie.”
•Any information disclosed pursuant to this agreement shall further include the following disclaimer: "The data and information provided by Wood Mackenzie should not be interpreted as advice and
•you should not rely on it for any purpose. You may not copy or use this data and information except as expressly permitted by Wood Mackenzie in writing. To the fullest extent permitted by law,
•Wood Mackenzie accepts no responsibility for your use of this data and information except as specified in a written agreement you have entered into with Wood Mackenzie for the provision of such of such data and information
2 Avista Corp.2021 Electric IRP Appendices 120
Us Natural Gas Storage
2 Avista Corp.2021 Electric IRP Appendices 121
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
#
o
f

R
i
g
s
US Rig Count History
Oil Gas Misc15
0
100
200
300
400
500
600
700
#
o
f

R
i
g
s
Canadian Rig Count History
OIL GAS MISC
Rig Counts
Avista Corp.2021 Electric IRP Appendices 122
Production and Drilling efficiency
2 Avista Corp.2021 Electric IRP Appendices 123
Historic Cash prices
(Jan. 1997 –July 2020)
$0.00
$2.00
$4.00
$6.00
$8.00
$10.00
$12.00
$14.00
$16.00
$18.00
$20.00
$
p
e
r

M
M
B
t
u
17Avista Corp.2021 Electric IRP Appendices 124
Upstream Emissions
Tom Pardee
Avista Corp.2021 Electric IRP Appendices 125
Upstream Emissions
•Use based greenhouse gas emissions at the point of combustion
and include upstream methane emissions
•Link for Natural Gas Advisory Committee information on upstream
methane: https://www.nwcouncil.org/energy/energy-advisory-
committees/natural-gas-advisory-committee
2 Avista Corp.2021 Electric IRP Appendices 126
Global warming potential (GWP) factors for conversion
to CO2 equivalents (CO2e)
5th Assessment of the Intergovernmental Panel on Climate Change
Greenhouse Gas GWP –100 Year GWP –20 Year
CO2 1 1
CH4 34 86
N2O 298 268
https://www.c2es.org/content/ipcc-fifth-assessment-report/
Global Warming Potential
2 Avista Corp.2021 Electric IRP Appendices 127
Upstream Emissions Sources and Estimates
•Rockies emissions –The EPA estimates all leakage through a bottoms up
analysis. It will estimate leaks based on equipment operated as designed
and combines these values to determine an overall rate of 1%. The
emissions and sinks study is published yearly and will capture emissions as
they change.
•Canadian emissions (British Columbia and Alberta) –A value of 0.77% was
developed from data pertaining to the recent environmental impact studies
for the PSE Tacoma LNG plant, Kalama Manufacturing and Export Facility
and the 2019 Puget Sound Energy IRP.
2 Avista Corp.2021 Electric IRP Appendices 128
WSU Natural Gas Methane Study
•Sponsored by EDF and utilities to estimate the leakage of
distribution systems
•National project and estimated a loss of 0.1 –0.2 percent of the
methane delivered nationwide
•Western region contributes much less as compared to the East
•“Out of 230 measurements, three large leaks accounted for
50%of the total measured emissions from pipeline leaks. In these
types of emission studies, a few leaks accounting for a large
fraction of total emissions are not unusual.”
2 Avista Corp.2021 Electric IRP Appendices 129
LDC Upstream Emissions
*Avista gas purchases
An average of the total volume purchased over the past 5
years by emissions location2Avista Corp.2021 Electric IRP Appendices 130
Electric Upstream Emissions
*Avista Purchases
All firm transportation to supply gas is located in Canada2Avista Corp.2021 Electric IRP Appendices 131
Renewable Natural Gas (RNG)
2 Avista Corp.2021 Electric IRP Appendices 132
What is Renewable Natural Gas (RNG)?
Renewable
Natural Gas = Natural
Gas
2 Avista Corp.2021 Electric IRP Appendices 133
Why does RNG matter?
Climate Change Solution
•Natural gas plays critical role for meeting aggressive green house gas
(GHG) reductions goals, RNG even more so!
•Utilizes existing infrastructure
•Advantages of RNG
–“De-carbonizes” gas stream
–Gives customers another renewable choice
2 Avista Corp.2021 Electric IRP Appendices 134
Carbon Intensity
2 Avista Corp.2021 Electric IRP Appendices 135
RFS and LCFS Effect on RNG Value
RIN = renewable identification number
Source: CARB
Source: EPA2Avista Corp.2021 Electric IRP Appendices 136
What are the challenges & barriers?
•California RNG market ($30+/Dth v. $2/Dth)
–Vehicle emission incentives shut-out other potential end users
–Producers see the pot of gold in California
•Financing for producers
–RIN market is volatile
–No forward pricing for RNG RINs in carbon market
–Vehicle market may be approaching saturation in CA
–Producer/LDC partnerships may make sense
2 Avista Corp.2021 Electric IRP Appendices 137
WA RNG Report (HB 2580)
*Released December 1, 2018
WSU Energy Program, Harnessing Renewable Natural Gas for Low-Carbon Fuel: A Roadmap for Washington State
0
500,000
1,000,000
1,500,000
2,000,000
2,500,000
Cedar Hills
Landfill (King
County)
Roosevelt
Landfill
(Republic
Services)
Klickitat
County PUD
South
Treatment
Plant (King
County)
Puget Sound
Energy
Landfills Wastewater
treatment
plants
Dairy
digesters
Municipal
food waste
digesters
Food
processing
residuals
Food
processed at
compost
facilities
Landfills Wastewater
treatment
plants
Dairy
digesters
Municipal
food waste
digesters
Dth
Existing Projects
Near Term Projects
Medium Term Projects
2 Avista Corp.2021 Electric IRP Appendices 138
Total Potential Annual Production = 32 Bcf
ID RNG NREL Estimates
Source -Anaerobic MMBtu per Year
Landfills 3,712,221
6,196,531
20,220,571
-Separated Organics (Solid Waste)2,311,354
Total 32,440,676
National Renewable Energy Laboratory, NREL Biofuels Atlas
2 Avista Corp.2021 Electric IRP Appendices 139
RNG $ per Dth/MMBtu
Source: Promoting RNG in WA State
Avista Owned and Operated
ID -WA
2035 Premium
Estimate ($ / Dth)
RNG -Landfills $7 -$10
RNG -Waste Water Treatment Plants (WWTP)$12 -$22
RNG -Agriculture Manure $28 -$53
RNG -Food Waste $29 -$53
2 Avista Corp.2021 Electric IRP Appendices 140
Natural Gas IRP
A detailed level of RNG understanding and evaluation process will
be included in the Natural Gas IRP TAC #3 meeting on September
30, 2020
2 Avista Corp.2021 Electric IRP Appendices 141
Natural Gas Price Forecast
Michael Brutocao, Natural Gas Analyst
Second Technical Advisory Committee Meeting
August 6, 2020
Avista Corp.2021 Electric IRP Appendices 142
Henry Hub Expected Price Methodology
•Expected Henry Hub prices derived from a blend of forward
market prices on the NYMEX (as of 6/30/2020) and forecasted
prices from the 2020 Annual Energy Outlook (EIA) and two
consultants
2020 – 2022 2023 2024 2025 2026 – 2045
NYMEX 100%75%50%25%-
EIA/AEO -8.33%16.66%25%33.33%
Consultant 1 -8.33%16.66%25%33.33%
Consultant 2 -8.33%16.66%25%33.33%
2 Avista Corp.2021 Electric IRP Appendices 143
Henry Hub Expected Price and Forecast Blending
3 Avista Corp.2021 Electric IRP Appendices 144
Henry Hub Expected Price and Average Annual Forecasts
4 Avista Corp.2021 Electric IRP Appendices 145
Stochastic Price Forecasting Methodology
•Evaluate a set of potential future outcomes based on the
probability of occurrence
–Expected Price used as the input
–At each period, random price adjustments follow a lognormal distribution
based on the Expected Price
•It is common practice to use lognormal distributions in forecasting prices as they have
no upward bound and should not fall below zero
•A single “draw” contains a set of unique price movements
•500 (electric) and 1000 (gas) draws were evaluated
5 Avista Corp.2021 Electric IRP Appendices 146
Sample Stochastic Price Draws
6 Avista Corp.2021 Electric IRP Appendices 147
Stochastic Price Draws
7 Avista Corp.2021 Electric IRP Appendices 148
Stochastic Prices (Results from 500 Draws)
8 Avista Corp.2021 Electric IRP Appendices 149
Levelized Stochastic Prices (Results from 500 Draws)
9 Avista Corp.2021 Electric IRP Appendices 150
Stochastic Prices (Results from 1000 Draws)
10 Avista Corp.2021 Electric IRP Appendices 151
Levelized Stochastic Prices (Results from 1000 Draws)
11 Avista Corp.2021 Electric IRP Appendices 152
Prices by Gas Hub (Henry Hub Expected Price + Basis)
12 Avista Corp.2021 Electric IRP Appendices 153
Levelized Prices 2022-2041
13 Avista Corp.2021 Electric IRP Appendices 154
Levelized Prices 2022-2045
14 Avista Corp.2021 Electric IRP Appendices 155
2021 Electric IRP
Regional Energy Policy Update
John Lyons, Ph.D.
Second Technical Advisory Committee Meeting
August 6, 2020
Avista Corp.2021 Electric IRP Appendices 156
Production and Investment Tax Credits
•Production tax credit $15/MWh adjusted for inflation
($25/MWh for 2019) for 10 years for wind construction
started by 12/31/20
•Investment tax credit for new solar construction drops
from 30% in 2019
–26% in 2020
–22% in 2021
–10% from 2022 onward
•Will be watching for any possible extensions with all of
the COVID-19 proposals
2 Avista Corp.2021 Electric IRP Appendices 157
State and Provincial Policies
State/Province No Coal RPS Clean Energy/Carbon Goal
Alberta Yes Yes Yes
Arizona No Yes No
British Columbia Yes Yes Yes
California Yes Yes Yes
Colorado No Yes Yes
Idaho No No No
Montana No Yes No
Nevada No Yes Goal
New Mexico No Yes No
Oregon Yes Yes Yes
Utah No Goal No
Washington Yes Yes Yes
Wyoming No No No
3 Avista Corp.2021 Electric IRP Appendices 158
Washington
•Clean Energy Transformation Act (CETA) SB 5116:
–No coal serving Washington customers by end of 2025
–Greenhouse gas neutral by 2030, up to 20% alternative
compliance
–2% cost cap over four-year compliance period
–100% non-emitting by January 1, 2045
–Social cost of carbon for new resources
–Additional reporting and planning requirements
–Highly impacted and vulnerable community identification
and resource planning implications
–Ongoing rulemaking in various stages for planning and
reporting
4 Avista Corp.2021 Electric IRP Appendices 159
Washington
•HB 1257: Clean Buildings for Washington Act
–Develop energy performance standards for commercial buildings over
50,000 square feet (2020 –2028) “… to maximize reductions of
greenhouse gas emissions from the building sector”
–By 2022, natural gas utilities must identify and acquire all available cost-
effective conservation including a social cost of carbon at the 2.5%
discount rate.(Section 11 and 15)
–Natural gas utilities may propose renewable natural gas (RNG)
programs for their customers and offer a voluntary RNG tariff
–Building code updates to improve efficiency and develop electric vehicle
charging infrastructure
5 Avista Corp.2021 Electric IRP Appendices 160
Oregon
Executive Order 20-04
•New GHG reduction goal
–45% below 1990 levels by 2035
–80% below 1990 levels by 2050
•Directs 16 Oregon agencies to “exercise any and all authority
and discretion” to reach GHG reduction goals and “prioritize
and expedite” action on GHG reductions “to the full extent
allowed by law.”
•Agencies are working on rulemaking and implementation
SB 98
•Development of utility renewable natural gas programs
6 Avista Corp.2021 Electric IRP Appendices 161
2021 Electric and Natural Gas IRPs
Natural Gas & Electric Coordinated Scenario
James Gall/Tom Pardee
Second Technical Advisory Committee Meeting
August 6, 2020
Avista Corp.2021 Electric IRP Appendices 162
Scenario Goal
•Understand impact to electric resource planning if
customers switch from natural gas to electric service
•Scenario Proposal:
–By 2030: 50% of Washington Residential & Commercial
customers
–By 2045: 80% of Washington Residential & Commercial
customers
•Potential Scenarios:
–Hybrid natural gas/electric heat pumps
–Highly efficient technology allows for cold temperature space
heating
2 Avista Corp.2021 Electric IRP Appendices 163
Converting Natural Gas Load to Electric
Load
Natural Gas
(therms)TemperatureEnd Use Efficiency
Electric
Service
Provider
Electric
(kWh)
3 Avista Corp.2021 Electric IRP Appendices 164
WA Res/Com Natural Gas Load Forecast
4
MD
t
h
Avista Corp.2021 Electric IRP Appendices 165
Customer Penetration Forecast
0.0%
10.0%
20.0%
30.0%
40.0%
50.0%
60.0%
70.0%
80.0%
90.0%
20
2
0
20
2
0
20
2
1
20
2
1
20
2
2
20
2
2
20
2
3
20
2
3
20
2
4
20
2
4
20
2
5
20
2
5
20
2
6
20
2
6
20
2
7
20
2
7
20
2
8
20
2
8
20
2
9
20
2
9
20
3
0
20
3
0
20
3
1
20
3
1
20
3
2
20
3
2
20
3
3
20
3
3
20
3
4
20
3
4
20
3
5
20
3
5
20
3
6
20
3
6
20
3
7
20
3
7
20
3
8
20
3
8
20
3
9
20
3
9
20
4
0
20
4
0
20
4
1
20
4
1
20
4
2
20
4
2
20
4
3
20
4
3
20
4
4
20
4
4
20
4
5
20
4
5
% Natural Gas Customer Reduction (WA Only)
5 Avista Corp.2021 Electric IRP Appendices 166
End Use Efficiency
0%
20%
40%
60%
80%
100%
120%
140%
160%
Water Heat Space Heat Process
Efficiency @ 5 Degrees
0%
20%
40%
60%
80%
100%
120%
140%
160%
Water Heat Space Heat Process
Efficiency @ 35 Degrees
Water Heat, 10.0%
Space Heat, 85.0%
Process, 5.0%
Water Heat, 30.0%
Space Heat, 60.0%
Process, 10.0%
Note: All efficiency conversion use a 10% efficiency benefit to electric
6 Avista Corp.2021 Electric IRP Appendices 167
Energy Conversion Factor
y = -3E-06x4 + 0.0007x3 -0.0438x2 -0.7097x + 259.49
R² = 0.9775
0
50
100
150
200
250
300
-20 0 20 40 60 80 100
Use
temperature
point
estimates
for
conversion
efficiency
Curve fit to
smooth out
steps
7 Avista Corp.2021 Electric IRP Appendices 168
WA Res/Com Natural Gas Load Forecast
8
MD
t
h
Avista Corp.2021 Electric IRP Appendices 169
Electric Peak Estimation Methodology
•Natural gas is typically daily nominations, while electric is
instantaneous.
–Hourly flow metering is available for some areas
•Sampled large gate-station hourly instantaneous natural
gas flow data
•Use sample data to estimate hourly natural gas load
from 2015-2019
•Estimate Peak-to-Energy load factor for each historical
month
•Use average monthly load factor for the peak adjustment
9 Avista Corp.2021 Electric IRP Appendices 170
Estimated Load Factors (2015-19)
10 Avista Corp.2021 Electric IRP Appendices 171
Hourly Electric Load History
-
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
5,000
Me
g
a
w
a
t
t
s
2015-2019 Control Area Load + WA LDC as Electric
CA Load + NG Control Area Load
11 Avista Corp.2021 Electric IRP Appendices 172
Eastern Washington Electric Service
Providers
EIA reported retail sales for 2018
Scenario assumes Avista will receive 75 percent of electric conversions
12 Avista Corp.2021 Electric IRP Appendices 173
Annual Conversion Load Forecast
-
100
200
300
400
500
600
700
800
900
1,000
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Annual Avg Peak
13
2020 IRP Forecast for 2030 absent fuel conversion:
Peak: 1,762 MW
Energy: 1,209 aMWAvista Corp.2021 Electric IRP Appendices 174
2030 Monthly Load Forecast
-
50
100
150
200
250
300
350
400
450
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Energy Peak
14 Avista Corp.2021 Electric IRP Appendices 175
Scenario Analysis-Conversion Rates
0
50
100
150
200
250
300
-20 0 20 40 60 80 100
Current Technology
Hybrid Future
High Efficiency Future
15 Avista Corp.2021 Electric IRP Appendices 176
Scenario Analysis- Electric Energy
16
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
Avista Corp.2021 Electric IRP Appendices 177
Scenario Analysis: Electric December
Peak Load
17
Me
g
a
w
a
t
t
s
Avista Corp.2021 Electric IRP Appendices 178
Scenario Analysis: Natural Gas Demand
18
MD
t
h
Avista Corp.2021 Electric IRP Appendices 179
Next Steps
•Input into PRiSM model to determine resource
selection and cost
–Estimate cost meeting CETA requirements
–Estimate cost using least cost methodology
–Estimate emissions savings
–Estimate $/tonne
•Conduct electric resource adequacy study if time
permits
19 Avista Corp.2021 Electric IRP Appendices 180
2021 Electric IRP
Washington Vulnerable Populations &
Highly Impacted Communities
James Gall, IRP Manager
Second Technical Advisory Committee Meeting
August 6, 2020
Avista Corp.2021 Electric IRP Appendices 181
Identifying Communities or “Customers”
Highly Impacted
Communities
–Cumulative Impact Analysis
–Tribal lands
•Spokane
•Colville
–Locations should be available
by end of 2020
•State held workshops in
August & September 2019
Vulnerable
Populations
–Use Washington State Health
Disparities map
•What is disproportionate on a
scale of 1 to 10?
•Avista proposes areas with a
score 8 or higher in either
Socioeconomic factors or
Sensitive population metrics
–Should we include other
metrics to identify these
communities?
2 Avista Corp.2021 Electric IRP Appendices 182
Environmental Health Disparities Map
https://fortress.wa.gov/doh/wtn/wtnibl/
Department of Health data is divided up by Federal Information Processing Standards (FIPS) Code
3 Avista Corp.2021 Electric IRP Appendices 183
Environmental Health Scoring
From WA Department of Health
Circle areas match definition of
vulnerable population,
although access to food &
health care, higher rates of
hospitalization are not
expressively included but are
an indication of poverty
4 Avista Corp.2021 Electric IRP Appendices 184
Selected Vulnerable Populations
5
Data is shown
by combined
score
“Large” Resource
Legend
Natural Gas
Biomass
Hydro
Wind
Solar
Kettle Falls CT
Kettle Falls
Little Falls Long Lake
Nine Mile
Palouse
Rattlesnake Flat
Adams Neilson
Northeast
Boulder ParkMonroe St
Upper Falls
Post Falls
Avista Corp.2021 Electric IRP Appendices 185
Spokane Area “Avista” Vulnerable
Populations
6
Data is shown
by combined
score
Resource Legend
Natural Gas
Biomass/Other
Hydro
Wind
Solar
Waste-to-Energy (QF)
Upriver (QF)Boulder Park
BP Community Solar
Northeast
Monroe Street
Upper Falls
Avista Corp.2021 Electric IRP Appendices 186
IRP Metrics (From Last TAC Meeting)
Metric IRP Relationship
Energy Usage per Customer •Expected change taking into account selected energy
efficiency then compare to remaining population.
•EE includes low income programs and TRC based
analysis which includes non-economic benefits.
Cost per Customer •Estimate cost per customer then compare to
remaining population.
•How do IRP results compare to above 6% of income?
Preference •Should the IRP have a monetary preference?
•For example-should all customers pay more to
locate assets (or programs) in areas with
vulnerable populations or highly impacted
communities?
•If so, how much more?
7 Avista Corp.2021 Electric IRP Appendices 187
IRP Metrics (From Last TAC Meeting)
Metric IRP Relationship
Reliability
•SAIFI: System Average Interruption
Frequency Index
•MAIFI: Momentary Average Interruption
Frequency Index
•Calculate baseline for each distribution feeder and
match with communities
•Estimate benefits for area with potential IRP
distribution projects
•Compare to other communities as baseline
•May be more appropriate in Distribution plan rather
than IRP
Resiliency:
•SAIDI: System Average Interruption Duration
Index
•CAIDI: Customer Average Interruption
Duration Index
•CELID: Customer’s Experiencing Long
Duration Outages
Resource Analysis •Estimate emissions (NOX,SO2, PM2.5, Hg) from
power projects located in/near identified communities
•Identify new resource or infrastructure project
candidates with benefit to communities; i.e. economic
benefit, reliability benefit
•Identify how resource can benefit energy security
8 Avista Corp.2021 Electric IRP Appendices 188
Energy Use Analysis Results
•Uses five years of customer billing data
•Median income over the same period is used to estimate
affordability
•Separated electric only vs electric/gas customers
–Future enhancement include single/multi family homes, and
manufactured homes
9 Avista Corp.2021 Electric IRP Appendices 189
Energy/Cost Analysis
Electric Only Customers
Natural Gas/Electric Customers
Note: Combined natural gas/electric homes have higher energy burden due to
fewer multifamily homes included in the population or all electric home including
homes with alternative heat such as wood, propane, oil, pellets. Future analysis
needed to validate this hypothesis.10
Area Fuel Type Energy Use Avg Bill Income % Income
Vulnerable Population Areas Electric 820 KWh $80
Other Areas Electric 875 KWh $84
Vulnerable Population Areas Gas 52 Therms $47 $44,889 3.4%
Other Areas Gas 62 Therms $56 $68,250 2.5%
Area Fuel Type Energy Use Avg Bill Income % Income
Vulnerable Population Areas Electric 998 KWh $98 $42,730 2.8%
Other Areas Electric 1,010 KWh $100 $58,834 2.0%
Note: Mean energy use is statistically significantly different when removing energy use data below 100 kWh per month (1,049 kWh vs 1,082 kWh)
Avista Corp.2021 Electric IRP Appendices 190
Vulnerable Populations
Electric Only Customers-Energy % of Income
11
Spokane Area
Avista Corp.2021 Electric IRP Appendices 191
Vulnerable Populations
Gas/Electric Only Customers-Energy % of Income
12
Spokane Area
Avista Corp.2021 Electric IRP Appendices 192
Reliability Data- CAIDI
Measure of resilience-minutes of outages per event
Excludes Major Event Days (MED)
13 Avista Corp.2021 Electric IRP Appendices 193
Reliability Data-CEMI
Measure of reliability-Events per Customer
14 Avista Corp.2021 Electric IRP Appendices 194
Vulnerable Area vs Non Vulnerable Areas
Vulnerable Areas
Non-Vulnerable Areas
CAIDI CEMI
15 Note: 5 yr Average differences are statistically significantly differentAvista Corp.2021 Electric IRP Appendices 195
CAIDI- By Feeder Type
Note: Avista has no
vulnerable areas with
urban feeders
16 Avista Corp.2021 Electric IRP Appendices 196
CEMI- By Feeder Type
Mixed Feeders
Vulnerable Areas
Non-Vulnerable Areas
Rural Feeders
Vulnerable Areas
Non-Vulnerable Areas
Note: Avista has no
vulnerable areas with
urban feeders
17 0.0
1.0
2.0
3.0
4.0
5.0
2015 2016 2017 2018 2019 5 yr Avg
Ev
e
n
t
s
Suburban Feeders
Avista Corp.2021 Electric IRP Appendices 197
Avista’s Washington Power Plant Air
Emissions
-
0.5
1.0
1.5
2.0
2.5
3.0
2015 2016 2017 2018 2019
Washington NOx Emissions
-
0.005
0.010
0.015
0.020
0.025
0.030
2015 2016 2017 2018 2019
Washington SO2 Emissions
-
0.00001
0.00001
0.00002
0.00002
0.00003
0.00003
0.00004
0.00004
0.00005
0.00005
2015 2016 2017 2018 2019
Washington Hg Emissions
-
0.050
0.100
0.150
0.200
0.250
0.300
2015 2016 2017 2018 2019
Washington VOC Emissions
18 Avista Corp.2021 Electric IRP Appendices 198
TAC Input
•What other metrics can we provide in an IRP to
show vulnerable populations and highly
impacted communities are not harmed by the
transition to clean energy
19 Avista Corp.2021 Electric IRP Appendices 199
Second Technical Advisory Committee Meeting, Thursday, August 6, 2020
Virtual Attendees: James Gall, Lori Hermanson, John Lyons, Tom Pardee, Rachelle
Farnsworth, Greg Nothstein, Dainee Gibson, John Chatburn, Mike Morrison, Terri
Carlock, James McDougall, Michael Brutocao, Paul Kimball, State of Idaho (x2), Steve
Vincent, Nikita Bankoti, Chip Estes, Joana Huang (UTC), Terrence Browne, Leona
Haley, Jody Morehouse, Scott Kinney, Corey Dahl, Katie Pegan, Sellers-Vaughn
(Casc); Joni Bosh, Devin McGreal, Vlad Gutman-Britten; Steven Simmons, Jennifer
Snyder, Morgan Brummund, Max St. Brown (OPUC), Jorgen Rasmussen, Jorgen;
Heutte, Fred Heutte (NWEC); Sudeshna Pal (CUB), Brian Robertson, A. Argetsinger,
Guest (18), Kaylene Schultz, Grant Forsyth, Anna Kim (OPUC), Dan Kirschner, Katie
Ware, Matt Nykiel, Ken Ross, Ashton Davis, and Steve Johnson (UTC).
Notes in italics are short responses from the presenters and notes with brackets [ ] and
times after them were pulled from the chat function on Skype.
Introductions and IRP Process Updates, John Lyons
Matt Nykiel: What is the study request deadline for gas?
Tom Pardee: No formal deadline. Feel free to forward to me. We will be running gas
models after this meeting and they will presented at TAC 3. Gas will show CPA results
at the November meeting, but will share some things earlier such as measure list.
Natural Gas & Renewable Natural Gas Market Overview, Tom Pardee
Matt Nykiel: Since Avista gets a lot of gas from Canada, how is legislation impacting
pricing and imports? Do you have general thoughts on this?
Tom Pardee: Haven’t heard of that. Wood-Mac does include legislation in their
fundamentals based forecast. What does the legislation entail?
Matt Nykiel: Carbon tax on gas essentially. How is this impacting the market in Canada
and what we get from them, the reverberating impacts to price? It is important to keep
on our radar as we’re evaluating for Avista.
Tom Pardee: Yes, British Columbia has a carbon tax. We will look into this specifically
and get back to the TAC.
Fred Heutte: Thanks for a very thorough survey. What are you seeing in near-term gas
prices in 1, 2, 3 years due to COVID? Rig counts are dependent on early production in particular for Canadian short-term. There are a lot of ways it could go.
Tom Pardee: Canada has the lowest marginal costs for natural gas. There are a lot of
liquids, not specifically drilling for natural gas but for oil so they need volumes to offset
the high capital. They have a low break-even cost and so much capital is already invested, so they’ll be slower to react to pricing changes than the northeast and the US.
Avista Corp.2021 Electric IRP Appendices 200
For oil or bitumen, they are based on the breakeven cost for liquids and oil. Dry gas is mostly about getting that out as cheap as possible.
Fred Heutte: That is helpful. Is Avista broadly speaking, sourced more from Alberta or
BC? What is going on in the Canadian Basin?
Tom Pardee: Alberta is mostly liquids and BC, Motney, etc. is dryer. Broadly, Avista is
AECO mostly.
Fred Heutte: So, not as much as Sumas. Thanks.

Nikita Bankoti (Slide 16, US demand): That is a lot of information to process. Seems
to be increases in LNG exports, will Avista be procuring more LNG?
Tom Pardee: Across all areas across all sectors, if you take away LNG exports, it’s
mostly staying the same. If gas started coming in large increments from Canada, that’d have a huge impact on us since we get 90% of our supply from Canada. In the US
everything is hedged financially at Henry Hub. Simple supply – Canada is king around
here, gas is cheap. Alberta is main economic driver, at least 50%. If there were an
issue, it’d come from Alberta. Does that help?
Nikita Bankoti: Yes, thank you so much.
Steve Johnson: To reduce to a more simple understanding, most of the growth in
demand will be from LNG exports.
Tom Pardee: Yes, that’s a fair statement.
Steve Johnson: There’s a lot of LNG exporters in the world. The US will become the
number one exporter if all of these planned projects come to fruition. The cost for gas
here rises and negatively impacts LNG going forward. Most investors think gas prices will stay low, therefore LNG goes forward which relieves upward price pressure on gas.
Focus on other side of the equation if LNG gas projects here go forward. Tells me a lot
of dollars think prices stay very low since if they go up projects won’t happen.
Tom Pardee: The cheaper oil is, the less likely LNG exports are wanted around the
world. Can they burn bunker oil? If oil goes high, then more demand for LNG. These are
often compared. If oil price is high, there is more demand for LNG exports. That is
where LNG comes in. History of LNG is tied to oil so oil price dictates the LNG price.
Now the linkage is broken and LNG is not as tied to oil as it was formerly. Now a LNG
rate is Henry Hub plus. If oil is expected to go up, then my guess is there’d be more LNG. If oil goes up to $120 a barrel, a lot more LNG is cheaper.
Steve Johnson: One can expect gas to remain flat?
Tom Pardee: Yes. Regardless of LNG exports.
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Nikita Bankoti: What is MSW? Municipal solid waste.
Fred Heutte: Wonder if you have been following Oregon AR632 docket for Northwest
Natural RNG policies?
Tom Pardee: Yes, we have had members go to every AR632 rulemaking. We were a
part of that. Trying to understand what the policy means. The gas side will have a more
detailed overview. I’m not an RNG expert. If you have better information into RNG price
on the east side you are always welcome to come over to our TAC.
Fred Heutte: Interesting info.
Jody Morehouse: Open rulemaking for SB passed 2 weeks ago in Oregon and were
adopted 7/31/20. Will cover more in September TAC.
Nikita Bankoti: The Commission has an ongoing docket under UG-190818 for the
Washington RNG Staff investigation.
Kathleen Kinney: Market pricing in the $10 - $12 range for RNG is doable. Utility is
able to offer a consistent long-term price.
Kathleen Kinney: Comments via RNG; for market pricing $10-12 price is doable. If
Utilities can offer a long-term prices that’s something that producers are looking for.
Another option, I haven’t seen done in person is to buy LNG at a relatively low fixed
costs until the LNG purchase requirement kick in and be able to sell long term when policies kick in. Avista can take advantage of that margin in the near-term. Again, I’m
certainly willing to connect after this.
Matt Nykiel: I could use a refresher in terms of how gas impacts customer rates and
how that is impacted through the price cost adjustment. How is the price set and passed on if higher or lower?
Tom Pardee: Within an LDC. You probably get cheap gas. Projected rate, say it’s a
dollar comes in higher, then in future rates, we’d charge more. Lower is passed through
against rate projection for the future. Pass through at the cost of gas, but procurement charge with no markup. What we buy gas for is what we sell gas to customers for with
no mark up. Optimization for Jackson Prairie or transport is for customers and goes
against rates. If we sell gas for $50,000 premium in the market, it goes against rates to
offset the commodity rate for overhead. PGA, or purchased gas adjustment is set on
November 1st. How accurate you were on every November 1st is adjusted. If too high now, it reduces rates later. It is an accounting deferral balance.
Matt Nykiel: Thanks so much, appreciate the refresher.
Natural Gas Price Forecast, Michael Brutocao
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Ben Otto: Can you tell us who the consultants are?

Tom Pardee: One is Wood-Mackenzie and the other is CERA. They are both well-
known and respected within the gas industry. We put out this way so we don’t have to
get their approval which is difficult.
Ben Otto: This highlights our concerns. It is a public process, but having stuff we can’t
comment on specifically is concerning.
Dan Kirschner: Nominal dollars? Yes.
Nikita Bankoti: Why is there a difference in percentages used? What is the reason for
blending and the mix across the years?
Michael Brutocao: Wouldn’t want to assume one is more accurate than the other.
Significant deviations in NYMEX more than accounts for risk and overtakes what you’d expect the nominal prices to be.
Nikita Bankoti: For 2023 weighting, why is NYMEX weighted more than the
consultants? Due to standard deviation?
Tom Pardee: So for historic measures, NYMEX in the near term is the best indicator of
everything that all traders know on that date. Fundamental forecasts take months.
NYMEX changes daily and is the most up to date pricing with fundamentals. NYMEX
actively trades about three-ish years out – it becomes a lot less liquid the further out you
go. Further out is less liquid so you really don’t know what the price is the further out you look.
Steve Johnson: Can I ask a follow up question? I recall these charts in the past IRPs.
Three year forecast based on forwards or combination, then we take consultants with
the forwards, update every IRP with the same upward trend further out with the same consultants. I’m not on board as we never seem to see these upward trends. It’s the
trends I’m not believing in. Will have to drop off in 10 minutes, but will circle back with
the team on this topic.
Sudeshna Pal: Is there any visibility into the forecast models and discussion into the
drivers and what is causing the trends? What are the drivers of this forecast?
Tom Pardee: Time. Known elements when putting the forecast together. For example,
one forecast may have COVID included, but an older one might not. Individual
assumptions and guessing about what may happen and when and how those impact prices. The further out you go, no one is going to be right, but they have people that
look at these issues. No one is going to be right.

Avista Corp.2021 Electric IRP Appendices 203
Ben Otto: Past two questions highlights the need to see these assumptions. Customers
end up paying for this. Important so we can see and understand. The best practice is to
disclose these forecasting techniques to understand them.
Fred Heutte: Gas future prices, NYMEX forward strip and the longer term by various
consultants. NYMEX market for today is over $2 at Henry Hub. Really liquid and a good indicator. It is the largest in the world at about $1 trillion a year, but it doesn’t go out far.
Starts with 126,000 September contracts, but down to 7,000 by February, and at 18
months almost none. Further out less and less trades yet they report prices all the way
out to 2032. Out to 18 months is very good. Longer term forecast basically take the
same view – we’ll have as much shale gas as we need forever. We don’t know the underlying production cost. Prices have been on average over the prices over the last
many years. What happens if the industry consolidates? The Wood-Mac and IHS
consultants are really smart, doing the best they can. We don’t have anything better
than long term forecasts. What is the upside price risk – that is the question. Make sure
to run a high price gas forecast if that comes to pass which is what the IRP is supposed to address.
James Gall: Appreciate the comments on the scenarios we do, which often don’t get
the focus they deserve. It is important to consider the scenarios from IRP to IRP. There
are differences in resource choices. This topic has a lot of interest.
Nikita Bankoti (slide 9): Is there a reason there’s more gas draws than electric? I
believe it is less, but am not 100% sure. What’s the reason behind that?
Tom Pardee: We do more gas draws because we can. We model on a daily basis. We
have a smaller daily model than electric, which is modeled hourly. Ours doesn’t take as
long to model. One or two days per run, and week on the electric side for one scenario
with 500 distribution draws.
Nikita Bankoti: OK, that makes sense.

Kathleen Kinney: Curious about the higher scenario above the $10-12 (tying into
RNG), is there some way to use extended RNG contracts to take out the risk?
Tom Pardee: It is something we can consider because you’re definitely taking some of
the risk out with RNG. There is a major risk of not being able to get supply. Take risk out
of a transportation pipeline. There was the explosion a few years ago on the west side.
Cost risk, loss risk and how much RNG can take off the board.
Kathleen Kinney: It would have to be a long-term contract.

Fred Heutte: Two comments. Run another version of this gas price and market price
looking at a peak of $3 shown. What about a peak of $4 with consolidation and a lower
rig count? With lower supply, prices go up. Delivery risk and questions raised by that.
Avista Corp.2021 Electric IRP Appendices 204
explosion and compressors. Has Avista looked at the risk involved with your main supply coming down from Alberta, which is very reliable? Have you looked at this risk?
Tom Pardee: Yes, we’ll talk more about supply risk from major locations at TAC 3. We
do look at it and there will be specific sensitivities around this.
Ben Otto: 100% or 90% of gas from Canada. Risk should focus on this and not
necessarily on the hubs since all supply comes from Canada. Previously you’ve shown
you only use Canadian supply.
Tom Pardee: We do use the other supply areas, although not as much. Where we have
supply from is number 1 at AECO, number 2 at Sumas for peak and Jackson Prairie,
and number 3 from Rockies for peak and Oregon. Each of these we look at to restrict or
take out of the model to understand. In the overall portfolio, Rockies in about 1-in-10
situations.
Upstream Natural Gas Emissions, Tom Pardee
Tom Pardee: Upstream emissions are natural gas emissions that occur prior to the
point of combustion.
Mike Morrison: When computing Global Warming Potentials, what were the residence
times assumed for each gas? How long are they assumed to remain in the
atmosphere?
Tom Pardee: 1 element of carbon, 1 factor of CH4 equal to 34. Continues to grow
(NOx) in the 100 year potential.
Kathleen Kinney: CH4 degrades to CO2 near-term emission and decreases as it
degrades over time.
Fred Heutte: I’m certainly not an atmospheric chemist. CO2 not very interactive
whereas methane is very interactive. For CO2, half is taken up in a year into trees,
ocean, and vegetation and the rest is over 1,000 years – impact is long. Methane –
because it’s interactive – it’s in the atmosphere for 10-12 years and gone in 20.
Nikita Bankoti: Is this a recent EP estimate?

Tom Pardee: 2020.
Dan Kirschner: April 2020 – considers through 2018.
[8/6/2020 12:44 PM] Steven Simmons: https://www.nwcouncil.org/energy/energy-
advisory-committees/natural-gas-advisory-committee
(https%3a//www.nwcouncil.org/energy/energy-advisory-committees/natural-gas-
advisory-committee) link to Northwest Power & Conservation Council work on methane
& NGAC
Avista Corp.2021 Electric IRP Appendices 205

Fred Heutte: We will be submitting comments in writing to Avista on this topic and won’t
belabor the point here. We are concerned with the emissions factor in the US and
Canada. The EDF project has been working on this issue for better than a decade.
Scientists and analysts in the US, the council adopting their low emissions rate in the
US. The problem with the Canadian sources is they are based on old data. Recent publications in peer reviewed journals will show this. Reasonable data for US-sourced
gas, but not Canadian-sourced gas which hasn’t been updated.
Dan Kirshner: We have a bit of a different perspective than Fred and will provide our
comments to the council. We support the regional approach Avista is taking as opposed to national averages. Puget Sound Clean Air Agency and the Port of Kalama data are
government sponsored and is sufficient and a good approach for Canada. We disagree
with NWEC for the Rockies. EPA has an annual update for Rockies. Each year is
appropriate in that regard. Will send a letter regarding this. There are different
perspectives on this.
Tom Pardee: Thanks Fred and Dan. The problem is Avista is not an expert on this
upstream emissions issue, but we have some expertise.
Fred Heutte: We’re not experts. Canadian FIMSA (0.78). It’s like pricing. You do as
best as you can. Appreciate there’s different perspectives. Power Council – we feel
this is the appropriate factors.
[8/6/2020 12:49 PM] Vlad Gutman-Britten: It would be useful to include at minimum a
sensitivity with a higher leakage rate to understand the impact of that choice on resource selection.
Tom Pardee: We could do this as Dan mentioned to show sensitivity. If we were to use
2.3% for Rockies, it doesn’t impact much because of how little gas we have from
there. Scenarios will likely address some of this. One scenario will be to change this fraction.
[8/6/2020 12:50 PM] Vlad Gutman-Britten: For example using EDF's number. Yes.
That would allow stakeholders to evaluate how important/not important this factor is.
Thanks very much for your consideration.

[8/6/2020 12:52 PM] Ben Otto, ICL: Agree with Vlad. For any uncertain forecast it is
good practice to assess a range of scenarios.
Fred Heutte: Some Canadian numbers are really dated and minor updates in the last
20 years.

Regional Energy Policy Update, John Lyons
Investment and production tax incentives:
Avista Corp.2021 Electric IRP Appendices 206
PTC $15/MWh (base) for 20 years for wind started by 12/31/20
ITC for solar drops 30% in 2019, 26% in 2020, 22% in 2021, 10% from 2022 on
ITC for battery storage if filled with solar
[8/6/2020 12:57 PM] Vlad Gutman-Britten: On the incentive side, are you considering
Washington state sales/use tax incentives for RE sited in the state?

James Gall: Yes we include those incentives in our Generating Resource Assumptions
sheet.
[8/6/2020 12:58 PM] Snyder, Jennifer (UTC): I thought New Mexico passed a clean
energy law. Am I mistaken?
Vlad Gutman-Britten: Yes.
Fred Heutte: Will put a link in the chat re: modeling this in Aurora from yesterday’s
NPPCC meeting. Here's the NW Council presentation and the spreadsheet. These are
downloads from the Box file sharing service:
• https://nwcouncil.app.box.com/s/s2whne2t77a1qxpm17qtz5aorwuksjil
• https%3a//nwcouncil.app.box.com/s/s2whne2t77a1qxpm17qtz5aorwuksjil)
• https://nwcouncil.app.box.com/s/po27u2275z0cuanuix6oucnw7luz62bk
• https%3a//nwcouncil.app.box.com/s/po27u2275z0cuanuix6oucnw7luz62bk)

[8/6/2020 1:03 PM] Fred Heutte (NWEC): And the System Analysis Advisory
Committee web page is here: https://www.nwcouncil.org/meeting/system-analysis-
advisory-committee-webinar-august-5-2020
https%3a//www.nwcouncil.org/meeting/system-analysis-advisory-committee-webinar-august-5-2020)
Ben Otto: Back to tax credits slide. PTC could be charged to storage if charged with
renewable. For this IRP will there be basic market power storage and renewable.
James Gall: We modeled both and treated the PTC correctly. Both technologies were
selected. One bundled with storage and selected. Storage as a standalone resource
with the credit. Both were selected.
[8/6/2020 1:05 PM] Rachelle Farnsworth: What happens to costs above 2%, and
costs for Colstrip that could occur after 2025?
James Gall: Colstrip costs from a CETA perspective. The 2% cost gap not applicable to
Colstrip since it’ll be fully depreciated by 2025
Vlad Gutman-Britten: I don’t believe the statute says for “new” resources. Can you
explain your interpretation?

Avista Corp.2021 Electric IRP Appendices 207
James Gall: Two instances 1) you’re correct, 2) for new resource decision-making.

Matt Nykiel: Can you talk more about how the social cost of carbon was analyzed –
fixed or variable cost?
James Gall: Planning on modeling social cost of carbon similarly to the expected case
in the last IRP. Model plant’s dispatch of real-time operations – new resources would
include construction and operations costs of emissions (shared at last TAC meeting).
Will be included in the optimization used to determine the least cost options. DR will be
assigned an emission benefit. Scenarios will be run for the Idaho portion to understand
the social cost of carbon implications for Idaho customers.
Nikita Bankoti: The Commission needs to update the social cost of carbon costs, it
should be updated and on the website [WUTC] soon.
Matt Nykiel: Is Avista treating SCC as a fixed or variable cost.

James Gall: Variable. There’s a price that’s fixed (construction) but also variable cost
assigned to operations.
Matt Nykiel: Can you clarify “analyzing social cost of carbon for Idaho”, clarify the
difference. I’m not totally taking up what you are putting down for Idaho.
James Gall: The social cost of carbon is included for Washington as required by law.
Scenarios for that cost for Idaho. Will discuss at next electric TAC. For the variable cost,
the price [per metric ton] of the social cost of carbon is fixed for each year, but the total cost is variable each year with the amount of emissions plus the emissions from
construction. For Washington, it is in the expected or base case and as a scenario for
Idaho.
[8/6/2020 1:12 PM] Fred Heutte (NWEC): Clarification from Joni: Hi all, Joni asked
me to pass this along (she can add more via the phone): the 2045 standard is for non-
emitting and RE.

Sec. 5. (1) It is the policy of the state that nonemitting electric generation and electricity
from renewable resources supply one hundred percent of all sales of electricity to Washington retail electric customers by January 1, 2045. By January 1, 2045, and each
year thereafter, each electric utility must demonstrate its compliance with this standard
using a combination of nonemitting electric generation and electricity from renewable
resources.
Natural Gas and Electric Coordinated Study, James Gall and Tom Pardee
James Gall: Potential scenarios – it would be helpful to have input on these; are these
the right scenarios to look at?
Fred Heutte: Heating and cooling, are you also looking at water heating?
Avista Corp.2021 Electric IRP Appendices 208
James Gall: Yes, we will get to that in a minute.
Kathleen Kinney: On the 10% efficiency, can you explain that more, is that a benefit to
electricity?
James Gall: We’re making assumptions of how folks will convert. We’re reducing
conversions by 10% in case we missed some efficiency benefits. More biased to
electric.
Fred Heutte: Have you been following Power Council and their load forecast? Are you
looking at a climate adjustment to the forecast for the substantial increase in late
summer demand?
James Gall: Yes. That is a great question for the next meeting, it will probably be a
topic at the next TAC.
Fred Heutte: Detecting a theme – lots of interesting stuff at the next meeting.
Kathleen Kinney: What portion are you assuming are heat pumps (of converted)?
James Gall: Most gas to electric is to heat pumps.
Kathleen Kinney: Is there a lower efficiency scenario too? Not everyone is going to
convert to heat pumps.
James Gall: A lot of that can be derived from showing the efficiencies at various temps.
Dan Kirschner: Baseboards are 100% efficient at site. Are you assuming at site?
James Gall: This is at the site. When building generation, we’ll have to adjust for
losses.
Jennifer Snyder: Baseboard versus heat pump idea, if someone were thinking of going
from gas to electric, most people wouldn’t go from gas to baseboard.
James Gall: Conversions currently using furnaces are often ducted or point source
heat. Homes with ducts will likely convert to heat pump. Those using point sources will
use a mix and it’s tough to determine the mix of baseboard to heat pumps.
Nikita Bankoti: Very drastic change in period, more energy use at peak, you’ll be using
a lot of different resources, will customers be charged a higher rate?
James Gall: Because of added load in the winter, what is the impact to customers?
The IRP process will illustrate the cost impact as compared with the expected changes
and also look at what the customer is avoiding on the gas side. Please look at the last
IRP where we did a similar analysis. Cost is higher, emissions are lower. Will the customer be paying more? Will depend on price of power, environmental policies, and
conversion costs (customer-borne). Lastly, we also need to address impacts on T&D –
large conversion to electric will likely require T&D incremental infrastructure costs. We
may not be able to address that in this IRP.
Vlad Gutman-Britten: Sorry, missed the first chunk of that. The idea of extra load
needs to be served with long-duration storages. CCS and RNG that can fill in that role
Avista Corp.2021 Electric IRP Appendices 209
Studies show that you can fill in the role without long-term storage. Are you looking at space and water heating?
James Gall: Looking at all end uses – water, space, process.
Vlad Gutman-Britten: In calculating peak are you incorporating latest codes?
James Gall: Yes we’re trying to estimate what the peak is, then when we pick
resources, the type of program that would reduce peak if cost effective.
Vlad Gutman-Britten: Incorporating that type of resource? Yes.
Jennifer Snyder: Are you modifying this within the CPA’s technology potential?
James Gall: Yes, since increasing the amount of water heaters on the system.
Kathleen Kinney: Could it be looked at with a cost comparison using RNG to achieve
the same emissions goal?
James Gall: Yes. Tom will have scenarios. My side will show electric and comparing
both we can come to a conclusion. Advantage of gas/electric IRP at the same time – we
can look at both.
Fred Heutte: Glad water heater load management is already addressed. With new
cross sector load on the section including electrification, if that load can be managed, it should be. To what degree have you looked at managing space heat?
James Gall: Through the CPA. Look at manageable savings we can get from our
existing load and how does that apply to this situation.
Ben Otto: Along with DR, applies to space heating load, applying a package of building
shell improvements is another way to address this issue.
James Gall: We will look to AEG for this and work with the CPA to incorporate.
Jennifer Snyder: Depending on how much you can do this in your CPA, electric house
has ability to be made tighter than gas heated house. Don’t know if that will make a
difference or if it can be captured in a CPA. Will have to get back to the group on this.
Kathleen Kinney (slide 15): I’m confused, I’m looking at the graph and it looks like
higher is more efficient.
James Gall: Less efficient the higher you go on the Y axis. More kWh used per Dth
replaced.
Sudeshna Pal: What is the current technology?
James Gall: Slides 6-7, the Base Case we already shared using current technology to
estimate future loads using more efficient technology in the future. Hybrid uses gas and
electricity more efficiently with existing technology.
[8/6/2020 2:24 PM] Vlad Gutman-Britten: I think we'll have comments on some of the
end use efficiency assumptions, but will provide those in writing.

Avista Corp.2021 Electric IRP Appendices 210
Mike Morrison (Slide 15): Dth to kWh is about 293, so what you are saying is the
hybrid future is 6 times as efficient?
James Gall: That is not what this is showing at the amount of gas in the base scenario.
We’re using electric not gas. Trying to illustrate how much gas demand will go to
electric. This may not be the best way to show that. We start with this track, but converting with simplifying, we remove space heat from the calculation. Efficiency
components are multiplied to those end uses.
Mike Morrison: Ok, so this is only in the context of the conversion you are doing. It
seems very complicated, you might have done it a simpler way.
[8/6/2020 2:28 PM] Steven Simmons: Have you thought about what might be the
implications on the gas system in these scenarios - especially the hybrid system where
you are relying on gas solely for peak days. More gas storage?
Tom Pardee: Will come out in the scenarios; maybe RNG can take some of this risk off
the system. Will circle back to the electric TAC to show the results of modeling this on
both sides.
Highly Impacted & Vulnerable Populations Baseline Analysis, James Gall:
Nikita Bankoti: Interesting to understand if company will use a map or delve into
individual household data. Interesting that resources are in these neighborhoods. What
does the company plan to do in this area regarding equity and community engagement?
Are you considering any factors and pollution burden for these indicators?
James Gall: At this time, we haven’t looked at those two items yet because it’s outside
of the law. The expectation is areas may be added, but we didn’t want to go down that
path until we get an indication from the state regarding these areas. May have low
income in areas that aren’t necessarily impacted. We have low income programs
broader than these areas. Look at how the law is written – what these areas look like today versus the future. That’s where we’re focusing right now. Looking to include these
populations in future IRPs as well as maybe programs to address these areas. There
are limited things an IRP can do. Where does the IRP apply and where do other
processes apply?
[8/6/2020 2:47 PM] Vlad Gutman-Bittmen: Given that the statute emphasizes health, I
assume you mean locating non-emitting assets in identified communities? Just a note
that not all resources that are "clean" under CETA are clean from a health perspective,
like biomass for example, but understand your point. Thank you.
James Gall: Correct.
Max St. Brown: Lot of overlap with what we’re doing for COVID and what customers
are being impacted. Is this process of linking marketing data to customer data being
documented?
Avista Corp.2021 Electric IRP Appendices 211
James Gall: No we ended up using census data for the most past and not the
marketing data. Lori Hermanson: Trove purchases data from 27 different parties and compiled income
data. We ended up using census data because the data was substantially different.
Nikita Bankoti: If you have data on average household size, can that be used?
Grant Forsyth: Yes there’s average household size from the American Community
Survey. It doesn’t go very far back, seems to be volatile and has been smoothed so much it has little variation over time. It is somewhat difficult data to work with unless you
use a 5-year moving average. You can get it down to the tract or block level, but can
you do any time analysis? 3 – 5 year average smooths things out a bit and causes
problems.
[8/6/2020 3:00 PM] Griffith, Kate (UTC): Are you able to see how this changes in
summer or winter months?
James Gall: No, only annual data is available. Will probably be a future analysis to see
from a heating versus air conditioning point of view.

Nikita Bankoti: Not a question. Just thinking if it will be easier to access and analyze
population density data (in vulnerable areas) instead of household level data.

Vlad Gutman-Britten: Is the reason for the shorter outage in vulnerable areas because
they’re urban?

James Gall: Yes, more vulnerable populations are in suburban areas. Being in the
mixed vulnerable and not vulnerable areas takes more time driving to them to fix the
outage.

Vlad Gutman-Britten: Not being accusatory, but it is not accurate to say vulnerable
areas are receiving a more resilient service because it is just in an urban area that is
easier to service?

James Gall: Wouldn’t go that far yet. The only ones that are less are rural areas. These
are very rural areas and if the analysis is by customers per mile this may be the case. It
would require more analysis and this may be the next step. Vulnerable areas seems to
have more reliability in urban areas.

[8/6/2020 3:14 PM] Vlad Gutman-Britten: Controlling resilience for customer density
does seems like a useful metric to develop to identify discrepancies. If they exist.

Avista Corp.2021 Electric IRP Appendices 212
[8/6/2020 3:15 PM] Vlad Gutman-Britten: Will you resend the deck with new slides
please?
[8/6/2020 3:15 PM] Yes, we will. Either later this week or early next at the latest.

[8/6/2020 3:18 PM] Ben Otto, ICL: Rathdrum gas power plant in Idaho is very close to
the Washington border. Is this included?
James Gall: No, it is not included in this study being it’s in Idaho.

[8/6/2020 3:19 PM] Vlad Gutman-Britten: I'm assuming this is assuming that pollution
harms accrue near a facility? This isn't based on a pollution transport model? What
about identified community down-wind even if they’re not close to a facility.
James Gall: Haven’t gotten down to that level. CS2 in Oregon and several CCCTs,
Rathdrum, Colstrip, etc. and limited thermal generation in eastern Washington. This is really only what there is in Washington.
Fred Heutte: Not that I’m an expert, but there is a good study on this from Portland
State. When you look forward to where the EV infrastructure can be placed, this is
something we should consider forward-looking.
[8/6/2020 3:24 PM] Vlad Gutman-Britten: These strike me as good metrics, but I'm
not sure the folks on the phone are necessarily well positioned to answer. That may
require proactive outreach to groups active in some of the communities you identified,
as well as Front & Centered.
Fred Heutte: CIMS or other data. Make sure to note where the data is coming from for
these studies.
Ben Otto: Super fascinating. Really good work. We’d encourage Avista to apply the
same thinking to Idaho. Just the right thing to do. Aligns with your corporate
commitments.
Vlad Gutman-Britten: Agree, its great work.
Ben Otto: This presentation has helped me understand the right questions to ask.
Nicholas: The OPUC breakout is by area (block group) of the vulnerable population.
One point of verification. Understand it as break out by area as being broadly, rather
than by meter.
James Gall: Characterized by geography. Meters in an area, but not identified if a
particular customer or not. Not necessarily every customer in that area is vulnerable.
Remind ourselves not to focus on geography when developing programs.

Avista Corp.2021 Electric IRP Appendices 213
Nicholas: Right. Thank you. Wanted to make sure. It is a challenge.

Avista Corp.2021 Electric IRP Appendices 214
Economic, Load, and Customer Forecasts
Grant D. Forsyth, Ph.D.
Chief Economist
Technical Advisory Committee Meeting
August 18, 2020
Avista Corp.2021 Electric IRP Appendices 215
Main Topic Areas
•Service Area Economy
•Long-run Energy Forecast
•Peak Load Forecast
•Long-run Gas Customer Forecast
2
Avista Corp.2021 Electric IRP Appendices 216
Service Area Economy
Grant D. Forsyth, Ph.D.
Chief Economist
[e-mail]
3
Avista Corp.2021 Electric IRP Appendices 217
Distribution of Employment, 2019
Source: BLS and author’s calculations.4
Private
Goods
14%
Private
Services
70%
Government
16%
Avista WA-ID-OR MSA
Private
Goods
14%
Private
Services
71%
Government
15%
U.S.
Federal
11%
State
20%
Local
69%
Avista WA-ID-OR MSA Government
Federal
12%
State
23%
Local
65%
U.S. Government
Avista Corp.2021 Electric IRP Appendices 218
Non-Farm Employment Growth, 2009-2020
Source: BLS, WA ESD, OR ED and author’s calculations.
-16%
-14%
-12%
-10%
-8%
-6%
-4%
-2%
0%
2%
4%
De
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-
0
7
Ap
r
-
0
8
Au
g
-
0
8
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-
0
8
Ap
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g
-
0
9
De
c
-
0
9
Ap
r
-
1
0
Au
g
-
1
0
De
c
-
1
0
Ap
r
-
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-
1
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1
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g
-
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c
-
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3
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5
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g
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-
1
5
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-
1
6
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g
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1
6
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r
-
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7
Ap
r
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Au
g
-
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c
-
1
8
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-
1
9
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9
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c
-
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r
-
2
0
Ye
a
r
-ov
e
r
-Ye
a
r
,

S
a
m
e

M
o
n
t
h

S
e
a
s
o
n
a
l
l
y

A
d
j
.
Non-Farm Employment Growth (Dashed Shaded Box = Recession Period)
Avista WA-ID-OR MSAs U.S.
Service Area employment level
same as 2013/14 period.
Avista Corp.2021 Electric IRP Appendices 219
MSA Population Growth, 2007-2019
Source: BEA, U.S. Census, and author’s calculations.
1.6%
1.2%
0.9%
0.7%
0.5%0.4%
0.7%
1.0%
1.2%
1.6%1.6%
1.5%1.5%
1.0%0.9%0.9%0.8%
0.7%0.7%0.7%0.7%0.7%0.7%0.6%0.5%0.5%
0.0%
0.5%
1.0%
1.5%
2.0%
2.5%
2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
An
n
u
a
l

G
r
o
w
t
h
Population Growth in Avista WA-ID-OR MSAs
Total WA-ID-OR MSA Pop. Growth U.S. Growth
2008-2012: Employment
Growth Slowing = Slowing
In-migration
2013-2019: Employment
Growth Increasing =
Increasing In-migration
Avista Corp.2021 Electric IRP Appendices 220
GDP Growth Assumptions: 2021 IRP vs. 2020 IRP
7 Source: Various and author’s calculations.
-8.0%
-6.0%
-4.0%
-2.0%
0.0%
2.0%
4.0%
6.0%
2020 2021 2022 2023 2024 2025
An
n
u
a
l

G
r
o
w
t
h
Average June 2019 Forecast Current Forecast Average
Avista Corp.2021 Electric IRP Appendices 221
Long-Term Energy Load Forecast
Grant D. Forsyth, Ph.D.
Chief Economist
[e-mail]
8
Avista Corp.2021 Electric IRP Appendices 222
Basic Forecast Approach
2020
Time
2025 20452026
1)Monthly econometric model by
schedule for each class.
2)Customer and UPC forecasts.
3)20-year moving average for “normal
weather.”
4)Economic drivers: GDP, industrial
production, employment growth,
population, price, natural gas
penetration, and ARIMA error
correction.
5)Native load (energy) forecast derived
from retail load forecast.
6)Current forecast is the “Summer/Fall
Forecast” done in June.
1)Boot strap off medium term forecast.
2)Apply long-run load growth relationships to
develop simulation model for high/low
scenarios.
3)Include different scenarios for renewable
penetration with controls for price elasticity,
EV/PHEVs, and natural gas penetration.
Medium Term Long Term
9
Avista Corp.2021 Electric IRP Appendices 223
The Long-Term Relationship, 2021-2045
Load = Customers Χ Use Per Customer (UPC)
Load Growth ≈ Customer Growth + UPC Growth
Assumed to be same as population
growth for residential after 2025,
commercial growth will follow
residential, and slow decline in
industrial.
Assumed to be a function of
multiple factors including
renewable penetration, gas
penetration, and
EVs/PHEVs.
10
Avista Corp.2021 Electric IRP Appendices 224
Residential Customer Growth, 2020-2045
0.40%
0.50%
0.60%
0.70%
0.80%
0.90%
1.00%
1.10%
1.20%
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Annual Residential Customer Growth Rates
2021 IRP Residential Customer Growth 2020 IRP Residential Customer Growth
Medium Term Long Term
Average annual growth rate from
2021-2045 = 0.8%. Shape of
time-path mimics a combination
of IHS (ID) and OFM (WA)
population forecasts.
11
Avista Corp.2021 Electric IRP Appendices 225
Residential Solar Penetration, 2008-2019
0.00%
0.05%
0.10%
0.15%
0.20%
0.25%
0.30%
0.35%
305,000 310,000 315,000 320,000 325,000 330,000 335,000 340,000 345,000 350,000
Sh
a
r
e

o
f

R
e
s
i
d
e
n
t
i
a
l

S
o
l
a
r

C
u
s
t
o
m
e
r
s

t
o

T
o
t
a
l

R
e
s
i
d
e
n
t
i
a
l

Cu
s
t
o
m
e
r
s
Customers
Customer Penetration vs. Customers Since 2008
12
2014
2015
2016
2017
2018
2008
2019
Avista Corp.2021 Electric IRP Appendices 226
Residential Solar Penetration, 2021-2045
0
2,000
4,000
6,000
8,000
10,000
12,000
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
To
t
a
l

P
V

C
u
s
t
o
m
e
r
s
Projected Base-Line Residental Solar Customers
2021 IRP Base-Line Residential Solar Customers 2020 IRP Base-Line Residential Solar Customers13
Current penetration is 0.3% and typical
size is 7,800 watts. By 2045, penetration
will be near 2.6% of residential customers
and average size of installed systems will
be over 10,000 watts.
Avista Corp.2021 Electric IRP Appendices 227
Residential EVs/PHEVs, 2021-2045
0
20,000
40,000
60,000
80,000
100,000
120,000
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
To
t
a
l

E
V
s
/
P
H
E
V
s
Projected Residental EVs/PHEVs
2020 IRP Projected EV/PHEV 2021 IRP Projected EV/PHEV
2020 ≈ 2,000
14
2045 ≈ 107,000
Avista Corp.2021 Electric IRP Appendices 228
Net Solar and EV/PHEV Impact, 2021-2045
-5
0
5
10
15
20
25
30
35
40
45
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
Average Megawatt Impact of Solar and EV/PHEV
2021 IRP Solar aMW (Load Reduction)2021 IRP EV/PHEV aMW (Load Addition)2021 Net IRP Solar and EV/PHEV Impacts aMW15
Avista Corp.2021 Electric IRP Appendices 229
Native Load Forecast, 2021-2045
1,000
1,050
1,100
1,150
1,200
1,250
1,300
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
Total Native Load Forecast, Average Megawatts
2021 IRP Base-Line Native Load 2020 IRP Base-Line Native Load
EV/PHEV “Bend”
IRP Avg. Annual
Growth
2020 IRP 0.3%
2021 IRP 0.3%
Medium Term Long Term
16
Avista Corp.2021 Electric IRP Appendices 230
Climate Change: A Trended 20-year Moving
Average (Preliminary!)
17
5,000
5,500
6,000
6,500
7,000
7,500
1965 1969 1973 1977 1981 1985 1989 1993 1997 2001 2005 2009 2013 2017 2021 2025 2029 2033 2037 2041 2045
HD
D
20-yr MA HDD
Annual 20-yr MA, Avista Trend Annual 20-yr MA, NWCC Trend Current 20-yr MA
0
100
200
300
400
500
600
700
800
1965 1969 1973 1977 1981 1985 1989 1993 1997 2001 2005 2009 2013 2017 2021 2025 2029 2033 2037 2041 2045
CD
D
20-yr MA CDD
Annual 20-yr MA, Avista Trend Annual 20-yr MA, NWCC Trend Current 20-yr MA
Avista Corp.2021 Electric IRP Appendices 231
Annual Native Load Forecast with Climate
Change, 2026-2045 (Preliminary!)
1,090
1,100
1,110
1,120
1,130
1,140
1,150
1,160
1,170
2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
2021 IRP Base-Line Native Load 2021 IRP Base-Line Native Load, Avista Trend 2021 IRP Base-Line Native Load, NWCC Trend18
IRP Avg. Annual Growth
2021 IRP, No Trend Base-Line 0.23%
2021 IRP, NWCC Trend 0.13%
2021 IRP, Avista Trend 0.21%
0.3% Lower than
Non-Trend Base-
Line
2% Lower than
Non-Trend Base-
Line
Avista Corp.2021 Electric IRP Appendices 232
Native Load Growth Forecast, 2021-2045
0.0%
0.5%
1.0%
1.5%
2.0%
2.5%
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
An
n
u
a
l

G
r
o
w
t
h
Native Load Growth
2021 IRP Base-Line Native Load Growth 2020 IRP Base-Line Native Load Growth19
EV/PHEV “Bend”
Load Recovery from
Recession
Avista Corp.2021 Electric IRP Appendices 233
Residential UPC Growth: 2021-2045
20
-1.5%
-1.0%
-0.5%
0.0%
0.5%
1.0%
1.5%
2.0%
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Base-Line Scenario: Residential UPC Growth Rate
EIA Refrence Case Use Per Household Growth 2021 IRP Residential Base-Line UPC Growth
Source Avg. Annual
Growth
2021 IRP -0.24%
EIA 0.03%
Avista Corp.2021 Electric IRP Appendices 234
Long-Run Load Forecast: Conservation
Adjustment
Grant D. Forsyth, Ph.D.
Chief Economist
[e-mail]
21 Avista Corp.2021 Electric IRP Appendices 235
Comparison of Native Load Forecasts, 2021-2045
900
1,000
1,100
1,200
1,300
1,400
1,500
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
Average Megawatts Load Comparision with Conservation Adjustment
Base-Line Native Load Base-Line Native Load with Conservation Added Back
22
Source Avg. Annual
Growth
2021 IRP 0.3%
No Conservation 1.0%
Avista Corp.2021 Electric IRP Appendices 236
Peak Load Forecast
Grant D. Forsyth, Ph.D.
Chief Economist
[e-mail]
23 Avista Corp.2021 Electric IRP Appendices 237
The Basic Model
•Monthly time-series regression model that initially excludes certain industrial loads and
EVs (but those are added back in for the final forecast).
•Based on monthly peak MW loads since 2004. The peak is pulled from hourly load data for
each day for each month.
•Explanatory variables include HDD-CDD and monthly and day-of-week dummy variables.
The level of real U.S. GDP is the primary economic driver in the model—the higher GDP, the
higher peak loads. Model allows GDP impact to differ between winter and summer.
•The coefficients of the model are used to generate a distribution of peak loads by month
based on historical max/min temperatures since 1890, holding GDP constant. A starting
expected peak load is then calculated using the average peak load simulated for that
month going back to 1890. Model shows Avista is a winter peaking utility for the forecast
period; however, the summer peak is growing at a faster than the winter peak.
•For comparison in the 2021 IRP, peak load is also calculated by averaging simulated peak
loads over the last 30 years and 20 years.
•The model is also used to calculate the long-run growth rate of peak loads for summer and
winter using a forecast of GDP growth under the “ceteris paribus” assumption for weather
and other factors.
24
Avista Corp.2021 Electric IRP Appendices 238
Peak Forecasts for Winter and Summer, 2021-2045
1,100
1,200
1,300
1,400
1,500
1,600
1,700
1,800
1,900
2,000
19
9
7
19
9
9
20
0
1
20
0
3
20
0
5
20
0
7
20
0
9
20
1
1
20
1
3
20
1
5
20
1
7
20
1
9
20
2
1
20
2
3
20
2
5
20
2
7
20
2
9
20
3
1
20
3
3
20
3
5
20
3
7
20
3
9
20
4
1
20
4
3
20
4
5
Me
g
a
w
a
t
t
s
Winter Peak Summer Peak
Peak Avg. Growth 2021-45
Winter 0.37%
Summer 0.44%
25
Avista Corp.2021 Electric IRP Appendices 239
Load Forecasts for Winter Peak, 2011-2043
1,500
1,750
2,000
2,250
2,500
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Me
g
a
w
a
t
t
s
Winter Peak Forecast: Current and Past
2009 IRP 2011 IRP 2013 IRP 2015 IRP 2017 IRP 2020 IRP 2021 IRP
26
Avista Corp.2021 Electric IRP Appendices 240
Load Forecasts for Summer Peak, 2011-2045
1,500
1,750
2,000
2,250
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Me
g
a
w
a
t
t
s
Summer Peak Forecast: Current and Past
2009 IRP 2011 IRP 2013 IRP 2015 IRP 2017 IRP 2020 IRP 2021 IRP27
Avista Corp.2021 Electric IRP Appendices 241
Peak Forecasts for Winter and Summer 30-Year
Average Weather, 2021-2045
1,100
1,200
1,300
1,400
1,500
1,600
1,700
1,800
1,900
2,000
19
9
7
19
9
9
20
0
1
20
0
3
20
0
5
20
0
7
20
0
9
20
1
1
20
1
3
20
1
5
20
1
7
20
1
9
20
2
1
20
2
3
20
2
5
20
2
7
20
2
9
20
3
1
20
3
3
20
3
5
20
3
7
20
3
9
20
4
1
20
4
3
20
4
5
Me
g
a
w
a
t
t
s
Winter Peak Summer Peak28
Avista Corp.2021 Electric IRP Appendices 242
Peak Forecasts for Winter and Summer 20-Year
Average Weather, 2021-2045
1,100
1,200
1,300
1,400
1,500
1,600
1,700
1,800
1,900
2,000
19
9
7
19
9
9
20
0
1
20
0
3
20
0
5
20
0
7
20
0
9
20
1
1
20
1
3
20
1
5
20
1
7
20
1
9
20
2
1
20
2
3
20
2
5
20
2
7
20
2
9
20
3
1
20
3
3
20
3
5
20
3
7
20
3
9
20
4
1
20
4
3
20
4
5
Me
g
a
w
a
t
t
s
Winter Peak Summer Peak29
Avista Corp.2021 Electric IRP Appendices 243
Long-Run Customer Forecast: Natural
Gas
Grant D. Forsyth, Ph.D.
Chief Economist
[e-mail]
30
Avista Corp.2021 Electric IRP Appendices 244
Firm Customers (Meters) by State and Class, 2019
31
WA
47%
ID
24%
OR
29%
Firm Customers by State
Residential
90%
Commercial
10%
Industrial
0.1%
Firm Customers by Class
Avista Corp.2021 Electric IRP Appendices 245
System All Types of Industrial Customers, 1997-2020
200
210
220
230
240
250
260
270
280
290
300
0
5
10
15
20
25
30
35
19
9
7
19
9
8
19
9
9
20
0
0
20
0
1
20
0
2
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0

E
s
t
WA
-ID

F
i
r
m

I
n
d
u
s
t
r
i
a
l
OR

F
i
r
m

I
n
d
u
s
t
r
i
a
l
OR Firm Industrial WA-ID Firm Industrial32
291 31
216
24
Avista Corp.2021 Electric IRP Appendices 246
Customer Forecast Models
•Forecast models are structured around each schedule, in each class, by jurisdiction.
In the case of OR, this is done individually for each of Avista’s service islands.
•Time series transfer function models (models with regressions drivers and ARIMA
error terms).
•Simple time series smoothing models (for schedules with little customer variation).
•Same models used for the bi-annual revenue model forecast pushed out to 2045.
The forecasts for this IRP were generated from the “Summer/Fall 2020” forecast
completed in June.
•Customer forecasts are sent to Gas Supply for inclusion in the SENDOUT model.
•Example of transfer function model: WA sch. 101 residential customers…
Avista Corp.2021 Electric IRP Appendices 247
Transfer Function Model Example
34
𝐶𝐶𝑡𝑡,𝑦𝑦,𝑊𝑊𝑊𝑊101.𝑟𝑟=𝛼𝛼0 +𝜏𝜏𝑃𝑃𝑃𝑃𝑃𝑃𝑡𝑡,𝑦𝑦,𝑆𝑆𝑆𝑆𝑆𝑆+𝝎𝝎𝑺𝑺𝑺𝑺𝑺𝑺𝒕𝒕,𝒚𝒚+𝜔𝜔𝑂𝑂𝑂𝑂𝐷𝐷𝑂𝑂𝑂𝑂𝑡𝑡2015=1 +𝜔𝜔𝑂𝑂𝑂𝑂𝐷𝐷𝐹𝐹𝐹𝐹𝐹𝐹2016=1+𝜔𝜔𝑂𝑂𝑂𝑂𝐷𝐷𝑀𝑀𝑀𝑀𝑟𝑟2018=1 +𝜔𝜔𝑂𝑂𝑂𝑂𝐷𝐷𝑁𝑁𝑁𝑁𝑁𝑁2018=1 +𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝑡𝑡,𝑦𝑦12,1,0 0,0,0 12
Monthly
Customer
(Meter Count)
Monthly
Interpolated
Population for
Spokane MSA
Seasonal
Dummies
Outlier
Dummies
(Interventions)Error Correction
Component
Avista Corp.2021 Electric IRP Appendices 248
Getting to Population as a Driver, 2020-2025 & 2026-2045
Average GDP Growth
Forecasts:
•WSJ, FOMC,
Bloomberg, etc.
•Average forecasts
out 5 full calendar
years.
Non-farm Employment
Growth Model:
•Model links year y, y-1, and
y-2 GDP growth to year y
regional employment
growth.
•Forecast out 5 full calendar
years.
•Averaged with IHS
employment growth
forecasts.
Regional Population Growth Models:
•Model links regional, U.S., and CA
year y-1 employment growth to year y
county population growth.
•Forecast out 5 full calendar years for
Spokane, WA; Kootenai, ID; and
Jackson+Josephine, OR.
•Averaged with IHS growth forecasts.
•Growth rates used to generate
population forecasts for use in
regression models—important driver
for main residential and commercial
schedules.
EMPGDP
2020-2025 For Spokane, WA; Kootenai, ID, and
Jackson+Josephine, OR
OR Douglas, Klamath, and Union counties: IHS population growth forecasts for 2020-2045
Kootenai and Jackson: IHS population growth forecasts for 2026-2045
Spokane: OFM population growth forecasts for 2026-2045
Monlthly Interpolation assumes: PN = P0erN
Deviation in the most
recent forecast!
35
Avista Corp.2021 Electric IRP Appendices 249
WA-ID Region Firm Customers, 2021-2040 (2018 IRP)
220,000
240,000
260,000
280,000
300,000
320,000
340,000
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
WA-ID Base-line 2018 WA-ID Base-line 2021
IRP Avg.Annual Growth
2021-2040
2021 1.1%
2018 1.2%≈ +1,400
36
Avista Corp.2021 Electric IRP Appendices 250
OR Region Firm Customers, 2021-2040 (2018 IRP)
95,000
100,000
105,000
110,000
115,000
120,000
125,000
130,000
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
OR Base-line 2018 OR Base-line 2021
≈ -2,800
IRP Avg.Annual Growth
2021-2040
2021 0.8%
2018 0.9%
37
Avista Corp.2021 Electric IRP Appendices 251
Medford, OR Region Firm Customers, 2021-2040 (2018 IRP)
55,000
60,000
65,000
70,000
75,000
80,000
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
Medford Base-line 2018 Medford Base-line 2021
IRP Avg.Annual Growth
2021-2037
2021 0.9%
2018 0.9%≈ +310
38
Avista Corp.2021 Electric IRP Appendices 252
Roseburg, OR Region Firm Customers, 2021-2040 (2018 IRP)
14,000
15,000
16,000
17,000
18,000
19,000
20,000
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
Roseburg Base-line 2018 Roseburg Base-line 2021
≈ -1,900
IRP Avg.Annual Growth
2021-2040
2021 0.4%
2018 0.9%
39
Avista Corp.2021 Electric IRP Appendices 253
Klamath, OR Region Firm Customers, 2021-2040 (2018 IRP)
15,000
16,000
17,000
18,000
19,000
20,000
21,000
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
Klamath Base-line 2018 Klamath Base-line 2021
IRP Avg.Annual Growth
2021-2040
2021 0.7%
2018 1.0%
≈ -1,200
40
Avista Corp.2021 Electric IRP Appendices 254
La Grande, OR Region Firm Customers, 2021-2040 (2018
IRP)
7,400
7,600
7,800
8,000
8,200
8,400
8,600
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
La Grande Base-line 2018 La Grande Base-line 2021
IRP Avg.Annual Growth
2021-2040
2021 0.5%
2018 0.5%
≈ +30
41
Avista Corp.2021 Electric IRP Appendices 255
System Firm Customers, 2021-2040 (2018 IRP)
320,000
340,000
360,000
380,000
400,000
420,000
440,000
460,000
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
WA-ID-OR Base 2018 WA-ID-OR Base 2021
≈ -1,400
IRP Avg.Annual Growth
2021-2040
2021 1.0%
2018 1.1%
42
Avista Corp.2021 Electric IRP Appendices 256
WA-ID Region Firm Customer Range, 2021-2045
220,000
240,000
260,000
280,000
300,000
320,000
340,000
360,000
380,000
400,000
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
WAIDFIRMCUS Base WAIDFIRMCUS High WAIDFIRMCUS Low
Variable Low
Growth
Base
Growth
High
Growth
WA-ID Customers 0.7%1.1%1.5%
WA Population 0.4%0.7%1.0%
ID Population 0.8%1.4%2.0%
WA-ID Population 0.5%0.8%1.2%
43
Avista Corp.2021 Electric IRP Appendices 257
OR Region Firm Customer Range, 2021-2045
95,000
100,000
105,000
110,000
115,000
120,000
125,000
130,000
135,000
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
ORFIRMCUS Base ORFIRMCUS High ORFIRMCUS Low
Variable Low
Growth
Base
Growth
High
Growth
Customers 0.5%0.7%0.9%
Population 0.3%0.5%0.7%
44
Avista Corp.2021 Electric IRP Appendices 258
System Firm Customer Range, 2021-2045
300,000
350,000
400,000
450,000
500,000
550,000
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
SYSTEMCUS.syf Base SYSTEMCUS.syf High SYSTEMCUS.syf Low
Variable Low
Growth
Base
Growth
High
Growth
Customers 0.6%1.0%1.3%
Population 0.4%0.8%1.1%
45
Avista Corp.2021 Electric IRP Appendices 259
Summary of Growth Rates
System Base-Case High Low
1.0%1.4%0.7%
Commercial 0.5%0.8%0.1%
Industrial -0.8%2.2%-3.8%
Total 1.0%1.3%0.6%
WA Base-Case High Low
1.0%1.3%0.7%
Commercial 0.4%0.7%0.1%
Industrial -0.8%1.9%-3.6%
Total 1.0%1.3%0.7%
ID Base-Case High Low
1.4%2.0%0.8%
Commercial 0.4%1.0%-0.2%
Industrial -1.0%1.8%-3.4%
Total 1.3%1.9%0.7%
OR Base-Case High Low
0.7%0.9%0.5%
Commercial 0.6%0.8%0.4%
Industrial 0.0%4.5%-10.6%
Total 0.7%0.9%0.5%
46
Avista Corp.2021 Electric IRP Appendices 260
TAC 2.5 Meeting, September 18, 2020
Virtual Meeting Attendees: Nikita Bankoti, Washington UTC; Ben Cartwright; John
Chatburn, Idaho Energy Office; Corey Dahl, Washington Public Counsel; Ashton Davis;
Daniel Hua, NPPC; Kevin Keyt, IPUC; State of Idaho; Katie Pegan, OEMR; Steve
Johnson, Washington UTC; Charles Pegan; Dan Kirschner, NW Gas Association; Fred
Huette, NWEC; Gina Saraswati; Kate Griffith, Washington UTC; Joni Bosh, NWEC; L
Molander; Devin McGreal, Cascade Natural Gas; Michael Eldred, IPUC; Mike Morrison,
IPUC; Morgan Brummund, Idaho Energy Office; Greg Nothstein, Washington
Department of Commerce; Andrew Rector, Washington UTC; Richard Keller, IPUC; Ken
Ross, Fortis; Sudeshna Pal, Oregon CUB; Ted Light; Terrence Browne, Avista; Vlad
Gutman-Britten, Climate Solutions; Yao Yin, IPUC; Tom Pardee, Avista; Jody
Morehouse, Avista; Jaime Majure, Avista; Paul Kimmell, Avista; Theophania Labay,
Avista; John Lyons, Avista; Lori Hermanson, Avista; James Gall, Avista; Grant Forsyth,
Avista; Ryan Finesilver, Avista; Michael Brutocao, Avista; Mike Tatko, Avista; Amanda
Ghering, Avista; Clint Kalich, Avista; Shawn Bonfield, Avista; Marissa Warren, IPUC;
two Unavailable; and four Guests
Replies in italics after questions are made by the presenter in the following notes.
Economic Load and Customer Forecast (TAC 2.5)
Grant Forsyth: MSA stands for metropolitan service areas. Includes Spokane, Coeur
d’Alene, Lewiston/Clarkston, and Grants Pass in our service territory.
Grant Forsyth: [Slide 4]: Most or 2/3 is local government, and half or more of
government employment is for education.
Grant Forsyth: 2008 slowing job opportunities. Population growth means more job
opportunities. About 0.5% growth, 80-100% in-migration influencing load growth.
Steve Johnson: Now, generally speaking is there about a year lag between
employment growth and population about a year later? Yes, about that.
Steve Johnson: Population drives service territory growth. Do we know why 2014
surged above the nation? A little late in the process. Retirement demographic, jobs.
What does it correlate to GDP, higher or lower? Multiple reasons. Employment is a
primary driver. It has been an OK predictor in the past, but talk to people in real estate
and a robust economy comes with job growth. Low housing costs bring equity refugees
to the area after selling a house. OK, thanks.
Steve Johnson: Is there a separate forecast for layoffs that local governments might do
in the next 1.5 years and the rate of government job growth after that 1.5 year period?
No, it looks at total employment growth and the lagged by a year population growth.
Grant Forsyth: Employment is also part of the GDP growth forecast based on an
average of forecasts, at least over the medium term out to 2025. Big difference from
Avista Corp.2021 Electric IRP Appendices 261
June 2019 to June 2020 with a 6 percent decline in GDP, expect 4 percent growth next
year and then back down to 2 percent growth after 2022.
Andrew Rector: Do you run sensitivities on the growth rates? Yes, did run sensitivities
on this lately because of the COVID crisis with different types of recessions. The most
sensitive is the industrial side. Slowed employment growth slows customer growth for
two years after the recession, but clearly the most sensitive is industrial. Does that
answer your question? Yes, it does.
Grant Forsyth: Last year, I was asked to look at load if there was a recession every six
years. Found that we get to the same place, but more volatility builds more noise into
the model.
James Gall: There will be a high and a low load growth scenario. Not sure if we have it
later, but we can add it to the slide deck later.
Steve Johnson: There are various GDP underlying assumptions of how COVID plays
out. In regards to GDP estimates you used, do you know what the underlying
assumption was related to COVID and how that plays out?
Grant Forsyth: In some forecasts you can observe the underlying assumptions and
some you cannot. Some were predicting various things about COVID. Some were V
shaped, some square root, and others W shaped. But averaged together you get the
red line on Slide 7.
Steve Johnson: Does the company have an idea of how they think it’ll play out from
the scientists and economists?
Grant Forsyth: I’m allowed some discretion with that, but I tend to stick with a forecast
procedure that the Commissions are aware of and familiar with. I did not use a lot of
discretion using epidemiological sources. That is something I thought I’d never be asked
looking back on forecasts.
Steve Johnson: Is it the company’s forecast looking at the scientific community’s look
at a second wave? Do you think that is realistic? Does the Company agree a second
wave is sound scientific reasoning?
Grant Forsyth: When this was first going on people like me stopped forecasting early in
COVID. Even the Fed [U.S. Federal Reserve] stopped providing guidance. Started to
look at economists forecasting with epidemiologist input for one, two or three waves, but
it didn’t provide that much guidance that largely impact the forecast. The NEBR
[National Bureau of Economic Research] looked at how the Spanish Flu [in 1918].
Slide #9: Medium term of 2020 – 2025 is what we used in the revenue and earnings
model in June 2020. 20-year moving average of weather (2000-2019) that gets updated
every year.
Avista Corp.2021 Electric IRP Appendices 262
Andrew Rector: When you say price do you mean price of electricity? Yes, own price
of electricity. Typically all-in annual prices – all revenues divided by usage for that
schedule)
Nikita Bankoti (Slide #9): Is GDP based on growth assumptions weighted a lot from
2020-2025?
Grant Forsyth: Good question. Typically what I’ll do is to not increase uncertainty in the
short run GDP for that period. I don’t necessarily increase the uncertainty from that
period.
Nikita Bankoti: I’m trying to understand if you assign an equal weight to GDP?
Grant Forsyth: Essentially a consensus as GDP filters through but no weighting.
Washington State weights their revenue model. I use a single GDP treated as a
consensus and drive that through the model. I don’t have any weightings like the state
does.
Nikita Bankoti: OK, that makes sense.
Mike Morrison: Multiplying customers by UPC isn’t difficult, mathematically. Why did
you use an approximation at all?
Grant Forsyth: I’m making sure everyone understands since not everyone does this
kind of work, so I start from the beginning and build up from there. There two
component parts you need to worry about to determine what’s driving load. Customer
growth and use per customer growth are the main things.
Andrew Rector: Can you say again? Overall the 0.8% is the same as the 2020
forecast, but shaped differently, is that what you’re saying?
Grant Forsyth: Yes. Taking it a step further, long term population growth is about 0.8%
on average. The U.S. is about 0.5% growth, so there is embedded in the forecast a
certain amount of in-migration for our service area.
Mike Morrison: Red line, increases and then precipitous drop in 2026 – what’s the drop
coming from?
Grant Forsyth: Long-term forecasts. That drop reflects what the third-party forecaster
are thinking will happen. Really the IHS forecast that can change from IRP to IRP based
on their own modeling processes. The OFM forecast is more stable because they don’t
update as often as IHS.
Steve Johnson (slide #12): Is this acceleration in Washington state and related to
incentives and programs?
Grant Forsyth: Washington probably dominates; if you look at customers who have
solar, it’s weighted to Washington. It is an assumption that we update as we get more
information. The cost has come down a lot on solar and that encourages more solar
Avista Corp.2021 Electric IRP Appendices 263
adoption. Also technological changes – roofs that look like shingles, but it’s actually
solar.
Steve Johnson: Are you modeling commercially available?
Grant Forsyth: Some are available and some are in testing, but when looking out over
time, assuming solar will accumulate at a rapid pace. It is an assumption. There is
another slide coming up that talks about this in more detail.
Yao Yin: Why isn’t residential solar considered from demand side versus supply side?
James Gall: Currently the customer controls that solar device and when it’s producing.
It belongs as a load component. In the event the utility offers incentives to change how
they operate, that’d be a demand-side resource, but it could translate into a supply side
resource.
Yao Yin: For other types of solar such as QF, do they belong to supply side? Yes.
Andrew Rector (Slide #12): What are your data sources for solar?
Grant Forsyth: Our own internal data from engineers that they collect. There is very
little non-solar net metering on our system anymore. The data includes customer
location and system size.
Nikita Bankoti (Slide #11): Again there is a lot of residential customer growth variation
in 2021-2023, variation in GDP forecast, is it a good idea for this variability to be
factored into the long-term forecast?
Grant Forsyth: I would need to think about this. Typically what happens with the
medium term forecast, it is currently set up to mesh with the medium term forecast for
the revenue model. The Company typically needs a medium term forecast to put into
the revenue model. One of the frustrations with forecasters is how to handle this current
COVID situation since it is atypical.
Steve Johnson: 10,000 watts in 2044. So that is a capacity factor of 15% on peak or
on average? On average, energy side rather than peak, approximately 10 aMW. It is on
a spreadsheet. I don’t need precision just a general sense. Are you modeling solar to
drop off before you get to your peak at 6 pm?
Grant Forsyth: It varies back and forth between 7 and 8 am to 5 to 6 pm where you
see the most peaks occur.
Steve Johnson: Is solar making a small impact on peak? Yes.
James Gall: On winter, solar is making virtually no impact on peak, but maybe some
peak shifting. In the summer, solar will reduce peak by about 60%. Subject to check, I
think it is about 14% capacity factor on rooftop solar (DC rating not AC rating)
Fred Heutte: What method are you using? Are you using a simple logistic regression
curve?
Avista Corp.2021 Electric IRP Appendices 264
Grant Forsyth: It assumes an exponential growth function out to 2045. At some time
we expect it to become logarithmic or some other type of term. It won’t go on forever at
this growth rate since we’re just getting started.
Fred Heutte: Are you taking into consideration technology and cost reductions?
Grant Forsyth: That’s why I’m assuming the size of growth due to technology
developments and cost reductions. Allowing the size to grow and as they develop more
solar, more ways to apply it.
Fred Heutte: I’m thinking about the experience curve. Can’t project current trends to the
longer term. Panel costs are not the majority of the costs now. Moved to telesales to
drop costs. May drive the market more going forward.
Grant Forsyth: Two big uncertainties to model the longer term – solar and EVs.
Fred Heutte: We are encouraging utilities to look at higher EV penetration scenarios.
Grant Forsyth: We do have EV charging shape built into our future forecast.
Fred Heutte: How do you do rate design so we don’t get a big hit?
Grant Forsyth: Where is policy going because that will shape a bunch of factors?
Currently difficult to get a sense of where that’s going.
James Gall: Commercial EVs?
Grant Forsyth: Residential EVs are highly correlated to growth in the commercial side.
They follow each other. Implicit assumption that as EV are accumulated on the
residential side, they’ll accumulate on the commercial side.
Andrew Rector: Does it take into account EVs yet like buses? No, it does not.
Yao Yin: Is there a similar assumption between residential and commercial solar?
Grant Forsyth: Yes, but solar is still weighted heavily to the residential side, but I’m
trying to maintain the correlation over time.
James Gall: Actually forecasting monthly, not hourly. We layer that into our models and
will talk at a future TAC about how we are doing that.
Slide #15: At what point EV load starts to negate of solar? The black dotted line. It
bends up about 2040. When it does occur, it has a significant effect on load behavior.
Mike Morrison: I don’t think aMW is a useful metric in planning what we care about. I’m
not sure of the relevance of aMW since capacity will occur over a couple of hours as
opposed to over 24 hours. It shows magnitude.
James Gall: This is only the first slide. Coincident peak slide is coming up. Energy
does matter – we look at peak and energy to meet both needs.
Avista Corp.2021 Electric IRP Appendices 265
Yao Yin: For solar, we assume about 14% capacity factor, for EVs do we assume a
certain percentage for solar?
James Gall: Yes, it’s built into Grant’s model, but I can’t recall the exact factor. We look
at the capability of a charge and the kilowatt per hour. We don’t typically look at it that
way so I don’t have a factor right off.
Yao Yin: Do we assume certain hours EVs will get charged?
Grant Forsyth: Yes the profile tries to take that into effect.
Yao Yin: For the load forecast does this start monthly and peak hourly?
Grant Forsyth: Monthly and peak comes from Rendall’s load profiles. Starts with
hourly, converted to monthly. I may be misunderstanding your question.
Yao Yin: If we start with annual why do we convert to monthly?
Grant Forsyth: We are using monthly data to do peak load forecast so we have to
convert it to monthly.
James Gall: For the IRP, we do use the monthly peak and energy in order to get to
hourly. We look at winter/summer peak, annual energy.
Yao Yin: Another question regarding EVs, solar assumes about 14%, so do we have to
assume a capacity factor for charging?
James Gall: There is a battery draw built into the model. 3,000 to 5,000 kWh per year
depending on mileage. Great question.
Grant Forsyth: Assuming about 3,500 kWh per year from Rendall Farley’s EV analysis
submitted to the WUTC.
Yao Yin: Do you assume specific charging hours? Yes, it’s built into the load forecast
and taken into account.
Andrew Rector: Just for context, I have your EV plan in front of me with 3,153 kWh per
year. Sounds approximately right with what I entered.
Vlad Gutman-Britten: What period of time is the trend your green line is using? The
whole time period.
Mike Morrison: Is that a trend on individual years or 20-year moving average? Is that
legal with a time series?
Grant Forsyth: I don’t know if that’s legal. I could try that. If I recall correctly, time
series on a time series. It is heavily smoothed, but it’s not being done nefariously. Can
try it the other way certainly do it on the raw data.
Mike Morrison (Slide #17): So you got an increase of about 20% in cooling degree
days, so people are going to buy more ACs with up to over 700 cooling degree days?
Avista Corp.2021 Electric IRP Appendices 266
Grant Forsyth: This is my initial look, probably big implications for peak load; haven’t
done analysis for how I’d apply this to peak load. Additional adjustments will be needed.
Multiple effects – income increasing, AC costs declining – leads to more purchase of
ACs.
Fred Heutte: I had a little trouble on audio or dial in. On slide #18, double check of
additive of slightly higher cooling degree days and quite a bit lower heating degree
days. Yes, that is the net effect through the regression model. Agree with the approach
of a 20-year moving average. Need at least 10 years and more is better. We can’t go
back too far or we lose the signal. Inter-year variability is very large. This seems to be in
the right direction.
Grant Forsyth: Finally have analytically figured out how to shape that monthly. I
appreciate the comments from everybody.
Mike Morrison: As far as conservation, I believe you go those numbers from your
energy efficiency folks. We actually disagree with a lot of the numbers you got out of
your energy efficiency group. The IPUC has asked Avista’s conservation group to revisit
their energy savings because IPUC disagrees with their estimates – very much over
reporting.
Grant Forsyth: Fair enough. The information provided to me is what I have to work
with.
Mike Morrison: Not criticizing you, but the information is dubious. There is very much
over reporting in what energy efficiency has been doing.
James Gall: When we do capacity expansion modeling, we need an estimate of what
our load looks like with our conservation. DSM programs compete against other
resources. Based on what’s picked (conservation) we adjust the black line up or down
(slide 22).
Mike Morrison: Forecast based on average is that what we should be looking at.
Grant Forsyth: We do provide a band.
Mike Morrison: Are you really going to continue to be a winter peaking utility? I’m
concerned with how you’re doing your conservation programs (fuel switching).
Grant Forsyth: Yes, the conflict we face is the climate is changing, but the empirical
data shows that winter is still the peak period. Summer is moving up and we need to be
looking at an upper band.
James Gall: Grant is showing the average cold or hot day. In LOLP analysis, we
simulate those bands. We typically see a winder band in the winter and typically a
tighter band in the summer. This is used for loss of load based on probability of those
ranges; what is the probability of one of these peaks aligning with an outage as such.
Avista Corp.2021 Electric IRP Appendices 267
Substantial amount of fuel-switching from electric to natural gas. That peak is now
removed. Both winter and summer are accounted for and optimized for.
Fred Heutte (slide 29): I have a comment about slide 25, but stay here. By eyeball it
looks summer, but still winter mathematically. LOLP makes most sense, most important
especially late summer – mid-July to mid-September.
Deborah Reynolds: As we’re thinking about how energy efficiency will be incorporated
into the load forecast, I’ve been thinking about taking the whole house efficiency and
how that will affect summer load. Weatherization affects both summer and winter. Be
thinking about how programs change over time. Ok, will do that.
Yao Yin: Winter and summer peak, have considered residential solar and EV
conservation?
Grant Forsyth: Solar is not as direct and is embedded only to the extent it’s in the
historical data. EV effects are more direct. Solar does not have the same impacts on
peak as EVs.
James Gall: We look at a peak credit to see how much it shaves peak. It was 2% in the
last plan.
Nikita Bankoti: Do you include gas transportation customers?
Grant Forsyth: Yes, I do a forecast for transportation but not for the IRP because we’re
looking at core load.
Tom Pardee (slide 32): Transportation customers are tasked with getting their own
transportation whereas we’re responsible for the firm gas customers.
Andrew Rector: Is it economic things driving IHS’s economic forecast in Roseburg?
Grant Forsyth: Yes, demographics. The only thing causing population growth is in-
migration or else it would be negative. I think they’re suggesting that in-migration is
restrained. Natural birth rate is zero or negative there and only growth is from in-
migration which they think will be lower than usual. It was revised down before the
shutdown.
Andrew Rector: Interesting context. Thanks.
Nikita Bankoti (slide 46): Negative industrial growth, is that from COVID?
Grant Forsyth: No that’s from a longer-term secular trend. This was in last IRP too. It
seems to be more of an acute problem in Washington than Idaho. Industrial companies
are exiting or relocating more heavily weighted towards Washington. Sneaking
suspicion that customers are going out of business or moving locations. Goes through
Actual May 2020 numbers but there could be some longer-term impacts from COVID
that may not appear for up to 24 months.
James Gall: What has the gas side seen from COVID?
Avista Corp.2021 Electric IRP Appendices 268
Grant Forsyth: I’d say gas data weathered better than east side out of heating.
Transportation customers being mostly industrial are a pretty good indicator of the
economy. Wood products firms, lumber, have done better with housing. Gas line
explosion caused some problem with switching from transport to firm schedules. The Air
Force Base and Idaho continue to be a surprise in terms of robust growth.
Deborah Reynolds: One last question. Have you looked at how robust transportation
conservation programs might impact gas transportation load and how much flexibility
there is in terms of the rate they pay?
Grant Forsyth: That’s a whopper. Many years ago, we had this conversation in
Oregon, at the time with the low gas costs, it didn’t make economic sense.
Tom Pardee: We can have Terrance speak about this on distribution if they are firm. If
on transportation, we can cut them. We’ll have an answer at the next TAC.
Deborah Reynolds: Legislation passed that you have to get ALL and that might include
transportation customers.
Shawn Bonfield: They don’t pay into the tariff.
Deborah Reynolds: I agree which is why I need you guys to do some work.

Avista Corp.2021 Electric IRP Appendices 269

2021 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 3 Agenda
Tuesday, September 29, 2020 Virtual Meeting
Topic Time Staff
Introductions 9:00 Lyons IRP Transmission Planning Studies 9:15 Spratt Break 10:15

Distribution Planning within the IRP 10:30 Fisher

Lunch 11:30

Demand Response Potential Assessment 12:30 AEG

Break 1:30

Conservation Potential Assessment 1:45 AEG

Electric Market Forecasts 2:45 Gall

Portfolio Scenarios 3:30 Lyons

Adjourn 4:00

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Avista Corp.2021 Electric IRP Appendices 270
2021 Electric IRP
TAC Introductions and IRP Process Updates
John Lyons, Ph.D.
Third Technical Advisory Committee Meeting
September 29, 2020
Avista Corp.2021 Electric IRP Appendices 271
Updated Meeting Guidelines
•Electric IRP team still working remotely, available by
email and phone for questions and comments
•Some processes are taking longer remotely
•Virtual IRP meetings until back in the office and able to
hold large group meetings
•Joint Avista IRP page for gas and electric:
https://www.myavista.com/about-us/integrated-resource-
planning
2 Avista Corp.2021 Electric IRP Appendices 272
Virtual TAC Meeting Reminders
•Please mute mics unless speaking or asking a question
•Use the Skype chat box to write questions or comments
or let us know you would like to say something
•Respect the pause
•Please try not to speak over the presenter or a speaker
who is voicing a question or thought
•Remember to state your name before speaking for the
note taker
•This is a public advisory meeting –presentations and
comments will be recorded and documented
3 Avista Corp.2021 Electric IRP Appendices 273
Integrated Resource Planning
•Required by Idaho and Washington* every other year
•Guides resource strategy over the next twenty + years
•Current and projected load & resource position
•Resource strategies under different future policies
–Resource choices
–Conservation measures and programs
–Transmission and distribution integration for electric
–Gas distribution planning
–Gas and electric market price forecasts
•Scenarios for uncertain future events and issues
•Key dates for modeling and IRP development are
available in the Work Plans
4 Avista Corp.2021 Electric IRP Appendices 274
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
–Help with soliciting new members
•Open forum while balancing need to get through all of the topics
•Welcome requests for studies or different assumptions.
–Time or resources may limit the number or type of studies
–Earlier study requests allow us to be more accommodating
–August 1, 2020 was the electric study request deadline
•Planning teams are available by email or phone for questions or
comments between the TAC meetings
5 Avista Corp.2021 Electric IRP Appendices 275
2021 Electric IRP TAC Schedule
•TAC 1: Thursday, June 18, 2020
•TAC 2: Thursday, August 6, 2020 (Joint with Natural Gas TAC)
•TAC 2.5: Tuesday, August 18, 2020 Economic and Load Forecast
•TAC 3: Tuesday, September 29, 2020
•TAC 4: Tuesday, November 17, 2020
•TAC 5: Thursday, January 21, 2021
•Public Outreach Meeting: February 2021
•TAC agendas, presentations, meeting minutes and IRP files
available at:
https://myavista.com/about-us/integrated-resource-planning
6 Avista Corp.2021 Electric IRP Appendices 276
Process Updates
IRP data available on the web site:
•Avista Resource Emissions Summary
•Load Forecast
•CPA Measures
•Avista 2020 Electric CPA –Summary and IRP Inputs
•Home Electrification Conversions
•Named Populations
•Natural Gas Prices
•Social Cost of Carbon
7 Avista Corp.2021 Electric IRP Appendices 277
Today’s TAC Agenda
9:00 Introductions, Lyons
9:15 IRP Transmission Planning Studies, Spratt
10:15 Break
10:30 Distribution Planning within the IRP, Fisher
11:30 Lunch
12:30 Demand Response Potential Assessment, AEG
1:30 Break
1:45 Conservation Potential Assessment, AEG
2:45 Electric Market Forecasts, Gall
3:30 Portfolio Scenarios, Lyons
4:00 Adjourn
8 Avista Corp.2021 Electric IRP Appendices 278
Integrated Resource Plan (IRP)
Transmission Planning Studies
Dean Spratt, Transmission Planning
Third Technical Advisory Committee Meeting
September 29, 2020
Avista Corp.2021 Electric IRP Appendices 279
FERC Standards of Conduct
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 Avista Corp.2021 Electric IRP Appendices 280
Agenda
•Introduction to Avista System Planning
•Useful information about Transmission Planning
•Recent Avista projects
•Generation Interconnection Study Process
•Integrated Resource Plan (IRP) Requests
•Large Generation Interconnection Queue
3 Avista Corp.2021 Electric IRP Appendices 281
Introduction to Avista System Planning
Avista’s System Planning Group includes:
•Asset Performance and Management
•Distribution Planning
•Transmission Planning
–Focus on reliable electric service
•Federal, regional, and state compliance
•Regional system coordination
–Provide transmission service and system analysis
•Planned load growth and changing generation dispatch
•Interconnection of any type of generation or load
–We are ambivalent about type (must perform though)
4 Avista Corp.2021 Electric IRP Appendices 282
Information About Transmission Planning
•We care about the Bulk Electric System (BES)
–Our 115 kV and 230 kV facilities (>100 kV)
•We identify issues where the Avista BES won’t
reliably deliver power to our customers
•Then put together 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 Avista Corp.2021 Electric IRP Appendices 283
TPL-001-4
•Describes outage conditions we must study
–P0: everything online and working
–P1: single facility outages, like a transformer
–P2, P4, P5 & P7: multiple facility outages
–P3 & P6: overlapping combination of two facilities
6 Avista Corp.2021 Electric IRP Appendices 284
TPL-001-4, 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”
7 Avista Corp.2021 Electric IRP Appendices 285
Two Approaches to 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
•Standards continue to define this balance
8 Avista Corp.2021 Electric IRP Appendices 286
Standards are a Roadmap
Changes in equipment, analysis tools, experience, and expectations impact Avista’s
study process and results
9 Avista Corp.2021 Electric IRP Appendices 287
Recent Transmission Projects
10
BNT-OSS 115 kV
increase capacity
Westside 230/115 kV increase capacity
SaddleMtn 230/115
kV new source
Neilson 115 kV new
switching station
115 kV underground
cable replacementSunset 115 kV rebuild
Moscow 230/115 kV
increase capacity
CDA-PIN 115 kV
increase capacity
BRX-CAB-SCK 115 kV
increase capacity
Adam Neilson
20 MW Solar
Rattlesnake Flat
144 MW Wind
Palouse
105 MW Wind
Avista Corp.2021 Electric IRP Appendices 288
Non Wire Solutions are Evaluated
•We are documenting this with more clarity
•Non-wire options require robust wires to perform
–Avista is working on the transmission fundamentals
11 Avista Corp.2021 Electric IRP Appendices 289
Evaluated Batteries for T-1-1
•TPL-001-4 ~ 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
–Could we mitigate performance issues with storage?
•Yes…but…
–We would need a 125 MW battery
»Charge is 8 hours, discharge for 12 to 16 hours (outage is weeks to months)
–A third transformer is a better solution
»Robust performance and much less $$$$
12 Avista Corp.2021 Electric IRP Appendices 290
Generation Interconnection Study Process
Process for Generation Requests
•Two sources:
•External developers
•Enter via the OATT
•Internal IRP requests
•Feasibility Lite 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 our findings and recommendations
13 Avista Corp.2021 Electric IRP Appendices 291
Interconnection Study Timeline
14 Avista Corp.2021 Electric IRP Appendices 292
Current Interconnection Queue
15 Avista Corp.2021 Electric IRP Appendices 293
Current Queue, continued
16 Avista Corp.2021 Electric IRP Appendices 294
2021 IRP TransmissionCost Estimates
Station Request (MW)POI Voltage Cost Estimate ($ million)
Kootenai County (GF)100 230 kV 4
Kootenai County (GF)200/300 230 kV 80-100
Rathdrum 25/50/100 115 kV <1
Rathdrum 200 115 kV 55
Rathdrum 50/100 230 kV <1
Rathdrum 200 230 kV 60
Benewah 100/200 230 kV <1
Tokio 50/100 115 <1, 20
Othello/Lind 50/100/200 115 kV Queue Issues
Lewiston/Clarkston 100/200 230 kV <1
Northeast 10 115 kV <1
Kettle Falls 12 115 kV <1
Kettle Falls 24/100/124 115 kV <20
Long Lake 68 115 kV 33
Monroe Street 80 115 kV 2
Post Falls 10 115 kV <1
Cabinet Gorge 110 230 kV <14
[1]Preliminary estimates are given as -25% to +75%17
Assume
anti-islanding
scheme, but
no RAS
Avista Corp.2021 Electric IRP Appendices 295
Monroe Street: 80 MW
18
Requires the Metro Rebuild
Project be completed
Avista Corp.2021 Electric IRP Appendices 296
Post Falls: 10 MW to 20 MW
19
Interconnection only
Avista Corp.2021 Electric IRP Appendices 297
Questions?
Avista OASIS link:
http://www.oasis.oati.com/avat/index.html
20 Avista Corp.2021 Electric IRP Appendices 298
Distribution Resource Planning
Damon Fisher, System Planning
Third Technical Advisory Committee Meeting
September 29, 2020
Avista Corp.2021 Electric IRP Appendices 299
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
–Operational flexibility
–Corporate/Regulatory goals
–Affordability
2 Avista Corp.2021 Electric IRP Appendices 300
Distribution Resource Planning
•Washington House Bill 1126 (passed 2019)
–https://app.leg.wa.gov/RCW/default.aspx?cite=19.280.100
–10-Year Plan
–DER’s and Non-Wire Alternatives
–IRP Resource Needs
–Temporal and spatial planning
–Temporal and spatial value
–Probabilistic analysis (Pessimistic, Optimistic)
–Open Planning
3 Avista Corp.2021 Electric IRP Appendices 301
Primary Goal of Distribution Resource Plan
•Where possible, solve distribution grid
deficiencies using distributed energy resources
(DER) that also contribute to system resource
needs as identified in the Integrated Resource
Plan.
4 Avista Corp.2021 Electric IRP Appendices 302
Can IRP resource needs and distribution
“fixes” be aligned? Certainly.
•Not without challenges.
–Temporal need
–Grid operation and flexibility
–Resource adequacy-a new distribution definition?
–System Protection
5 Avista Corp.2021 Electric IRP Appendices 303
Typical Distribution System Deficiencies
•Low Voltage
•Capacity (Substation/Feeder)
•Asset Condition
•Contingency Switching Limits
6 Avista Corp.2021 Electric IRP Appendices 304
What are DER’s? –Distribution’s Perspective
•Anything that can reduce demand or support
voltage
Real
Targeted Energy Efficiency
Targeted Demand Response
Apparent
Storage (Load shifting)
Generation (Load service)
7 Avista Corp.2021 Electric IRP Appendices 305
How Do DER’s Get Implemented?
•Three Paths-
1.Retail/Commercial Customer driven. Customers
install DER’s on their side of the meter for unknown
reasons.
2.The second way would be 3rd party grid connections
(utility scale). We have a few requests in the queue
and a 20MW installation in Lind Washington. These
can cause grid challenges.
3.The third way is utility-driven targeted DER’s to solve
grid issues on either side of the meter. Incentivized
#1 and #2 above.
8 Avista Corp.2021 Electric IRP Appendices 306
System Resources vs. Feeder Demand
9 Avista Corp.2021 Electric IRP Appendices 307
System Resources vs. Feeder Demand
10 Avista Corp.2021 Electric IRP Appendices 308
It Is All About Curves
•The ideal curve-
11 Avista Corp.2021 Electric IRP Appendices 309
It is all about curves
•A real curve (not ideal)-
12 Avista Corp.2021 Electric IRP Appendices 310
Can We Fix Curves with PV?
Community Solar – Summer
13 Avista Corp.2021 Electric IRP Appendices 311
Can We Fix Curves with PV?
Community Solar – Winter
14 Avista Corp.2021 Electric IRP Appendices 312
Can We Fix Curves with Just PV?
Community Solar –Cloudy Day, Battery
15 Avista Corp.2021 Electric IRP Appendices 313
Capacity Projects
53 Flint Road Station
Scope not complete.New distribution station located north of
Spokane along the Airway Heights -
Sunset 115 kV Transmission Line.
Q3
2022
Budgeted
Not
Scoped
98 Midway Station
Scope not complete.
New distribution station located north of
Spokane along the Bell –Addy 115 kV Transmission Line.
Q1 2023
Budgeted
Not Scoped
80 Huetter Station Expansion
Scope not complete.Rebuild existing distribution station to
two 30MVA transformers, 6 feeders,
and looped through transmission with circuit breakers.
Q1 2025
Budgeted
Not Scoped
16 Avista Corp.2021 Electric IRP Appendices 314
Locations
17 Avista Corp.2021 Electric IRP Appendices 315
DRP Implementation Gaps
•Spatial Load Forecasting
•Spatial DER Forecasting
•System Performance Criteria
•DER Acquisition and Implementation Processes
•Engineering/Operational Expertise
18 Avista Corp.2021 Electric IRP Appendices 316
Interesting Distribution Efforts
•AMI data load disaggregation
•Hosting Capacity Maps
–Example Hosting Capacity map:
https://www.arcgis.com/apps/webappviewer/index.html?id=84de
299296d649808f5a149e16f2d87c
•Northwest Utility DER Technical Discussion
19 Avista Corp.2021 Electric IRP Appendices 317
Questions?
20 Avista Corp.2021 Electric IRP Appendices 318
Energy solutions. Delivered.
AVISTA DR POTENTIAL STUDY
Preliminary Results Slide Deck –Sep 28, 2020
Avista Corp.2021 Electric IRP Appendices 319
| 2Applied Energy Group · www.appliedenergygroup.com
Methodology
Program Characterization
Preliminary Impacts
Next Steps
AGENDA
Avista Corp.2021 Electric IRP Appendices 320
Methodology
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| 4Applied Energy Group · www.appliedenergygroup.com
Data Collection
•Align with EE Potential study
•Market Profiles
•Secondary Sources
•Industry or regional reports & previous studies
Characterize the Market
•Segmentation by Customer Class
•Residential and C&I (General Service, Large General Service and Extra Large General Service)
Develop list of DR Options
•DLC
•Third Party
•Storage
•Rates
•Ancillary Services
Characterize the Options
•Develop Program Assumptions
•Impacts, Participation, Technology, Costs, Incentives
Estimate Potential
•
•
•Realistic Achievable Potential
•Integrated case of cost-effective programs
APPROACH TO THE STUDY
Analysis Inputs Baseline Forecast Program List Potential Inputs Final Results
Avista Corp.2021 Electric IRP Appendices 322
| 5Applied Energy Group · www.appliedenergygroup.com
𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝐼𝐼𝑃𝑃𝐼𝐼𝑃𝑃𝐼𝐼𝐼𝐼𝑦𝑦𝑦𝑦𝑦𝑦𝑦𝑦,𝑝𝑝𝑦𝑦𝑝𝑝𝑝𝑝𝑦𝑦𝑦𝑦𝑝𝑝=𝑃𝑃𝑃𝑃𝑃𝑃𝐶𝐶𝐶𝐶𝐶𝐶𝐼𝐼𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝐼𝐼𝑃𝑃𝐼𝐼𝑃𝑃𝐼𝐼𝐼𝐼∗𝐸𝐸𝐸𝐸𝐸𝐸𝑃𝑃𝐸𝐸𝐸𝐸𝐸𝐸𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝐼𝐼𝐸𝐸𝐼𝐼𝐸𝐸𝐼𝐼𝑃𝑃𝑃𝑃𝐼𝐼𝐶𝐶∗𝑃𝑃𝑃𝑃𝑃𝑃𝐼𝐼𝐸𝐸𝐼𝐼𝐸𝐸𝐼𝐼𝑃𝑃𝐼𝐼𝐸𝐸𝑃𝑃𝑃𝑃 𝑅𝑅𝑃𝑃𝐼𝐼𝑃𝑃∗𝐸𝐸𝐸𝐸𝐶𝐶𝐸𝐸𝐼𝐼𝑃𝑃𝑃𝑃𝑃𝑃𝐼𝐼𝑆𝑆𝑃𝑃𝐼𝐼𝐶𝐶𝑃𝑃𝑃𝑃𝐼𝐼𝐸𝐸𝑃𝑃𝑃𝑃𝑅𝑅𝑃𝑃𝐼𝐼𝑃𝑃
where:
Year= Forecasted year between 2022 and 2045
CALCULATION OF IMPACT (MW)
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Program Characterization
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| 7Applied Energy Group · www.appliedenergygroup.com
DR PROGRAM OPTIONS
Program Type Program Option Mechanism
Curtailable /
Controllable DR
DLC with two-way communicating or Smart T-stats Internet-enabled control of thermostat set points, can be coupled with any dynamic pricing
rate
DLC switch installed on customer’s Central AC
Modular communications interface for water heaters that will become the new technology
standard
DLC switch installed on customer’s Water Heater
Automated, fast-responding curtailment strategies with advanced telemetry capabilities
suitable for load balancing, frequency regulation, etc. Equipment considered for this option
includes:
Internet-enabled control of operational cycles of white goods appliances
DLC switch installed on customer’s equipment
Includes the following three measure options
Capacity Bidding Customers volunteer a specified amount of capacity during a predefined “economic event”
called by the utility in return for a financial incentive.
Emergency Curtailment Agreements Customers enact their customized, mandatory curtailment plan. May use stand-by
generation. Penalties apply for non-performance.
Demand Buyback Customers enact their customized, voluntary curtailment plan. May use stand-by generation.
No penalties for non-performance. Requires AMI technology.
Peak shifting of loads using stored electrochemical energy
Voluntary DR reductions in response to behavioral messaging. Example programs exist in CA
and other states. Requires AMI technology.
Peak shifting of primarily space cooling or heating loads using a thermal storage medium
such as water or ice
Higher rate for a particular block of hours that occurs every day. Requires either on/off peak
meters or AMI technology.
Much higher rate for a particular block of hours that occurs only on event days. Requires AMI
technology. Avista Corp.2021 Electric IRP Appendices 325
| 8Applied Energy Group · www.appliedenergygroup.com
Some of the options require AMI
•DLC Options-No AMI Metering Required
•Dynamic Rates-require AMI for billing
•Ancillary Options-require two way communicating controls
currently has 93% AMI saturation
•Assume 100% saturation by 2022
will start AMI rollout in 2022 and will take 18 months to fully deploy
•Assume 33% saturation in 2022 and 100% by 2024
AMI ASSUMPTIONS
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| 9Applied Energy Group · www.appliedenergygroup.com
Sources:
•DLC Central AC–NWPCC DLC Switch cooling assumption-5 yr ramp rate•DLC Smart Thermostats (Cooling)–NWPCC Smart Thermostat cooling assumption-5 yr ramp rate•DLC Smart Thermostats (Heating)–Agreed upon estimate with Avista. NWPC participation estimate was too high.•CTA –2045 WH -NWPCC Grid interactive WH assumptions.•DLC Water Heating –Best estimate based on industry experience –in line with other DLC programs•DLC Electric Vehicle Charging –NWPC Electric Resistance Grid-Ready Summer/Winter Participation-10 yr ramp rate•DLC Smart Appliances -2015 ISACA IT Risk Reward Barometer -US Consumer Results. October 2015. http://www.isaca.org/SiteCollectionDocuments/2015-risk-reward-survey/2015-isaca-risk-reward-consumer-summary-us_res_eng_1015.pdf
PARTICIPATION RATES
DLC PROGRAM OPTIONS
Program Option Residential General Service Large General
Service
Extra Large
General Service
DLC Central AC 10%10%
DLC Smart Thermostats -Cooling 20%20%
DLC Smart Thermostats -Heating 5%3%
CTA-2045 WH 50%50%
DLC Water Heating 15%5%
DLC Electric Vehicle Charging 25%
DLC Smart Appliances 5%5%
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| 10Applied Energy Group · www.appliedenergygroup.com
Sources:
•Third Party Contracts –Best estimate based on industry experience
•Thermal Energy Storage –Best estimate based on industry experience
•Battery Energy Storage –Best estimate based on industry experience
•Behavioral -PG&E rollout with six waves http://www.calmac.org/publications/DNVGL_PGE_HERs_2015_final_to_calmac.pdf
•Time-of-Use Rates –Best estimate based on industry experience; Brattle Analysis and Estimate; Winter impacts ½ of summer impacts
•Variable Peak Pricing Rates -OG&E 2017 Smart Hours Study
•Real Time Pricing -Best estimate based on industry experience
PARTICIPATION RATES
RATES AND STORAGE
Program Option Residential General Service Large General
Service
Extra Large
General Service
Third Party Contracts 15%20%20%
Thermal Energy Storage 0.5%1.5%1.5%
Battery Energy Storage 0.5%0.5%0.5%0.5%
Behavioral 20%
Time-of-Use Opt-in 13%13%13%13%
Time-of-Use Opt-out 74%74%74%74%
Variable Peak Pricing Rates 25%25%25%25%
Avista Corp.2021 Electric IRP Appendices 328
| 11Applied Energy Group · www.appliedenergygroup.com
PEAK IMPACTS
DLC PROGRAMS
Season Program Option Residential General Service Large General
Service
Extra Large
General Service
Summer only DLC Central AC 0.5 kW 1.25 kW
Summer only DLC Smart Thermostats -Cooling 0.5 kW 1.25 kW
Winter only DLC Smart Thermostats -Heating 1.09 kW 1.35 kW
Annual CTA-2045 WH 0.5 kW 1.26 kW
Annual DLC Water Heating 0.5 kW 1.26 kW
Annual DLC Electric Vehicle Charging 0.5 kW
Annual DLC Smart Appliances 0.14 kW 0.14 kW
Sources:
•DLC Central AC and Smart Thermostats (Cooling)–NWPC DLC Switch cooling assumption was close to 1.0 kW reduced to adjust for Avista proposed cycling strategy, Thermostats equal to switch
•DLC Smart Thermostats (Heating)–NWPC Smart thermostat heating assumption (east)
•CTA-2045 Water Heating -NWPC Electric Resistance Grid-Ready Summer/Winter Impact, Gen Service is 2.52x that of res based on DLC Central AC Res to C&I ratio
•DLC Water Heating-NWPC Electric Resistance Switch Summer Impact, Gen Service is 2.52x that of res based on DLC Central AC Res to C&I ratio
•DLC Electric Vehicle Charging –Based on Avista Research
•DLC Smart Appliances -Ghatikar, Rish. Demand Response Automation in Appliance and Equipment. Lawrence Berkley National Laboratory, 2015. Web. http://docketpublic.energy.ca.gov/PublicDocuments/15-IEPR-05/TN205072_20150618T110004_Demand_Response_Automation_in_Appliances_and_Equipment.pptxAvista Corp.2021 Electric IRP Appendices 329
| 12Applied Energy Group · www.appliedenergygroup.com
PEAK IMPACTS
RATES AND OTHER OPTIONS
Season Program Option Residential General Service Large General Service Extra Large General Service
Annual Third Party Contracts 10%21%21%
Annual Thermal Energy Storage 1.7 kW 8.4 kW 8.4 kW
Annual Battery Energy Storage 2 kW 2 kW 15 kW 15 kW
Annual Behavioral 2%
Annual Time-of-Use Rate Opt-in 5.7%0.2%2.6%3.1%
Annual Time-of-Use Rate Opt-out 3.4%0.2%2.6%3.1%
Annual Variable Peak Pricing Rates 10%4%4%4%
Sources:
•Third Party Contracts - Weighted average impacts from report: Impact Estimates from Aggregator Programs in California (Source: 2019 Statewide Load Impact Evaluation of California Aggregator Demand Response Programs)
•Thermal Energy Storage -Ice Bear Tech Specifications, https://www.ice-energy.com/wp-content/uploads/2016/03/ICE-BEAR-30-Product-Sheet.pdf
•Battery Energy Storage –Typical Battery size per segment•Behavioral -Opower documentation for BDR with Consumers and DTE
•Time-of-Use Rates –Brattle Analysis and Estimate -PacifiCorp 2019 opt-in and opt-out scenarios. Summer Impacts Shown (Winter impacts ½ summer)
•Variable Peak Pricing Rates -OG&E 2018 Smart Hours Study, Summer Impacts Shown (Winter impacts ¾ summer)
Avista Corp.2021 Electric IRP Appendices 330
| 13Applied Energy Group · www.appliedenergygroup.com
AVERAGE EVENT DURATION FOR
DLC OPTIONS
Option Annual Event Hours Average Duration per Event Max Event Duration
Central AC 50 3 hrs 6 hrs
Smart Thermostats -Cooling 36 3 hrs 6 hrs
Smart Thermostats -Heating 36 3 hrs 6 hrs
Water Heating 100 3 hrs 6 hrs
Electric Vehicle Charging 528 6 hrs 8 hrs
Smart Appliances 528 6 hrs 8 hrs
Third Party Contracts 30 4 hrs 8 hrs
Avista Corp.2021 Electric IRP Appendices 331
Technical Achievable Potential
DLC Options
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| 15Applied Energy Group · www.appliedenergygroup.com
TECHNICAL ACHIEVABLE POTENTIAL
WINTER -DLC OPTIONS
Sector Option 2022 2025 2035 2045
Residential DLC Central AC ----
CTA-2045 WH 0.0 1.3 21.1 38.5
DLC Water Heating 0.5 4.3 4.7 4.6
DLC Smart Appliances 0.3 2.4 3.0 3.3
DLC Smart Thermostats -Cooling ----
DLC Smart Thermostats -Heating 0.8 7.8 9.5 10.5
DLC Electric Vehicle Charging -0.3 5.6 30.2
DLC Central AC ----
CTA-2045 WH 0.0 0.3 5.2 10.4
DLC Water Heating 0.1 0.6 0.8 0.9
DLC Smart Appliances 0.0 0.3 0.3 0.4
DLC Smart Thermostats -Cooling ----
DLC Smart Thermostats -Heating 0.0 0.2 0.3 0.3
Third Party Contracts 4.6 21.9 21.8 21.9
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| 16Applied Energy Group · www.appliedenergygroup.com
TECHNICAL ACHIEVABLE POTENTIAL
SUMMER -DLC OPTIONS
Sector Option 2022 2025 2035 2045
Residential DLC Central AC 0.6 6.8 14.5 23.7
CTA-2045 WH 0.0 1.3 21.1 38.5
DLC Water Heating 0.5 4.3 4.7 4.6
DLC Smart Appliances 0.3 2.4 3.0 3.3
DLC Smart Thermostats -Cooling 1.2 13.5 29.1 47.4
DLC Smart Thermostats -Heating ----
DLC Electric Vehicle Charging -0.3 5.6 30.2
DLC Central AC 0.2 1.9 4.1 6.8
CTA-2045 WH 0.0 0.3 5.2 10.4
DLC Water Heating 0.1 0.6 0.8 0.9
DLC Smart Appliances 0.0 0.3 0.3 0.4
DLC Smart Thermostats -Cooling 0.3 3.8 8.3 13.5
DLC Smart Thermostats -Heating ----
Third Party Contracts 4.5 21.4 21.3 21.4
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Technical Achievable Potential
Rates and Other Options
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| 18Applied Energy Group · www.appliedenergygroup.com
TECHNICAL ACHIEVABLE POTENTIAL
WINTER -RATES AND OTHER OPTIONS
Sector Option 2022 2025 2035 2045
Residential Time-of-Use Opt-in 0.4 5.0 5.9 6.2
Time-of-Use Opt-out 19.6 19.4 20.0 21.1
Variable Peak Pricing Rates 1.4 16.8 19.7 20.8
Battery Energy Storage 0.1 0.6 4.3 4.8
Behavioral 0.6 3.0 3.1 3.3
Time-of-Use Opt-in 0.1 1.4 1.6 1.5
Time-of-Use Opt-out 10.4 9.2 8.9 8.8
Variable Peak Pricing Rates 0.5 5.3 6.0 6.1
Thermal Energy Storage ----
Battery Energy Storage 0.0 0.1 0.7 0.8
Avista Corp.2021 Electric IRP Appendices 336
| 19Applied Energy Group · www.appliedenergygroup.com
TECHNICAL ACHIEVABLE POTENTIAL
SUMMER -RATES AND OTHER OPTIONS
Sector Option 2022 2025 2035 2045
Residential Time-of-Use Opt-in 0.5 5.4 6.3 6.6
Time-of-Use Opt-out 21.1 20.7 21.4 22.5
Variable Peak Pricing Rates 1.5 17.9 21.0 22.2
Battery Energy Storage 0.1 0.6 4.3 4.8
Behavioral 0.6 3.2 3.4 3.5
Time-of-Use Opt-in 0.1 1.4 1.5 1.5
Time-of-Use Opt-out 10.1 8.9 8.6 8.5
Variable Peak Pricing Rates 0.5 5.2 5.9 6.0
Thermal Energy Storage 0.1 0.7 0.8 0.8
Battery Energy Storage 0.0 0.1 0.7 0.8
Avista Corp.2021 Electric IRP Appendices 337
Ancillary Services
By Option
Avista Corp.2021 Electric IRP Appendices 338
| 21Applied Energy Group · www.appliedenergygroup.com
Participation Assumptions
•Full for Battery/EV/WH
•Half for Heating/Cooling
•Third Party based on saturations of EMS systems for PAC C&I
•Full for Battery/WH
•75% for Third Party
•Half for Heating/Cooling/EV
ANCILLARY SERVICE ASSUMPTIONS
Ancillary Option
Battery Energy Storage
Electric Vehicle Charging
DLC Smart Thermostats- Cooling
DLC Smart Thermostats- Heating
DLC Water Heaters
CTA-2045 Water Heaters
Third Party Contracts
Avista Corp.2021 Electric IRP Appendices 339
| 22Applied Energy Group · www.appliedenergygroup.com
ANCILLARY SERVICES
TECHNICAL ACHIEVABLE POTENTIAL
Avista Corp.2021 Electric IRP Appendices 340
DR Event Shapes
Load Shifting Assumptions
Avista Corp.2021 Electric IRP Appendices 341
| 24Applied Energy Group · www.appliedenergygroup.com
In order to incorporate the impacts into the IRP we need to understand how an even effects overall consumption
Depending on the program type, calling an event can have different effects
•Save energy (0% shift)
•Shift energy (100% shift)
•Partial shift
The next slide will show specific examples of each
SHIFT OR SAVE
Graph shows typical event shape
for a Residential Variable Peak
Pricing program
Avista Corp.2021 Electric IRP Appendices 342
| 25Applied Energy Group · www.appliedenergygroup.com
EVENT LOAD SHAPES
Program
State
Season Winter Summer Winter Summer Winter Summer Winter Summer Winter Summer Winter Summer Winter Summer Winter Summer
Pre-Event Shift Ratio 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 35% 35% 35% 35%
Post-Event Shift Ratio 65% 65% 65% 65% 100% 100% 100% 100% 0% 0% 0% 0% 65% 65% 65% 65%
Impact at Peak (kW)0.50 0.50 0.50 0.50 0.50 0.50 0.50 0.50
Peak Impact Percentage 24.9% 23.1% 26.7% 25.5% 24.9% 23.1% 26.7% 25.5% 2.9% 5.7% 2.9% 5.7% 7.5% 10.0% 7.5% 10.0%
Hour Ending
1 - - - - - - - - - - - - - - - -
14 - - - - - - - - - - - - - - - -
15 - - - - - - - - - - - - (0.08) (0.11) (0.07) (0.10)
16 - - - - - - - - - - - - (0.08) (0.11) (0.07) (0.10)
17 0.43 0.46 0.46 0.46 0.46 0.46 0.46 0.46 0.05 0.11 0.05 0.10 0.14 0.20 0.13 0.18
18 0.46 0.49 0.50 0.49 0.50 0.49 0.50 0.49 0.06 0.12 0.05 0.11 0.15 0.21 0.14 0.19
19 0.46 0.50 0.50 0.50 0.50 0.50 0.50 0.50 0.06 0.12 0.05 0.11 0.15 0.22 0.14 0.20
20 (0.29) (0.31) (0.32) (0.31) (0.37) (0.36) (0.37) (0.36) - - - - (0.10) (0.14) (0.09) (0.12)
21 (0.29) (0.31) (0.32) (0.31) (0.37) (0.36) (0.37) (0.36) - - - - (0.10) (0.14) (0.09) (0.12)
22 (0.29) (0.31) (0.32) (0.31) (0.37) (0.36) (0.37) (0.36) - - - - (0.10) (0.14) (0.09) (0.12)
23 - - - - (0.37) (0.36) (0.37) (0.36) - - - - - - - -
24 - - - - - - - - - - - - - - - -
Full Shift spread out before/after event
Time-Of-Use Opt-In
WA ID
Partial Shift Full Shift Full Save
Variable Peak Pricing
WA ID
DLC Central AC
WA ID
CTA-2045 Water Heating
WA ID
Avista Corp.2021 Electric IRP Appendices 343
Next Steps
Avista Corp.2021 Electric IRP Appendices 344
| 27Applied Energy Group · www.appliedenergygroup.com
Finalize Technical Achievable Potential
Characterize Program Costs
Estimate Achievable Potential
•Integrated case
•Calculate levelized costs
Finalize Results
NEXT STEPS
Avista Corp.2021 Electric IRP Appendices 345
Kelly Marrin, Managing Director
[e-mail]
Tommy Williams, Lead Analyst
[e-mail]
Avista Corp.2021 Electric IRP Appendices 346
Energy solutions. Delivered.
2020 CONSERVATION POTENTIAL
ASSESSMENT –UPDATE
Prepared for the Avista Technical Advisory Commitee
September 29, 2020Avista Corp.2021 Electric IRP Appendices 347
| 2Applied Energy Group · www.appliedenergygroup.com
AGENDA
Topics
•AEG Introduction
•AEG’s CPA Methodology
•Electric CPA Summary
•DR Analysis Summary
•Natural Gas CPA Summary
Avista Corp.2021 Electric IRP Appendices 348
| 3Applied Energy Group · www.appliedenergygroup.com
ABOUT AEG
Planning
Baseline studies
Market
assessment studies
Program design &
action plans
End-use forecasting
EM&V
EE portfolio & targeted programs
Demand response programs & dynamic pricing
Pilot design & experimental design
Behavioral programs
Implementation &
Technical Services
Engineering review, due-diligence, QA/QC
M&V, modeling &
simulation, onsite
assessments
Technology R&D and data tools (DEEM)
Program admin,
marketing,
implementation,
application processing
Market Research
Program / service pricing
optimization
Process evaluations
Market assessment /
saturation surveys
Customer satisfaction /
customer engagement
Market segmentation
VISION DSMTM Platform
Full DSM lifecycle tracking & reporting
Avista Corp.2021 Electric IRP Appendices 349
| 4Applied Energy Group · www.appliedenergygroup.com
Including Potential Studies and End-Use Forecasting
AEG has conducted more than 60 planning studies for more than 40 utilities /
organizations in the past five years.
AEG has a team of 11 experienced Planning staff plus support from AEG’s
Technical Services and Program Evaluation groups
AEG EXPERIENCE IN PLANNING
Northwest & Mountain:Avista*BPA*Cascade Natural GasChelan PUDCheyenne LFPColorado Electric*Cowlitz PUD*
Inland P&L*Oregon Trail ECPacifiCorp*PNGCPGE*Seattle City Light*Tacoma Power*
HECOLADWPNV Energy*Public Service New Mexico* State of HawaiiState of New MexicoXcel/SPS
Ameren Illinois*Ameren Missouri*Citizens EnergyEmpire District ElectricIndianapolis P&L*Indiana & Michigan Utilities
Kansas City Power & Light MERCNIPSCO*Omaha Public Power DistrictState of MichiganVectren Energy*
Central Hudson G&E*Con Edison of NY*New Jersey BPUPECO EnergyPSEG Long IslandState of Maryland (BG&E, DelMarva, PEPCO, Potomac Edison, SMECO)
Midcontinent ISO*EEI/IEE*EPRI FERC
OG&EKentucky PowerSouthern Company (APC,GPC, Gulf Power, MPC)TVA
Avista Corp.2021 Electric IRP Appendices 350
AEG CPA Methodology
Avista Corp.2021 Electric IRP Appendices 351
| 6Applied Energy Group · www.appliedenergygroup.com
The Avista Conservation Potential Assessment (CPA) supports the Company’s regulatory filing and other demand-side management (DSM) planning efforts and initiatives.
The two primary research objectives for the 2020 CPA are:
•Program Planning:insights into the market for electric and natural gas energy efficiency (EE) measures and electric demand response (DR) measures in
Avista’s Washington and Idaho service territories
For example, CPAs provide insight into changes to existing program measures as well
as new measures to consider
•IRP: long-term forecast of future EE and DR potential for use in the IRP
Technical Achievable Potential (TAP) for electricity
Economic Achievable Potential (EAP) for natural gas
AEG utilizes its comprehensive LoadMAP analytical models that are
customized to Avista’s service territory.
CPA OBJECTIVES
Avista Corp.2021 Electric IRP Appendices 352
| 7Applied Energy Group · www.appliedenergygroup.com
Overview –Electric and GasOVERVIEW OF AEG’S APPROACH
Market Characterization
•Avista control totals•Customer account data
•Secondary data•Avista market research
Identify Demand-Side Resources
•EE technologies
•EE measures•Emerging measures and technologies
Baseline Projection
•Avista Load Forecast•Customer growth
•Standards and building codes•Efficiency options
•Purchase Shares
Potential Estimation
•Technical•Technical Achievable
•Economic Screen (TRC and UCT) are handled by Avista’s IRP
Avista Corp.2021 Electric IRP Appendices 353
| 8Applied Energy Group · www.appliedenergygroup.com
Prioritization of Avista Data
Data from Avista was prioritized when available, followed by regional data, and finally well-vetted national data.
•2013 Residential GenPop Survey
•Forecast data and load research
•Recent-year accomplishments and plans
•NEEA studies (RBSA 2016, CBSA 2019, IFSA)
•RTF and Power Council methodologies, ramp rates, and measure assumptions
•U.S. DOE’s Annual Energy Outlook
•U.S. DOE’s projections on solid state lighting technology improvements
•Technical Reference Manuals and California DEER
•AEG Research
KEY SOURCES OF DATA
Avista Corp.2021 Electric IRP Appendices 354
| 9Applied Energy Group · www.appliedenergygroup.com
Overview
“How much energy would customers use in the future if Avista stopped running programs now and in the absence of naturally occurring efficiency?”
•The baseline projection answers this question
The baseline projection is an independent end-use forecast of electric or natural gas consumption at the same level of detail as the market profile
BASELINE PROJECTION
Includes
•To the extent possible, the same forecast drivers used in
the official load forecast, particularly customer growth,
natural gas prices, normal weather, income growth, etc.
•Trends in appliance saturations, including distinctions for
new construction.
•Efficiency options available for each technology , with share of purchases reflecting codes and standards (current and finalized future standards)
•Expected impact of appliance standards that are “on the
books”
•Expected impact of building codes, as reflected in market profiles for new construction
•Market baselines when present in regional planning
assumptions
Excludes
•Expected impact of naturally occurring efficiency (except
market baselines)
•Exception:RTF workbooks have a market baseline for lighting, which AEG’s models also use.
•Impacts of current and future demand-side management
programs
Avista Corp.2021 Electric IRP Appendices 355
Electric CPA
Avista Corp.2021 Electric IRP Appendices 356
| 11Applied Energy Group · www.appliedenergygroup.com
AVISTA 2020 ELECTRIC CPA
CPA Methodology Overview
•Levels of Potential
•Economic Evaluation and IRP Integration
•Retained enhancements from 2018 Action Plan
Summary of EE Results
•Summary of Potential
High level results
Top measures
Potential by cost bundles
•Comparison to previous CPA
Summary of DR Results
Avista Corp.2021 Electric IRP Appendices 357
| 12Applied Energy Group · www.appliedenergygroup.com
•Focus of the study is to explore a wide range of options for reducing annual energy use
•This study develops two sets of estimates:
•Technical potential (TP): everyone chooses the mostefficient option possible when equipment fails
•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 utility-and non-utility driven mechanisms
•To better emulate likely programs, Technical Achievable
Potential calculates savings from efficient options more likely
to be selected by the IRP
•In addition to these estimates, the study produces cost data for the TRC and UCT tests that can be used by Avista’s IRP process to select energy efficiency measures in competition with other resources
TWO LEVELS OF SAVINGS ESTIMATES
Technical
Technical
Achievable
Power Council Methodology
Avista Corp.2021 Electric IRP Appendices 358
| 13Applied Energy Group · www.appliedenergygroup.com
Two Cost-Effectiveness TestsECONOMIC METRICS
AEG provided a levelized net cost of energy ($/kWh) for each measure within the achievable potential within Avista’s Washington and Idaho territories from two perspectives.
•Utility Cost Test (UCT): Assesses cost-effectiveness from a utility or
program administrator’s perspective.
•Total Resource Cost Test (TRC):
Assesses cost-effectiveness from the
utility’s and participant’s perspectives. Includes non-energy
impacts if they can be quantified and monetized.
Component UCT TRC
Avoided Energy Benefit Benefit
Non-Energy Benefits*Benefit
Incremental Cost Cost
Incentive Cost
Administrative Cost Cost Cost
Non-Energy Costs* (e.g. O&M)Cost
*Council methodology includes monetized impacts on other fuels within these categories
Both values are provided to Avista for all measure level potential, so that the IRP can use the appropriate evaluation for each state: TRC for WA and UCT for ID.
Avista Corp.2021 Electric IRP Appendices 359
| 14Applied Energy Group · www.appliedenergygroup.com
AEG has preserved the enhancements to the CPA process that were included in the previous CPA:
•Any measures screened out in advance of technical potential are documented in the measure list along with the reason. As before, very few measures were
excluded in this step
Measures that were excluded were generally either emerging measures with
insufficient data to characterize properly, or highly custom measures that are instead modeled within broader retrocommissioning or strategic energy management programs.
•Full Technical Achievable potential is provided to the IRP along with TRC and
UCT costs for each measure
•The Measure Assumptions appendix is again available, containing UES data
and other key assumptions and their sources
•Demand Response potential includes analysis of both Summer and Winter possible programs
ENHANCEMENTS RETAINED FROM 2018
CPA
Avista Corp.2021 Electric IRP Appendices 360
| 15Applied Energy Group · www.appliedenergygroup.com
Achievability
All potential “ramps up” over time –all ramp rates are based
on those found within the NWPCC’s 2021 Power Plan
•Max Achievability
•NWPCC 2021 Plan allows some measures
max achievability to reach up to 100% of
technical potential
•7th Power Plan and prior CPA had a max achievability of 85%
•AEG has aligned assumptions with the 2021
Plan and measures such as lighting reach
greater than 85%
•Please note Power Council’s ramp rates include potential realized from outside of utility DSM programs, including regional
initiatives and market transformation
POTENTIAL ESTIMATES
Measures examples over 85% Achievability:
•All Lighting
•Washers/Dryers
•Dishwashers
•Refrigerators/Freezers
•Circulation Pumps
•Thermostats
•C&I Fans
Avista Corp.2021 Electric IRP Appendices 361
| 16Applied Energy Group · www.appliedenergygroup.com
Potential Summary –WA & ID All SectorsENERGY EFFICIENCY POTENTIAL
Projections indicate that energy savings of ~1.0% of baseline consumption per year are Technically Achievable.
•190 GWh (22 aMW) in biennium period (2022-2023)
•1,317 GWh (150 aMW) by 2031
•This level of savings offsets future load growth
-
2,000.0
4,000.0
6,000.0
8,000.0
10,000.0
12,000.0
GWh
Annual Energy Projections
Baseline Projection
Achievable Technical Potential
Technical Potential
0
50
100
150
200
250
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Annual Incremental Potential (GWh)
Achievable Technical Potential Technical Potential
Avista Corp.2021 Electric IRP Appendices 362
| 17Applied Energy Group · www.appliedenergygroup.com
EE POTENTIAL, CONTINUEDPotential Summary –WA & ID, All Sectors
Summary of Energy Savings (GWh),
Selected Years 2022 2023 2025 2031 2041 2045
Reference Baseline
Cumulative Savings (GWh)
Technical Achievable Potential
Technical Potential
Energy Savings (% of Baseline)
Technical Achievable Potential
Technical Potential
Incremental Savings (GWh)
Technical Achievable Potential
Technical Potential
0
500
1,000
1,500
2,000
2,500
2022 2025 2028 2031 2034 2037 2040 2043
Cumulative ATP Savings (GWh) by Sector
Residential Commercial Industrial
0%
5%
10%
15%
20%
25%
30%
35%
2022 2023 2025 2031 2041 2045
% of
Baseline
Cumulative Electric Savings, selected years
Technical Achievable Potential Technical Potential
Avista Corp.2021 Electric IRP Appendices 363
| 18Applied Energy Group · www.appliedenergygroup.com
ATP Peak Savings Summary –WA & ID, All SectorsEE POTENTIAL -CONTINUED
EE Peak Savings (MW),
Selected Years 2022 2023 2025 2031 2041 2045
Reference Baseline
Summer Peak MW
Winter Peak MW
Cumulative Savings (MW)
Summer Peak
Winter Peak
Cumulative Savings (% of Baseline)
Summer Peak
Winter Peak
Incremental Savings (MW)
Summer Peak
Winter Peak
-
50
100
150
200
250
300
350
400
2022 2025 2028 2031 2034 2037 2040 2043
ATP Summer Peak Savings (MW)
Residential Commercial Industrial
-
50
100
150
200
250
300
350
400
2022 2025 2028 2031 2034 2037 2040 2043
ATP Winter Peak Savings (MW)
Residential Commercial Industrial
Avista Corp.2021 Electric IRP Appendices 364
| 19Applied Energy Group · www.appliedenergygroup.com
Achievable Technical Potential –WA & IDEE POTENTIAL BY SECTOR
2022 2023 2024 2031 2041
Baseline projection (GWh)
Residential 3,774 3,785 3,796 3,953 4,489
Commercial 3,223 3,234 3,248 3,427 3,924
Industrial 845 843 839 812 780
Total Consumption (GWh)7,842 7,863 7,883 8,192 9,193
ATP Cumulative Savings (GWh)
Residential 32 72 120 623 1,004
Commercial 46 97 152 583 819
Industrial 10 21 33 110 151
Total Savings (GWh)88 190 304 1,317 1,974
ATP Cumulative Savings (aMW)
Residential 4 8 14 71 115
Commercial 5 11 17 67 94
Industrial 1 2 4 13 17
Total Savings (aMW)10 22 35 150 225
ATP Cumulative Savings as a % of Baseline
Residential 0.8%1.9%3.1%15.8%22.4%
Commercial 1.4%3.0%4.7%17.0%20.9%
Industrial 1.2%2.5%3.9%13.6%19.3%
Total Savings (% of Baseline)1.1%2.4%3.9%16.1%21.5%
0.0%
5.0%
10.0%
15.0%
20.0%
25.0%
2022 2023 2024 2031 2041
ATP Savings by Sector (% of Baseline)
Residential Commercial Industrial
0
500
1,000
1,500
2,000
2,500
2022 2025 2028 2031 2034 2037 2040 2043
Cumulative ATP Savings (GWh) by Sector
Residential Commercial Industrial
Avista Corp.2021 Electric IRP Appendices 365
| 20Applied Energy Group · www.appliedenergygroup.com
Cumulative Potential Summary –WA & ID All SectorsEE POTENTIAL -TOP MEASURES
Technical Achievable Potential, Ranked by Savings in 2031 (MWh)
Rank Measure / Technology
2023 Achievable
(MWh)
% of Total
2031 Achievable
(MWh)
% of Total
TRC
Levelized
$/kWh
UCT
Levelized
$/kWh
1 -Linear Lighting 9,139 62,302
2 -Retrocommissioning 9,318 59,994
3 -Water Heater <= 55 Gal 2,647 55,156
4 -Strategic Energy Management 7,047 44,581
5 -Ductless Mini Split Heat Pump (Zonal)6,599 42,085
6 -ENERGY STAR -Connected Thermostat 5,890 40,216
7 -Windows -High Efficiency/ENERGY STAR 5,808 35,780
8 -Ductless Mini Split Heat Pump with Optimized 1,485 33,420
9 -Home Energy Management System (HEMS)4,975 30,271
10 -Windows -Cellular Shades 988 28,248
11 -HVAC -Dedicated Outdoor Air System (DOAS)3,054 21,141
12 -Insulation -Basement Sidewall Installation 2,933 20,698
13 -Space Heating -Heat Recovery Ventilator 5,128 20,274
14 -High-Bay Lighting 4,123 19,394
15 -Windows -Low-e Storm Addition 2,832 18,790
16 -Furnace -Conversion to Air-Source Heat Pump 639 15,407
17 -High-Bay Lighting 6,056 14,687
18 -General Service Lighting 3,181 13,705
19 -Interior Lighting -Embedded Fixture Controls 2,470 13,523
20 -Connected Line-Voltage Thermostat 1,817 13,433
Total of Top 20 Measures 86,126 603,105
190,351 1,316,823Avista Corp.2021 Electric IRP Appendices 366
| 21Applied Energy Group · www.appliedenergygroup.com
WA & ID Technical Achievable Potential by 2031SUPPLY CURVES
$-
$0.20
$0.40
$0.60
$0.80
$1.00
- 500,000 1,000,000 1,500,000 2,000,000
Levelized
Cost of
Energy
($/kWh)
Cumulative Savings (MWh)
TRC Conservation Supply Curve, 2031
Achievable Technical Potential Technical Potential
$-
$0.20
$0.40
$0.60
$0.80
$1.00
- 500,000 1,000,000 1,500,000 2,000,000
Levelized
Cost of
Energy
($/kWh)
Cumulative Savings (MWh)
UCT Conservation Supply Curve, 2031
Achievable Technical Potential Technical Potential
Avista Corp.2021 Electric IRP Appendices 367
| 22Applied Energy Group · www.appliedenergygroup.com
Top Measure Notes
•Some expensive or emerging measures have significant potential, but may not be selected by the IRP due to costs
•Heat Pump measures, including DHPs and HPWHs, have significant annual energy benefits, however since heat pumps revert to electric resistance heating during extreme cold, they do not have a corresponding winter peak benefit
•In addition to being expensive, some emerging tech measures are included in Technical Achievable which may not prove feasible for programs at this time, but can be kept in mind for future programs, e.g.:
•Advanced New Construction –Zero Net Energy
•Connected Home Control Systems
EE POTENTIAL
Avista Corp.2021 Electric IRP Appendices 368
| 23Applied Energy Group · www.appliedenergygroup.com
Top Measures -Winter Peak (MW) Reduction
by 2031
2031
MW
% of
Total
1 -ENERGY STAR -Connected Thermostat
2 -Windows -High Efficiency/ENERGY
3 -Windows -Cellular Shades
4 -Insulation -Basement Sidewall
5 -Windows -Low-e Storm Addition
6 -Home Energy Management System
7 -Connected Line-Voltage Thermostat
8 -Linear Lighting
9 -Building Shell -Air Sealing (Infiltration
10 -Insulation -Floor Upgrade
11 -Ducting -Repair and Sealing
12 -Insulation -Floor Installation
13 -Water Heater <= 55 Gal
14 -Insulation -Ducting
15 -Ducting -Repair and Sealing -Aerosol
16 -Building Shell -Liquid-Applied
-Resistive Barrier
17 -Fan System -Equipment Upgrade
18 -Retrocommissioning
19 -Building Shell -Whole-Home Aerosol
20 -Strategic Energy Management
Total of Top 20 Measures 95 70.9%
Total Cumulative Savings 134 100.0%
Peak Impacts –Technical Achievable Potential
Top Measures -Summer Peak (MW)
Reduction by 2031
2031
MW
% of
Total
1 -Retrocommissioning
2 -ENERGY STAR -Connected Thermostat
3 -Windows -High Efficiency/ENERGY STAR
4 -Windows -Cellular Shades
5 -Ductless Mini Split Heat Pump (Zonal)
6 -Strategic Energy Management
7 -Whole-House Fan -Installation
8 -Room AC -Removal of Second Unit
9 -Home Energy Management System
10 -HVAC -Dedicated Outdoor Air System
11 -Insulation -Ceiling Installation
12 -RTU -Evaporative Precooler
13 -Linear Lighting
14 -Ductless Mini Split Heat Pump with
15 -Insulation -Wall Sheathing
16 -Chiller -Variable Flow Chilled Water
17 -Central AC
18 -Building Shell -Liquid-Applied Weather-
19 -RTU -Advanced Controls
20 -Behavioral Programs (Incremental)
Total of Top 20 Measures 128 58.7%
Total Cumulative Savings 218 100.0%
EE POTENTIAL -CONTINUED
Avista Corp.2021 Electric IRP Appendices 369
| 24Applied Energy Group · www.appliedenergygroup.com
WA –TAP by Bundled $/kWhCOST OF SAVINGS
Washington
TRC $/kWh 2022 2023 2031
< $0.00
$0.00 -$0.05
$0.06 -$0.10
$0.11 -$0.20
$0.21 -$0.30
$0.31 -$0.40
$0.41 -$0.50
$0.51 -$0.75
$0.76 -$1.00
$1.01 -$1.50
$1.51 -$2.00
> $2.00
< $0.00
$0.00 -$0.05
$0.06 -$0.10
$0.11 -$0.20
$0.21 -$0.30
$0.31 -$0.40
$0.41 -$0.50
$0.51 -$0.75
$0.76 -$1.00
$1.01 -$1.50
$1.51 -$2.00
> $2.00
0
100,000
200,000
300,000
400,000
<$0 $0.05 $0.10 $0.20 $0.30 $0.40 $0.50 $0.75 $1.00 $1.50 $2.00 >$2
MWh
$/kWh
WA TAP by Cost Bundle -2031
TRC
UCT
Avista Corp.2021 Electric IRP Appendices 370
| 25Applied Energy Group · www.appliedenergygroup.com
ID –TAP by Bundled $/kWhCOST OF SAVINGS
Idaho
TRC $/kWh 2022 2023 2031
< $0.00
$0.00 -$0.05
$0.06 -$0.10
$0.11 -$0.20
$0.21 -$0.30
$0.31 -$0.40
$0.41 -$0.50
$0.51 -$0.75
$0.76 -$1.00
$1.01 -$1.50
$1.51 -$2.00
> $2.00
< $0.00
$0.00 -$0.05
$0.06 -$0.10
$0.11 -$0.20
$0.21 -$0.30
$0.31 -$0.40
$0.41 -$0.50
$0.51 -$0.75
$0.76 -$1.00
$1.01 -$1.50
$1.51 -$2.00
> $2.00
0
100,000
200,000
300,000
400,000
<$0 $0.05 $0.10 $0.20 $0.30 $0.40 $0.50 $0.75 $1.00 $1.50 $2.00 >$2
MWh
$/kWh
ID TAP by Cost Bundle -2031
TRC
UCT
Avista Corp.2021 Electric IRP Appendices 371
| 26Applied Energy Group · www.appliedenergygroup.com
EE POTENTIAL, CONTINUEDPotential Summary –Washington, All Sectors
2022 2023 2024 2031 2041
Baseline projection (GWh)5,196 5,212 5,229 5,479 6,243
Cumulative Savings (GWh)
Achievable Technical Potential 56 121 194 868 1,309
Technical Potential 101 209 325 1,247 1,822
Cumulative Savings (aMW)
Achievable Technical Potential 6 14 22 99 149
Technical Potential 12 24 37 142 208
Cumulative Savings as a % of Baseline
Achievable Technical Potential 1.1%2.3%3.7%15.8%21.0%
Technical Potential 2.0%4.0%6.2%22.8%29.2%
-
200
400
600
800
1,000
1,200
1,400
1,600
2022 2025 2028 2031 2034 2037 2040 2043
Cumulative TAP Savings (GWh) by Sector
Residential Commercial Industrial
0%
5%
10%
15%
20%
25%
30%
35%
2022 2023 2024 2031 2041
% of
Baseline
Cumulative Electric Savings
Achievable Technical Potential Technical Potential
Avista Corp.2021 Electric IRP Appendices 372
| 27Applied Energy Group · www.appliedenergygroup.com
EE POTENTIAL, CONTINUEDPotential Summary –Idaho, All Sectors
2022 2023 2024 2031 2041
Baseline projection (GWh)2,646 2,650 2,653 2,713 2,951
Cumulative Savings (GWh)
Achievable Technical Potential 33 70 110 448 665
Technical Potential 58 119 183 654 948
Cumulative Savings (aMW)
Achievable Technical Potential 4 8 13 51 76
Technical Potential 7 14 21 75 108
Cumulative Savings as a % of Baseline
Achievable Technical Potential 1.2%2.6%4.1%16.5%22.5%
Technical Potential 2.2%4.5%6.9%24.1%32.1%
-
200
400
600
800
1,000
1,200
1,400
1,600
2022 2025 2028 2031 2034 2037 2040 2043
Cumulative TAP Savings (GWh) by Sector
Residential Commercial Industrial
0%
5%
10%
15%
20%
25%
30%
35%
2022 2023 2024 2031 2041
% of
Baseline
Cumulative Electric Savings
Achievable Technical Potential Technical Potential
Avista Corp.2021 Electric IRP Appendices 373
Comparison with 2018 Electric CPA
Avista Corp.2021 Electric IRP Appendices 374
| 29Applied Energy Group · www.appliedenergygroup.com
Comparison with Prior Potential Study
We are often asked to compare results between current and prior potential study estimates –it is important to define comparison parameters.
Aligning calendar years, rather than study years results in a more thorough comparison
•This is mainly due to things like equipment standards, which come on by calendar year, not relative to the start year of the study
Since we are not estimating potential in 2021, potential for that year must be removed from the comparison
•First-Year Incremental Potential -2022
Prior Study: 2nd year of potential
Current Study: first year
The previous study’s 20-year look ended in 2040, therefore we must remove2041-2045 from the comparison
•Cumulative Potential Comparisons –2022 through year 2040
This should have a minimal impact on potential since retrofits are mainly captured prior to this point
As a result, we can draw up to a 19 year comparison (2022-2040)
NOTES ON COMPARISON
Avista Corp.2021 Electric IRP Appendices 375
| 30Applied Energy Group · www.appliedenergygroup.com
ACHIEVABLE POTENTIAL COMPARISONComparison with Prior Potential Study (2022-2037 TAP)
Sector End Use Prior CPA
2040 MWh
Current Study
2040 MWh Diff.(All States)
Residential
Cooling 74,528 112,573 38,045
Heating 444,182 442,897 -1,285
Water Heating 267,144 217,843 -49,301
Interior Lighting 63,331 24,122 -39,209
Exterior Lighting 10,059 4,122 -5,937
Appliances 91,966 82,297 -9,668
Electronics 49,899 58,651 8,752
Miscellaneous 35,248 45,661 10,413
Commercial
Cooling 99,708 145,262 45,554
Heating 33,372 100,989 67,617
Ventilation 73,363 116,241 42,878
Water Heating 22,078 26,182 4,104
Interior Lighting 261,940 210,469 -51,471
Exterior Lighting 103,244 61,188 -42,057
Refrigeration 42,103 119,602 77,499
Food Preparation 0 8,517 8,517
Office Equipment 3,805 14,945 11,139
Miscellaneous 2,018 10,216 8,198
Industrial
Cooling 6,160 4,779 -1,381
Heating 11,042 566 -10,476
Ventilation 7,942 11,679 3,736
Interior Lighting 52,125 49,781 -2,344
Exterior Lighting 12,428 5,213 -7,215
Motors 33,106 69,081 35,975
Process 10,059 7,012 -3,047
Miscellaneous 671 775 104
Grand Total 1,811,520 1,950,662 139,142
-
200
400
600
800
1,000
1,200
1,400
2021 2022 2023 2030 2040
GWh
Washington All-Sector TAP Comparison
Current Study
Prior Study (2021)
Prior Study (2022-2040)
-
100
200
300
400
500
600
700
2021 2022 2023 2030 2040
GWh
Idaho All-Sector TAP Comparison
Current Study
Prior Study (2021)
Prior Study (2022-2040)
Avista Corp.2021 Electric IRP Appendices 376
| 31Applied Energy Group · www.appliedenergygroup.com
SECTOR-LEVEL ACHIEVABLE POTENTIAL
Washington -Comparison with Prior Study –Technical Achievable
•2020 savings already removed
from prior study values
-
100,000
200,000
300,000
400,000
500,000
600,000
700,000
800,000
2022 2025 2030 2035 2040
MWh
Residential
Prior Study
Current Study
-
50,000
100,000
150,000
200,000
250,000
300,000
350,000
400,000
450,000
500,000
2022 2025 2030 2035 2040
MWh
Industrial
Prior Study
Current Study
-
100,000
200,000
300,000
400,000
500,000
600,000
2022 2025 2030 2035 2040
MWh
Commercial
Prior Study
Current Study
Avista Corp.2021 Electric IRP Appendices 377
| 32Applied Energy Group · www.appliedenergygroup.com
SECTOR-LEVEL ACHIEVABLE POTENTIALIdaho -Comparison with Prior Study –Technical Achievable
•2020 savings already removed
from prior study values
-
100,000
200,000
300,000
400,000
500,000
600,000
700,000
800,000
2022 2025 2030 2035 2040
MWh
Residential
Prior Study
Current Study
-
50,000
100,000
150,000
200,000
250,000
300,000
350,000
400,000
450,000
500,000
2022 2025 2030 2035 2040
MWh
Industrial
Prior Study
Current Study
-
100,000
200,000
300,000
400,000
500,000
600,000
2022 2025 2030 2035 2040
MWh
Commercial
Prior Study
Current Study
Avista Corp.2021 Electric IRP Appendices 378
| 33Applied Energy Group · www.appliedenergygroup.com
Comparison with Prior Potential Study –Technical Achievable
Residential:
•LED share of interior lighting market baseline continues to grow, reducing available potential from turnover of old units
This limits the extra potential Idaho gets from not having the EISA backstop in place
•HPWH savings have been revised slightly downward
•Decreases in interior lighting potential as base LED share grows in interior lighting; accelerated turnover and ramp rate compensates, but not completely
•Increased refrigeration potential from new and emerging measures, updated RTF workbooks
•HVAC retrocommissioning and controls (e.g. Strategic Energy Management
systems) greatly expanded applicability in 2021 plan compared to prior study
•Increased potential in motors from updated retrofit applicability in 2021 plan
SECTOR-LEVEL NOTES
Avista Corp.2021 Electric IRP Appendices 379
| 34Applied Energy Group · www.appliedenergygroup.com
NEXT STEPS
•AEG has provided measure list and assumption appendices for EE to
Avista for circulation
•Electric IRP will evaluate cost effective portfolio based on AEG
provided savings and levelized costs
•Gas IRP will run with AEG-provided UCT cost effective potential
Avista Corp.2021 Electric IRP Appendices 380
THANK YOU!
Ingrid Rohmund, Sr. Vice President, [e-mail]
Ken Walter, Project [e-mail]
Kelly Marrin, Managing Director
[e-mail]
Tommy Williams, Lead Analyst
[e-mail]
Avista Corp.2021 Electric IRP Appendices 381
Supplemental Slides
Avista Corp.2021 Electric IRP Appendices 382
| 37Applied Energy Group · www.appliedenergygroup.com
NWPCC 2021 PLAN RAMP RATES
Avista Corp.2021 Electric IRP Appendices 383
| 38Applied Energy Group · www.appliedenergygroup.com
•Several residential categories were adjusted to faster ramp rates
•C&I changes mostly slowed adoption, except for lighting which is greatly accelerated and non-equipment HVAC (maintenance, tune ups, etc) which accelerated
EE RAMP RATE CHANGES
Legend:
Faster Ramp
Slower Ramp
No Change
*compared to 2019
CPA Ramps
Sector(s)Measure Category Equipment or Non-Equip 2019 CPA Ramp Rate 2021 Plan Ramp Rate
Res Appliances Equipment LO1Slow LO12Med
Non-Equipment Retro12Med Retro5Med
Non-Equipment Aerators: Retro3Slow, SH:
Ret12Med
Retro3Slow
Equipment LO5Med CAC, LO1Slow RAC LO5Med CAC,
Non-Equipment Thermostat&DHP Retro5Med,
Retro3Slow
Thermostat&DHP
Retro5Med, Retro5Med
Equipment LO12Med & LO20 Fast LO20Fast
Equipment LO3Slow LO5Med
Non-Equipment LOEven20 NA
Non-Equipment Retro3Slow Retro3Slow
Sector(s)Measure Category Equipment or Non-Equip 2019 CPA Ramp Rate 2021 Plan Ramp Rate
C&I Building Shell Non-Equipment RetroEven20 Retro1Slow
Both Retro5Med, Retro12Med Retro5Med, Retro12Med
Non-Equipment Retro12Med Retro5Med
Equipment LO5Med, LO12Med LO3Slow, LO1Slow
Equipment LO5Med, LO20Fast LO5Med, LO12Med
Non-Equipment RetroEven20, Retro12Med,
Retro3Slow, Retro1Slow
Retro12Med,Retro5Med
Non-Equipment Retro12Med mostly RetroEven20
Equipment LO20Fast/LO50Fast LO80Fast
Non-Equipment Retro12Med Retro12Med
Both Retro12Med Retro5Med
Avista Corp.2021 Electric IRP Appendices 384
| 39Applied Energy Group · www.appliedenergygroup.com
Cumulative and Incremental
Over the following slides, we will display potential both as a impact on baseline as well as in annual
potential includes the impacts of potential acquired from the first year of the study period (2022) through the year of interest, including effects of measures persistence
potential summarizes new impacts realized in any given year of interest, excluding the effects of measure repurchases
DEFINITIONS OF POTENTIAL
Avista Corp.2021 Electric IRP Appendices 385
Electric Wholesale Market Price Forecast
James Gall, Electric IRP Manager
Third Technical Advisory Committee Meeting
September 29, 2020
Avista Corp.2021 Electric IRP Appendices 386
Market Price Forecast – Purpose
•Estimate “market value” of
resources options for the IRP
•Estimate dispatch of “dispatchable”
resources
•Helps estimate avoided costs
•May change resource selection if
resource production is counter to
needs of the wholesale market
Source: NERC
2 Avista Corp.2021 Electric IRP Appendices 387
-$100
-$50
$0
$50
$100
$150
$200
$250
$300
$350
0 10,000 20,000 30,000 40,000 50,000
$
p
e
r

M
W
h
Capability (MW)
Hydro (Must Run for Negative Pricing)
CCCT
Peakers
Demand
Hydro Availability
Fu
e
l

P
r
i
c
e
s
/
V
a
r
i
a
b
l
e

O
&
M
Other Resource Availability
Nuclear/ Co-Gen/ Coal/ Other
Wind (Net PTC/REC)
Market Price
Note: minimum price is negative $25/ MWh (2018$)
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 & emission)
–Regional energy mix
–Transmission usage
–Greenhouse gas emissions
–Power plant margins, generation levels, fuel
costs
–Avista’s variable power supply costs
3 Avista Corp.2021 Electric IRP Appendices 388
Wholesale Mid-C Electric Market Price History
13
23 23
117
126
22
38 42
58
45
51
59
32 33
23 19
32 33
23 20 22
30 36
22
30 29 29 28
$0
$20
$40
$60
$80
$100
$120
$140
19
9
7
19
9
8
19
9
9
20
0
0
20
0
1
20
0
2
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
Cheap
Natural
Gas, good
hydro
Energy Crisis
Natural Gas Market Tightens
Shale Development Forwards
as of
9/18/2020
4 Avista Corp.2021 Electric IRP Appendices 389
U.S. Western Interconnect Generation Mix
Significant changes (aGW
Solar: + 5.0
Wind: + 6.2
Nat Gas: + 6.5
Coal: -9.3
Nuclear:-1.5
Total: + 11.0
Hydro: -4.2 / +5.2
-
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
90,000
100,000
2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
5 Source: EIA
Avista Corp.2021 Electric IRP Appendices 390
Northwest Generation Mix (ID, MT, OR and WA)
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
Coal Natural Gas Hydro Nuclear Wind Solar Petroleum Other
Significant changes (aGW)
Solar: + 0.1
Wind: + 2.3
Nat Gas: + 2.0
Coal: -0.8
Total: + 5.7
Hydro: -3.7 / +3.5
2019 2.0 aGW less than
2002-2018 Avg
6 Source: EIA
Avista Corp.2021 Electric IRP Appendices 391
2019 Fuel Mix
Northwest
70% GHG Emission Free*
U.S. Western Interconnect
49% GHG Emission Free
Source: EIA
* Low hydro year dropped emission free statistic from 77% in 2018 to 70% in 2019 7 Avista Corp.2021 Electric IRP Appendices 392
$0
$10
$20
$30
$40
$50
$60
$70
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
$
p
e
r

M
W
h
Daily Mid-C Price Standard Deviation
Off Peak
On Peak
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
Po
w
e
r
/

G
a
s

x

1
0
0
0
Implied Market Heat Rate
y = 6.9043x + 9.4321R² = 0.9031
$0
$10
$20
$30
$40
$50
$60
$70
$0 $2 $4 $6 $8 $10
Mi
d
-C
$

p
e
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M
W
h
Stanfield $ per DTh
Daily NG vs On-Peak Electric
4.57 6.13 7.02
3.89
7.95
3.62
7.24
4.43
(2.45)
1.30
7.71
4.54
6.92 5.16 4.19
13.12
16.55
-$5
$0
$5
$10
$15
$20
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
St
a
n
f
i
e
l
d

x

7

-
Mi
d

C
Spark Spread
Market Indicators-Market is Tightening
8 Avista Corp.2021 Electric IRP Appendices 393
US Western GHG Emission End Use
0
200
400
600
800
1,000
1,200
19
8
0
19
8
1
19
8
2
19
8
3
19
8
4
19
8
5
19
8
6
19
8
7
19
8
8
19
8
9
19
9
0
19
9
1
19
9
2
19
9
3
19
9
4
19
9
5
19
9
6
19
9
7
19
9
8
19
9
9
20
0
0
20
0
1
20
0
2
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
Residential Commercial Industrial Electric Power Transportation
Source: EIA
2017:
Transportation: 46%
Electric Power: 28%
Industrial: 15%
Commercial: 5%
9 Avista Corp.2021 Electric IRP Appendices 394
Electric Greenhouse Gas Emissions
U.S. Western Interconnect
0
50
100
150
200
250
300
350
Emissions are adjusted for generation within the Western Interconnect
2018 and 2019 estimates are subject to adjustment
Change+5.9
+4.9
+18.1
+10.3
-4.4+1.9
+9.2
+1.4
+11.4
-26.6
+16.4
10 Avista Corp.2021 Electric IRP Appendices 395
Northwest Greenhouse Gas Emissions
MT WA OR ID
11 Avista Corp.2021 Electric IRP Appendices 396
The Forecast: 2022 to 2045
Deterministic Model
•Simulate based on average
conditions
•210,240 hours simulation
•Takes about 6 hours on one
processor
•Good approximation to estimate
impacts of assumptions-great for
scenario analysis, but not risk
•Output Files: 26 GB
Stochastic Model
•Simulate 500 varying conditions
•Fuel Prices, Loads, Wind, Hydro,
Outages, Inflation
•105 million hours of simulation
•Takes about 5 days on 33
processors
•Allows for full evaluation of
resource alternatives and accounts
for risk
•Output Files: 360 GB
12 Avista Corp.2021 Electric IRP Appendices 397
Modeling Process
Vendor Database
(2019 North American)
Input Changes
80 yr hydro
NG prices
Regional Loads
Avista Resources/Loads
Operational Detail
Capacity Expansion
Add new resource forecast
(Capacity/RPS)
Include known retirements
Model adds resources to meet planning targets
Test Year Stochastic Study
Test Resource Adequacy
Re-Run Capacity Expansion
Increase/Decrease Planning Margin Targets
Run Full Forecast
Stochastic & Deterministic
Run Scenarios
Deterministic
Stochastic (if necessary)
13 Avista Corp.2021 Electric IRP Appendices 398
Load Forecast
•Regional load forecast from ‘IHS
–Forecast includes energy efficiency
•Add net meter resource forecast
–Input annually with hourly shape
•Add electric vehicle forecast
–Input annual with hourly shape
•Future load shape to be different
then today’s load shape
14 Avista Corp.2021 Electric IRP Appendices 399
Electric Vehicle and Solar Adjustments
Roof Top Solar
•EIA existing estimates for history
•‘IHS regional growth rates
Electric Vehicles
•Penetration rates increase each year (2040 shown below)
•15-30% light duty
•12-15% medium duty
•5% heavy duty
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
Me
g
a
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a
t
t
s
15 Avista Corp.2021 Electric IRP Appendices 400
New Resource Forecast (Western Interconnect)
2025 2030 2035 2040 2045
CCCT 3.3 9.9 10.7 11.6 12.8
SCCT 15.4 17.8 19.3 20.2 22.7
DR 2.1 6.0 7.6 9.5 11.5
Storage 7.9 16.2 25.7 35.5 47.1
Net-Meter 4.5 6.5 8.5 10.8 13.9
Solar 25.5 37.5 47.8 59.7 73.0
Wind 7.8 15.7 24.1 33.4 43.3
Geothermal 0.3 0.7 1.2 1.9 2.9
Biomass 0.2 0.4 0.6 0.7 0.9
Hydro 1.3 1.6 1.9 2.4 2.8
-
50.0
100.0
150.0
200.0
250.0
Gi
g
a
w
a
t
t
s
16 Avista Corp.2021 Electric IRP Appendices 401
U.S. West Resource Type Forecast
17
-
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
90,000
100,000
20
0
1
20
0
2
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
Significant changes
2045 to 2022 (aGW)
Solar: + 15.9
Wind: + 10.5
Nat Gas: -3.1
Coal: -11.9
Nuclear:-4.5
Other: + 1.5
Hydro:+ 0.3
Total: + 11.9
Avista Corp.2021 Electric IRP Appendices 402
Northwest Resource Type Forecast
18
-
5,000
10,000
15,000
20,000
25,000
30,000
20
0
1
20
0
2
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Av
e
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a
g
e

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a
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a
t
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s
Significant changes (aGW)
2045 to 2022
Solar: + 2.9
Wind: + 2.4
Nat Gas: - 2.1
Coal: - 0.6
Other: + 0.7
Nuclear: - 1.1
Total: + 2.2
Avista Corp.2021 Electric IRP Appendices 403
Mid-C Electric Price Forecast
•Levelized Prices:
–2022-45: $26.05/MWh
–2022-41: $23.03/MWh
•Off-peak prices over take
on-peak in 2024 on an
annual basis
•Evening peak prices
remain high (4pm-10pm)
19
$
p
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Mid-Columbia Electric Forecast (Deterministic)
Avista Corp.2021 Electric IRP Appendices 404
Mid-C Price Forecast (Stochastic- Draft)
20
$0
$10
$20
$30
$40
$50
$60
$70
$80
$90
$100
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
$
p
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M
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24-yr Levelized Prices
Mean: $27.11/MWh
Median: $24.84/MWh
Deterministic: $26.05/MWh
Avista Corp.2021 Electric IRP Appendices 405
Mid-C Electric Price Comparison vs. Previous IRPs
21 * These forecasts use price scenarios without GHG “taxes” to make all forecasts consistent
$
p
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Avista Corp.2021 Electric IRP Appendices 406
Hourly Wholesale Mid-C Electric Price Shapes
-$25
$0
$25
$50
$75
$100
$125
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
$
p
e
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M
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Hour
Summer: Jun 16 -Sep 15
2022 2030 2035 2040 2045
22
$
p
e
r

M
W
h
Hour
Winter: Dec 16 -Mar 15
$
p
e
r

M
W
h
Hour
Spring: Mar 16 -Jun 15
$
p
e
r

M
W
h
Hour
Fall: Sep 16 -Dec 15
Avista Corp.2021 Electric IRP Appendices 407
Greenhouse Gas Forecast
U.S. Western Interconnect
23
Mi
l
l
i
o
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M
e
t
r
i
c

T
o
n
s
Avista Corp.2021 Electric IRP Appendices 408
Greenhouse Gas Forecast
Northwest States
24
-
5
10
15
20
25
30
35
40
45
19
8
0
19
8
2
19
8
4
19
8
6
19
8
8
19
9
0
19
9
2
19
9
4
19
9
6
19
9
8
20
0
0
20
0
2
20
0
4
20
0
6
20
0
8
20
1
0
20
1
2
20
1
4
20
1
6
20
1
8
20
2
0
20
2
2
20
2
4
20
2
6
20
2
8
20
3
0
20
3
2
20
3
4
20
3
6
20
3
8
20
4
0
20
4
2
20
4
4
Mi
l
l
i
o
n

M
e
t
r
i
c

T
o
n
s
Avista Corp.2021 Electric IRP Appendices 409
Market Scenario Assumptions
•High Natural Gas Prices
–90th percentile of stochastic prices
using 1,000 draws
•Low Natural Gas Prices
–25th percentile of stochastic prices
using 1,000 draws
•Social Cost of Carbon “Tax”
–Western Interconnect Carbon “Tax” on
Generation
–SCC pricing beginning in 2025,
trending up beginning in 2022.
•Climate Shift
–Uses NWCC three climate futures
–Trend Northwest hydro and loads for
warming temperatures
–Lower NG CT capability due to
temperature change
$
p
e
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D
e
k
a
t
h
e
r
m
25 Avista Corp.2021 Electric IRP Appendices 410
Climate Shift Methodology (Loads)
•Uses 2024 operating year
forecast.
•Overlays the 2020 to 2049
temperature forecast using
an average of three climate
models chosen by the
NPCC.
•Create a linear trend of load
based on changes in
weather*-referred to as
scalers.
•Apply scalers to expected
case load forecast.
* does not include secondary changes in load due to climate shift
Data & scalars provided by PNUCC
26 Avista Corp.2021 Electric IRP Appendices 411
Climate Shift Methodology (Hydro)
•NPCC provides 80-year hydro
history and three models with
30 years of potential hydro for
the 2040’s.
•Compare the average of three
climate models to the 80-year
hydro history.
•Linearly trend the change
between the beginning and the
end of the forecast.Av
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s
27 Avista Corp.2021 Electric IRP Appendices 412
Scenario Results: Wholesale Electric Prices
Levelized Prices (2022-2045)
•Expected Case: $26.05/MWh
•Social Cost of Carbon: $58.56/MWh
•High NG Prices: $46.07/MWh
•Low NG Prices: $19.35/MWh
•Climate Shift: $25.51/MWh
28
$
p
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Avista Corp.2021 Electric IRP Appendices 413
Scenario Results: US Western Interconnect GHG Emissions
187 196
179 187
169
126 128 122 125
100
85 83 83 83
68
0
50
100
150
200
250
Expected Case High NG Price Scenario Low NG Price Scenario Climate Shift Scenario Social Cost of Carbon
Scenario
Me
t
r
i
c

T
o
n
s

(
M
i
l
l
i
o
n
s
)
Market Forecast Scenario
2022 Average 2045
29 Avista Corp.2021 Electric IRP Appendices 414
Scenario Results: U.S. Western Interconnect Resource Type
Expected
Case
Low NGPriceScenario
High NGPriceScenario
ClimateShiftScenario
SocialCost of
CarbonScenario
Solar 9,024 9,023 9,024 9,022 9,978
Wind 9,698 9,698 9,700 9,692 9,694
Natural Gas 17,785 19,394 16,002 17,788 19,158
Coal 14,870 13,160 16,783 14,886 12,164
Nuclear 7,188 7,187 7,195 7,178 7,185
Other 3,623 3,625 3,604 3,597 3,628
Hydro 19,570 19,570 19,570 19,570 19,571
0
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
90,000
100,000
Av
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a
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s
Year: 2022
ExpectedCase
Low NGPriceScenario
High NGPriceScenario
ClimateShiftScenario
SocialCost ofCarbonScenario
Solar 16,053 16,047 16,059 16,050 16,864
Wind 13,048 13,033 13,057 13,049 13,010
Natural Gas 16,411 17,126 16,094 16,267 19,170
Coal 9,699 8,935 9,973 9,670 4,874
Nuclear 4,426 4,416 4,432 4,424 4,440
Other 4,013 3,992 3,994 4,007 3,680
Hydro 19,568 19,568 19,568 19,694 19,568
0
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
90,000
100,000
Av
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a
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M
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a
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s
Year: 2030
ExpectedCase
Low NGPriceScenario
High NGPriceScenario
ClimateShiftScenario
SocialCost of
CarbonScenario
Solar 22,059 22,040 22,071 22,033 22,550
Wind 17,477 17,461 17,498 17,455 17,367
Natural Gas 14,489 14,782 13,997 14,255 15,309
Coal 4,477 4,251 4,535 4,410 2,069
Nuclear 4,729 4,713 4,740 4,714 4,727
Other 4,605 4,550 4,632 4,585 4,295
Hydro 19,726 19,726 19,726 20,028 19,726
0
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
90,000
100,000
Av
e
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M
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a
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s
Year: 2040
30 Avista Corp.2021 Electric IRP Appendices 415
Incremental GHG Emissions for Energy Efficiency
•This IRP assumes GHG emissions from load
reduction and associated emissions from market
purchases/(sales)*
•2020 IRP assumes average emissions each year
based on average emissions compared to load
each year. (See blue bars)
•Avista believes average emissions best
represents the associated emissions for market
purchases/sales:
–Should this be based on load or generation?
•Avista is considering using incremental emissions
for valuing energy efficiency for Washington’s cost
analysis:
–Load or generation calculation method?
–Increase load vs. decrease load method (or average)?
–At what granularity to apply benefit?
* Purchases related to storage resources assumes a slightly different provide due to charging times
lb
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Northwest Emission Intensity
(WA, OR, ID, MT, UT, WY)
31 Avista Corp.2021 Electric IRP Appendices 416
Data Availability
Outputs
•Expected Case: annual Mid-C
prices by iteration (stochastic)
•Expected Case: hourly Mid-C
prices (deterministic)
•Scenarios: monthly Mid-C electric
prices
•Regional resource dispatch
•Regional GHG emissions
•Avista resource dispatch data will
be included within PRiSM Model
Inputs (Not already Posted)
•Climate shift scaling factors for
load/hydro
•High/low natural gas prices
Avista Corp.2021 Electric IRP Appendices 417
2020 Electric Integrated Resource Plan
Draft Portfolio Scenario Analysis
John Lyons, Ph.D.
Third Technical Advisory Committee Meeting
September 29, 2020
Avista Corp.2021 Electric IRP Appendices 418
DRAFT
Portfolio Scenarios –2020 IRP
1. Preferred Resource Strategy
2. Least Cost Plan-w/o CETA
3. Clean Resource Plan: 100% net clean by 2027
4. Rely on energy markets only (no capacity or renewable additions) w/o CETA
5. 100% net clean by 2027, and no CTs by 2045
6. Least Cost Plan w/o pumped storage or Long Lake as options
7. Colstrip extended to 2035 w/o CETA
8. Colstrip extended to 2035 w/ CETA
9. Least Cost Plan w/ higher pumped storage cost
10. Least Cost w/ federal tax credits extended
11. Clean Resource Plan w/ federal tax credits extended
12. Least Cost Plan w/ low load growth (flat loads-low economic/population growth)
13. Least Cost Plan w/ high load growth (high economic/population growth)
14. Least Cost Plan w/ Lancaster PPA extended five years (financials will not be public)
Others: Efficient frontier portfolio (least risk, 75/25, 50/50, and 25/75)
2 Avista Corp.2021 Electric IRP Appendices 419
DRAFT
Portfolio Scenarios-2021 IRP
1.Preferred Resource Strategy
2.Baseline Portfolio 1 (No CETA renewable targets)
3.Baseline Portfolio 2 (No CETA renewable targets/SCC)
4.Clean Resource Plan (100% Portfolio net clean by 2027)
5.Clean Resource Plan (100% Portfolio clean by 2045)
6.Social Cost of Carbon applied to Idaho
7.Least Cost Plan-w/ low load growth
8.Least Cost Plan-w/ high load growth
9.Least Cost Plan-w/ Northwest Resource Adequacy Market Peak Credits
10.Heating Electrification Scenario 1
11.Heating Electrification Scenario 2
12.Heating Electrification Scenario 3
13.Least Cost Plan-w/ climate shift
14.Least Cost Plan-w/ 2x SCC prices
15.Colstrip serves Idaho customers through 2025
16.Colstrip serves Idaho customers through 2035
17.Colstrip serves Idaho customers through 2045
18.If necessary: CETA deliver to customers each hour
19.If necessary: other resource specific scenarios depending on outcome of PRS results
3 Avista Corp.2021 Electric IRP Appendices 420
TAC Meeting 3 Notes – September 29, 2020
Virtual Attendees: Shay Bauman, Shawn Bonfield, Annette Brandon, Terrence
Browne, Morgan Brummund, Michael Brutocao, Ethan Case, John Chatburn, Corey
Dahl (Public Counsel), Michael Eldred (IPUC), Chip Estes, Ben Fadie, Rachelle
Farnsworth (IPUC), Ryan Finesilver, Damon Fisher, James Gall, Amanda Ghering, GS,
Guest (5), Leona Haley, Lori Hermanson, Jan Himebaugh (BIAW), Elizabeth Hossner,
Tina Jayaweera, Clint Kalich, Kathlyn Kinney, Dean Kinzer, Melissa Kuo, Scott Kinney,
John Lyons, Fred Heutte (NWEC), Jaime Majure, Kelly Marrin, Stuart M., Eli Morris,
Katie Pegan, Tom Pardee, Jorgen Rasmussen, Jeff Schlect, Jennifer Snyder (WUTC),
Darrell Soyars, Collins Sprague, Dean Spratt, State of Idaho, Jason Thackston,
Unavailable (1), Ken Walter (AEG), Tom Williams, Katie Ware, and Yao Yin (IPUC).
Notes in italics after questions were made by the presenter.

IRP Transmission Planning Studies – Dean Spratt, Avista
Yao Yin (Slide 15): When Avista contracts with a QF [qualifying facility under PURPA],
does the QF contract for transmission at the same time? Probably a better merchant
question. It was studied by us and neighboring utilities. They typically don’t have tools to
conduct full qualified studies. Does that help? Yes, thank you.
Dean Spratt: Regarding QF versus non-QF impacts, these are studied by us [Avista
transmission] and others. The scope is different for these.
Yao Yin (Slide 16): Does a QF get into the same queue regarding scope of the project?
Dean Spratt: Yes. Anyone, QF or not, that wants to get on the system has to go
through the [same] interconnection process. A QF or large project has to go through the
interconnection request. There is one queue that captures everything. Transmission
planning only sees the larger projects. It could be a cut-off for smaller projects. There
are different rules for different states.
Jeff Schlect: I’m going to chime in here. I’m the Senior Manager of Transmission
Services here at Avista. Yes, all projects work through the same queue under FERC or
by state agreement based on the size of the project. There is one queue for all sizes,
but they could be subject to a FERC process or to some other process.
Yao Yin: Thanks Jeff. I was unsure of the small project cut off.

Distribution Planning within the IRP – Damon Fisher, Avista
Jennifer Snyder: HB 1126 has been codified in RCW 19.280.100.
Rachelle Farnsworth: Talk about how and if the company is looking at smart inverters
and how you will use those?
Avista Corp.2021 Electric IRP Appendices 421
Damon Fisher: Latest IEEE. Yes, but how planning is going to integrate remains to be
seen. I don’t think the hardware has caught up with the standard yet, maybe by 2021 or
2022. We are not quite there. We would implement that as stated in the new 1547 right
through. There are concerns with transmission faults in Germany and California where a
lot of load was dropped due to the large amount of inverters and them not recognizing it
was a short trip and needed to stay online longer. A distribution fault drops all
generation and transmission fault stays online longer.
Rachelle Farnsworth: Yes, I was just curious on smart inverter policy and settings.
Where is the company on developing a policy on this?
Damon Fisher: Existing 1547 is what we are following. New 1547 is the ride through
ability. Thank you. That is system protection and I’m not an expert on it.
Kathlyn Kinney: Is there something outward facing where you publicize where grid
issues are and where DR is needed?
Jennifer Snyder: Do you have studies on where DR would be helpful?
Damon Fisher: No, there isn’t yet. We’ve been working hard to get modeling for
facilities hosting capacity for load and later generation. There are lots of benefits
internally for guiding new load to where it doesn’t create system constraints. Lots of
work is being done on these maps with this intent. Can approach more sophisticated
customers first with incentives to help with grid constraints. Some of these studies are
out there, such as the work done in New York. I will send a link. If anyone is interested,
New York has one that is pretty interesting. New York was able to work through it.
There are a few studies out there.
Damon Fisher (Slide 14): 15 days in December, it’s dark before 4 pm back in the old
days when we went to work. Something that would give me pause would be to just use
solar to fix a grid issue when there are situations like that.
Damon Fisher (Slide 15): Will drastic changes in the day cause a problem as a grid fix
issue? Need data and studies. What if we fix the curve with a battery or use two DERs?
Maybe we just go straight to a battery. All of these are considerations in fixing the gird
and adding resources when available to the system.
Damon Fisher (Slide 17): Blue is transmission. Orange is the 230 kV lines. BPA is in
there as well. Airway Heights is a big growth area. We don’t serve the new Amazon
facility directly, but local growth in the area is occurring through our substation feeders
nearby and they are approaching their limits.
Yao Yin (slide 19): I’m not very familiar with the concept of hosting capacity. What does
that mean?
Damon Fisher: Our system can host your generation. Like 5 MW of solar. We can do
pre-analysis of the system with gobs and gobs of analysis to show constraints on a
map. If it’s in a development and you want to put in 1 MW of solar, where can I get it
Avista Corp.2021 Electric IRP Appendices 422
attached quicker? I can also do that for load. Pre-analysis of where you can add more
resources without causing system problems. Load is also interesting. Generators who
might be interested in hosting solar or whatever generation on our system. You run
through scenarios of attached generation and look for constraints such as high voltage
problems. Map can then be geo-referenced that tells generators of where you can
locate projects. Possibly to do pre-analysis to shorten Dean’s queuing process. Intend
to do this with load and generation and where to locate generation without causing
problems.
Yao Yin: Does that consider upgrades only for existing or does it assume upgrades
happen?
Damon Fisher: Yes. Run analysis until you encounter the first constraint. If done
correctly, you can do a hosting map that will guide these projects without requiring
system investment. Hosting capacity map will go stale when resources are added. Easy
to go stale if maps aren’t maintained. How often do you do this? It could be a resource
intense operation. Possibly automate it, but that remains to be seen.
Damon Fisher (Slide 19): AMI data is 5 minutes out of the meters. Can apply various
techniques to the data to pick out what load is occurring. Where are we getting electric
vehicles as more of them are out there? Will we have less visibility of where they are
and what they are doing to the system as they are charging? Can look for the most
offensive user of energy or demand (AC) and then target those as a DER candidate.
This causes all sorts of weird questions on tariffs, targeting, etc. For northwest utility
DERS, this is an enlightening conversation with everyone. What is right, appropriate,
average and above average?

Demand Response Potential Assessment – Kelly Marrin, AEG
Kelly Marrin: This Demand Response (DR) Potential Assessment shows the
preliminary results. It is not the first round, but is not finished yet.

Brian Fadie (Slide 11): The first note under sources mentions an Avista proposed
cycling strategy for DLC Central AC and Smart Thermostats (cooling). Can you describe
that further?

Kelly Marrin: The Power Plan has something closer to 1, when talking to Avista about
what they might use, they said they’d implement something more moderate so AEG
adjusted this down.

Kathlyn Kinney: On the percentage with EV charging, what is getting measured? Is it a percentage over the top and will this be changing over the year, what exactly is being
measured here?

Avista Corp.2021 Electric IRP Appendices 423
Kelly Marrin: This is an average per customer reduction per event and accounts for all participants whether they’re plugged in or charging. As EV penetration increases,
megawatts will go up and that’ll show up in EV saturation. Impacts start low, but by
2045 they will be substantial as we have more EVs.

Yao Yin: Any assumptions regarding battery duration and efficiency?

Kelly Marrin: We will provide more detail on technical research done on batteries. We
have six hours storage assumed per day and 8 hours for larger batteries.

Tina Jayaweera: There a number of electrification scenarios in the IRP, have you incorporated that in your work?

Kelly Marin: We are not doing any scenarios. We are using the same forecast.

James Gall: From energy efficiency, those electrification scenarios already include them. We have not discussed DR yet, but will discuss this when our studies are
complete. Tina thanks for reminding us to circle back and do that analysis.

Yao Yin: Big picture, if a technology is used for ancillary services does it hurt the chance for it to serve other purposes? For example, a battery. Are these two mutually exclusive?

Kelly Marrin: That’s right. Ancillary service doesn’t always have a specific time, so we
don’t add these and don’t stack the value of ancillary services on top of the capacity. If there’s an overlapping event. Ancillary services are not at a specific time, they can be at
any time of the year or day. We never add these to the other programs. This loads first.
Capacity is looked at separately and in a particular order. They account for not calling
the same load at the same time but for ancillary service. It’s a completely different load
and we assume this doesn’t happen during system peak event times.

Yao Yin: So there is an order?

Kelly Marrin: Yes, could do either one, but not both.

Damon Fisher: Have any of the grid limitations been taken into consideration? All
batteries operating on a feeder at the same time that cause voltage whip-sawing if they
are on all at once?

Kelly Marrin: We haven’t gone into that level of detail. This is a broad brush study, less broad than before, but take it with the idea of trying to get a sense of what the potential
could be. But we haven’t looked at it at the technical level of response.

Avista Corp.2021 Electric IRP Appendices 424
Damon Fisher: The feeder itself could be at the limit itself, not the technical potential.

Kathlyn Kinney: At a high level, how does this compare to increasing electricity
demand over time? How close are we to breaking even?

Kelly Marrin: Haven’t gotten to that step yet. If we add up all of the DR reductions versus the forecast. We haven’t gotten to that step yet, but when we add up at a very
high level of the percentage – I think close to 10%, but 5 – 10% of total peak demand by
2045.

Kathlyn Kinney: Do we know what the increase from electrification will be?

James Gall: It’s available on the website, but is about 800 MW over the next 24 years.
If we did all these programs, we can offset more than our load growth. DR is only for
those couple of hours. We still have the rest of the year to deal with.

Fred Heutte: I just came in from another call I had to run to. DR is a key interest these
days. Specifically, we think the new standard grid-integrated water heaters will provide a
lot of savings. We are very interested in utilities trying to show this. How many electric
water heaters are now in the Avista service territory? We’ve seen increasing periods of very high pricing at Mid-C and elsewhere. Will that be folded into the value of DR?

Ken Walter: The water heater number is not in front of me, but we could map it.

Fred Heutte: 45-55% in the region. It is helpful to know. I’ve looked at the saturation assessments, but don’t know for sure. My guess over time is a high number above 50%.

James Gall: That is the plan. We’ll assign a price to call on DR. From a modeling
perspective, it’s difficult, it will need to be done outside of the model. Not sure of the
price yet, so there is a market opportunity to take advantage of. It is not impossible to model, but very difficult.

Fred Heutte: Lots of different factors with coal retirements and limited DR now.

Tina Jayaweera: For the transmission and distribution side, how can DR help with this and what we heard earlier? Haven’t finished with costs for both T&D particulars.

Kelly Marrin: A question we need to address together when we get there. Sounds like
there could be additional value from geographic-specific DR. Definitely on the location
specific side. Will make a note of that for when we get there and will revisit with Avista when we get there.

Avista Corp.2021 Electric IRP Appendices 425
Conservation Potential Assessment – Ken Walter, AEG
Tina Jayaweera: Is the T&D deferral being incorporated here?
Ken Walter: It’s being incorporated in the avoided cost. I’ll ask Ryan if he remembers.
It’s not an exact value. We are looking into how to have a more prospective approach to
historic value of the net plant value for T&D deferral.
Tina Jayaweera: The Council has a proposed methodology, I can’t remember if Avista
used that?
Ryan Finesilver: No, it wasn’t used but we’d be happy to talk about it.
Tina Jayaweera: Ok, we can talk about it offline.
Brian Fadie: Is the social cost of carbon being considered in these cost effectiveness tests?

James Gall: Yes, we include it for incremental energy efficiency. There will be more
emissions avoided somewhere else in the region. There is a slide on that later today. More energy efficiency and more incremental emissions are avoided and we would include that benefit.

Yao Yin (Slide 14): In the load and resource balance, which line is used to determine
the amount of energy efficiency?
Ken Walter: The middle green line, but we provide savings at the measure level. About
7,000 line items.
James Gall: The load forecast which we show there is reduced somewhere between
the red and the hashed lines. Energy efficiency programs that are cost-effective will
reduce that load.
Grant Forsyth: Forecast without energy efficiency included, run PRiSM, and then I
gross up the forecast for energy efficiency that could be existing in the future.
James Gall: Yes, it’s a circular chicken and egg issue as we don’t know what programs
will be used in the future. The idea is to get a forecast of programs that are cost
effective to increase or decrease loads, then iterate between the two. Start with a high
load forecast, select energy efficiency programs with PRiSM, and then redo the forecast
with and without energy efficiency for energy and for peak load.
Yao Yin: In Grant’s forecast without energy efficiency, PRiSM is then used to select and
adjust that load. How does this slide fit into that process (slide 14)?
James Gall: There are a number of programs that are available to be selected as to
whether they should move forward or not.
Ken Walter: Pool of all measures is what the model selects from.
Avista Corp.2021 Electric IRP Appendices 426
Richard Keller: Is slide 14 in GWh, not aMW? Yes, GWh. Thanks.
Tina Jayaweera: Catching up with industrial customers in your assessment, are those
two large industrial customers eligible for energy efficiency programs?
Ryan Finesilver: I believe all customers are eligible. All customers pay into the
efficiency program. So I guess the question is how we are accounting for industrial
customers in the IRP? They are not in the baseline. The problem is we can’t apply a
curve to a single individual customer. The large industrial company makes its own
energy efficiency decisions, which is not something we can do on a model level.
James Gall: We need to take this issue back as a group internally and discuss it.
Tina Jayaweera (slide 15): How are you accounting for the missed energy efficiency
for these two customers?
Ryan Finesilver: Assume that their efficiency will be included as well.
Ken Walter: Not in baseline so not included. Can’t apply a curve designed for a whole
population to a single individuals. Other clients have approached this by having AEG
speak to these customers and see what they intend to do.
James Gall: Sounds like we need to discuss this internally.
Ken Walter: Tina, thanks for the idea.
Tina Jayaweera: How are you determining the peak impact for energy efficiency?
What is the methodology?
Ken Walter: The ratio of peak kW to annual kWh based on end use shapes on an
hourly level. We use that to segment.
Tina Jayaweera: For load shapes, what are your main sources?
Ken Walter: Open EI and I think the Yakima weather station.
Yao Yin: When are the peak hours for Avista for both winter and summer?
James Gall: 7-8 am in morning or 5-6 pm in the evening for the winter. Summer peaks
around 4 pm or 6 to 7pm. summer peak usually occurs in July or August and winter is in
the end of November through mid-February. The days of the week also matter, Monday
through Wednesday are usually the highest load. Some peak weather events occur on
holidays or weekends when loads are lower.
Yao Yin: What is the method used to determine peak hours?
James Gall: Looking at actual load history.
Tina Jayaweera: For energy efficiency do you take the average or the peak?
Ken Walter: We do it based on the actual single peak hour.
Avista Corp.2021 Electric IRP Appendices 427
Yao Yin: I’m a little confused, is it the single peak hour, not a period but one hour?
James Gall: Yes, we assume it as a single hour as opposed to an average over 2 to 3
hours.
Yao Yin: How did you determine which hour?
James Gall: For each month, Grant looks at the hottest and coldest day of the month
and averages the historic weather years to come up with a peak hour.
Yao Yin: That results in one single peak hour instead of the timeframes you mentioned
earlier?
James Gall: Our modeling is at the annual peak perspective. We are not looking at
when that specific hour is. We are given a high water mark and then looking at
measures to reduce it from there. Value we are looking at is an average. The future is
an expectation of what that will change to.
Tina Jayaweera: The IRP is an hourly model. Are you taking 8760 hours from energy
efficiency? The peak from here doesn’t actually get used. Is that correct?
James Gall: The 8760 is used for the economic analysis of energy valuation for how
much energy is worth. We get a summer and a winter peak value. Evaluate on energy
and then how much it lowers winter or summer peak value for the L&R.
Tina Jayaweera: Confused about peak of a couple of hours versus what we have here.
James Gall: We don’t know a specific hour when it will occur.
Tina Jayaweera: That makes sense and it can shift around. My concern is on the
energy efficiency side, it’s over or under estimating because it’s not just one hour.
Ken Walter: How a peak event breaks down across end use typically won’t be
materially different so there is not much risk of over or under estimating.
Tina Jayaweera: My concern is with winter, if it occurs in the morning versus the
evening, equipment operates differently. I don’t know how impactful this would be, just
exploring.
Ken Walter: I’m making a note on that.
James Gall: No model can evaluate every hour so that the model can solve. We don’t
know the specific hour when a peak will occur. It is not a consistent hour for every day.
All inputs are available on our website in the same format I used in the IRP.

Electric Market Price Forecast, James Gall
Richard Keller (slide 4): Is this the average annual price?

Avista Corp.2021 Electric IRP Appendices 428
James Gall: Yes, for on peak and off peak.

Richard Keller: How does the model look at hourly reliability attributed to operating
reserves?

James Gall (slide 12): The model is solving for operating reserves on a system basis for an area or zone and not on a utility basis. Six percent operating/spinning and non-
spinning reserves and 2% for regulation. Hopefully, that helps.

Fred Heutte: A lot of data there. I’m not terribly surprised with trying to take into account all of the things in the stochastic model. There is a jump logic approach to shock parameters, I’m wondering if you do something like that to pick up a COVID or
such an event. PAC does something similar.

James Gall: Not specifically, but there are specific tail shock events that do occur. A black swan event is great to test as a scenario. They show up, but not at the same time.
Stochastic modeling tries to take into account an event like those tail events.

Yao Yin (slide 12): Is there an algorithm that calculates whether the wind/solar can be
integrated?

James Gall: There is not a specific requirement looking at the instantaneous number.
There is not a dynamic reserve held for winter. It holds back capacity for integration
based on the inputs. We can model this in the future, but it probably wouldn’t solve in
time to be useful as it would slow the model to a crawl. The model wouldn’t solve in enough time to be usable. Maybe the technology will get better so it could solve.

Yao Yin: Is the amount of reserve percentage manually entered?

James Gall: Yes, for price, but for reliability it’s dynamic at the local system level. We include it for our need at a local system level. In the resource adequacy portion and in
PRiSM it is rolled up in the model runs and set aside for capacity from the reliability
model.

Yao Yin: Is the local dynamic done within PRiSM?

James Gall: No, in the reliability model which estimates what the planning margin
should be and then that number gets put into PRiSM. We will talk about that in the next
meeting.

Fred Heutte: The SAAC talked about this in the morning. What is the west going to do
for new resources for the late 2020s and early 2030s with the shape of prices? They are
seeing a similar issue for the regional modeling.
Avista Corp.2021 Electric IRP Appendices 429

James Gall: Yes, that’s the rest of the presentation.

Charlie Inman (Slide 13): How many zones are in Avista’s [Aurora] model?

James Gall: 12 to 14. We are using the same database as the 2020 IRP. There is a newer one, but that one came out too late for this IRP.

Yao Yin (slide 16): Is DR considered on the supply side and not as a load adjustment?

James Gall: It is a load adjustment, but the model dispatches it so it acts like generation. Included it here because it acts like a generator – same with net metering.

Yao Yin: Net metering is a reduction to load and DR is dispatched?

James Gall: Correct. Model first goes to DR to select the amount of DR. DR is dispatched by the model, but it may or may not be chosen.

Yao Yin: So the amount of DR is from a model result whereas net metering is based on
an entered number?

James Gall: Correct. Along with combined cycle and simple cycle generation. There is
a process to shut off generation – typically renewables have a tax credit and can
operate with a negative price. Hydro has a negative $25 price but it often can’t be
turned off due to a fish constraint. Negative prices are based on dispatch order.

Kathlyn Kinney (slide 22): Is there somewhere where pricing here transfers to price
reductions and scenarios where higher priced renewables still fit in and make sense?

James Gall: When the model looks at a resource choice it’s looking at the margin. It is willing to pay more for the resource that meets those super peak hours. Now you have to pay for solar plus storage and the extra cost may not equal the extra benefit you get
from that solar plus storage resource. Start to see what hours to dispatch a DR program
and whether they are for economic or for reliability reasons. As far as demand goes, we
are starting to see where some of those resources might be dispatched.

James Gall: Back to slide 21, the history of electric price forecasts since I’ve been
doing them here since 2005. A few times we got it right and others we were too high. In
the teens we were getting lower and now we are pretty close to the market. Prices over
the last 15 years have been falling, similar to loads.

Avista Corp.2021 Electric IRP Appendices 430
James Gall (slide 24): In the analysis, we will make a decision about if a plant is uneconomic, such as Colstrip. In Washington, there is a cost cap for new renewables
and it is load versus generation based in other states.

James Gall (slide 25): The rest of the slides are on scenarios that we agreed to perform previously for this IRP.

Yao Yin: Which natural gas forecast will be used for the October 15th filing [Idaho
avoided cost filing]?

James Gall: Will need to check. We used expected price (middle), which is based on the forecast from the consultants we hire rather than a higher or lower gas price

Yao Yin: Why don’t we include the expected case in here?

James Gall: It is, these are higher and lower scenarios for high and low gas prices.

Jennifer Snyder: Can you give a high level overview of your social cost of carbon
modeling and what’s changed?
James Gall: The model was used to acquire the resources based on the resource plus
cost of the social cost of carbon plus upstream emissions plus construction costs.
Energy efficiency used an average rate, we have been talking about using an
incremental cost (talked about more this afternoon). Market purchases/sales use an
average emission rate as well – this is not a change. Two changes – energy efficiency
average to incremental and including a social cost of carbon cost for resource
acquisition.
Corey Dahl: What is the problem with the social cost of carbon?
James Gall: To capture the cost of carbon associated with the manufacturing and
construction processes associated with the resources – both sides. We used
construction and operations life cycle carbon analysis study from NREL. It is a small
amount of dollars, but it tries to estimate the total carbon costs associated with different
resource choices.
Kathlyn Kinney (slide 31): Incremental means?
James Gall: To run existing infrastructure, how would the system operate in that world.
Jennifer Snyder: I was kicked off the call and just rejoined. I missed what you said and
will have to talk with you later.

James Gall: That’s fine, we can have an offline conversation.

Avista Corp.2021 Electric IRP Appendices 431

2021 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 4 Agenda
Tuesday, November 17, 2020 Virtual Meeting
Topic Time Staff
Introductions 9:00 Lyons

Final Resource Needs Assessment 9:15 Lyons

2020 Renewable RFP Update 9:45 Drake

Break 10:20

Portfolio Modeling Overview 10:30 Gall

Lunch 11:30
Draft PRS and Scenarios 12:30 Gall

Adjourn 2:00
.........................................................................................................................................
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Avista Corp.2021 Electric IRP Appendices 432
2021 Electric IRP
TAC Introductions and IRP Process Updates
John Lyons, Ph.D.
Fourth Technical Advisory Committee Meeting
November 17, 2020
Avista Corp.2021 Electric IRP Appendices 433
Updated TAC Meeting Guidelines
•IRP team working remotely through the rest of this IRP, but still
available by email and phone for questions and comments
•Some processes are taking longer remotely
•Virtual IRP meetings until able to hold large group meetings again
•Joint Avista IRP page for gas and electric:
https://www.myavista.com/about-us/integrated-resource-planning
–TAC presentations
–Documentation for IRP work
–Past IRPs
2 Avista Corp.2021 Electric IRP Appendices 434
Virtual TAC Meeting Reminders
•Please mute mics unless speaking or asking a question
•Use the Skype chat box to write questions or comments
or let us know you would like to say something
•Respect the pause
•Please try not to speak over the presenter or a speaker
who is voicing a question or thought
•Remember to state your name before speaking for the
note taker
•This is a public advisory meeting –presentations and
comments will be recorded and documented
3 Avista Corp.2021 Electric IRP Appendices 435
Integrated Resource Planning
•Required by Idaho and Washington* every other year
•Guides resource strategy over the next twenty + years
•Current and projected load & resource position
•Resource strategies under different future policies
–Resource choices
–Conservation measures and programs
–Transmission and distribution integration for electric
–Gas distribution planning
–Gas and electric market price forecasts
•Scenarios for uncertain future events and issues
•Key dates for modeling and IRP development are
available in the Work Plans
4 Avista Corp.2021 Electric IRP Appendices 436
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
–Help with soliciting new members
•Open forum while balancing need to get through all of the topics
•Welcome requests for studies or different assumptions.
–Time or resources may limit the number or type of studies
–Earlier study requests allow us to be more accommodating
–August 1, 2020 was the electric study request deadline
•Planning teams are available by email or phone for questions or
comments between the TAC meetings
5 Avista Corp.2021 Electric IRP Appendices 437
2021 Electric IRP TAC Schedule
•TAC 1: Thursday, June 18, 2020
•TAC 2: Thursday, August 6, 2020 (Joint with Natural Gas TAC)
•TAC 2.5: Tuesday, August 18, 2020 Economic and Load Forecast
•TAC 3: Tuesday, September 29, 2020
•TAC 4: Tuesday, November 17, 2020
•TAC 4.5: December 2020 –2 Hours on Scenarios
•TAC 5: Thursday, January 21, 2021
•Public Outreach Meeting: February 2021
•TAC agendas, presentations, meeting minutes and IRP files
available at:
https://myavista.com/about-us/integrated-resource-planning
6 Avista Corp.2021 Electric IRP Appendices 438
Process Updates
Available IRP Data:
•Avista Resource Emissions Summary
•Load Forecast
•CPA Measures
•Avista 2020 Electric CPA –Summary and IRP Inputs
•Home Electrification Conversions
•Named Populations
•Natural Gas Prices
•Social Cost of Carbon
Files Added Since TAC 3:
•High and Low Natural Gas Prices
•Market Modeling Results
•Climate Shift Scenario Inputs
•2021 IRP New Resource Options
7 Avista Corp.2021 Electric IRP Appendices 439
Today’s TAC Agenda
9:00 Introductions, Lyons
9:15 Final Resource Need Assessment, Lyons
9:45 2020 Renewable RFP Update, Drake
10:20 Break
10:30 Portfolio Modeling Overview, Gall
11:30 Lunch
12:30 Draft PRS and Scenarios, Gall
2:00 Adjourn
8 Avista Corp.2021 Electric IRP Appendices 440
2020 Electric IRP
Resource Need Assessment
John Lyons, Ph.D.
Fourth Technical Advisory Committee Meeting
November 17, 2020
Avista Corp.2021 Electric IRP Appendices 441
Load & Resource Methodology Review
•Sum resource capabilities against loads
•Resource plans are subject to 5% LOLP analysis –
determines planning margins
•Colstrip is included through 2025 per 2020 IRP
•Capacity
–Planning Margin (16% Winter, 7% Summer)
•Using 2020 IRP result; pending future analysis
–Operating Reserves and Regulation (~8%)
–Reduced by planned outages for maintenance
–Plan to largest deficit months between 1-and 18-hour analyses
•Energy
–Reduced by planned and forced outages
–Maximum potential thermal generation over the year
–80-year hydro average, adjusted down to 10th percentile
2 Avista Corp.2021 Electric IRP Appendices 442
One Hour Peak Load & Resource Position
3
(700)
(600)
(500)
(400)
(300)
(200)
(100)
0
100
200
300
400
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Me
g
a
w
a
t
t
s
1 Hour Peak Load & Resource Position
Avista Corp.2021 Electric IRP Appendices 443
18-Hour Peak Load & Resource Position
4
(500)
(400)
(300)
(200)
(100)
0
100
200
300
400
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Me
g
a
w
a
t
t
s
18 Hour Peak Load & Resource Position
Avista Corp.2021 Electric IRP Appendices 444
Energy Load & Resource Position
5
(700)
(600)
(500)
(400)
(300)
(200)
(100)
0
100
200
300
400
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Me
g
a
w
a
t
t
s
Energy Load & Resource Position
Avista Corp.2021 Electric IRP Appendices 445
Avista’s Clean Energy Goal
•2027 –100% carbon-neutral
•2045 –100% clean electricity
How we will get there
Goals
•It’s not just about generation –various solutions are necessary
•Maintain focus on reliability and affordability
•Natural gas plays an important part of a clean energy future
•Cost effective technologies need to emerge and mature
6 Avista Corp.2021 Electric IRP Appendices 446
Washington State Clean Energy Goals
•Energy Independence Act or Initiative 937
–15% of Washington retail load after 2020
–Not modeling for this IRP since CETA takes us beyond 15%
–Last IRP anticipated the inclusion of qualifying BPA and
Wanapum generation, neither of which materialized
•Avista decision to offset costs in lieu of BPA RECs
•Inability to use Wanapum because of difference in hydro methodology
•Clean Energy Transformation Act
–By 2025 –eliminate coal-fired resources from serving WA
customers
–By 2030 –electric supply must be greenhouse gas neutral,
–By 2045 –electric supply must be 100% renewable or be
generated from zero-carbon resources
7 Avista Corp.2021 Electric IRP Appendices 447
2020 Renewable RFP Update
Chris Drake, Wholesale Marketing Manager
Fourth Technical Advisory Committee Meeting
November 17, 2020
Avista Corp.2021 Electric IRP Appendices 448
2
Justification
•Integrated Resource Plan (IRP) -Preferred
Resource Strategy (PRS)
•Market indicators suggested competitive
pricing for renewables
•Competition for preferred sites
•Corporate renewable goals –systemwide
–Carbon neutral by 2027
–100% clean electricity by 2045
•If bids are not compelling, no obligation to contract
•Capacity Request For Information (or similar investigation) may be considered at a later
date
2020 IRP Preferred Resource Strategy
Avista Corp.2021 Electric IRP Appendices 449
3
Cross-Departmental Review
•Power Supply
–Wholesale marketing, resource
planning, real-time, traders, credit
and resource optimization
•Transmission
•Regulatory
•Insurance/Risk
•Corporate Communications
•Legal
Transmission
Legal
Corporate
Communications
Regulatory
Insurance Risk
Power Supply
2020 Avista
Renewable RFP
Avista Corp.2021 Electric IRP Appendices 450
4
New Elements of 2020 RFP
•New and existing projects were eligible to bid
–New renewable resources
–Nonemitting electric generation (existing)
•Updated evaluation methodology criteria
–Risk Management, Net Price, Price Risk, Electric Factors, Environmental
–Added Community Impact
•Avista service territory economic impact
•Equity provisions
•Vulnerable and highly impacted communities
•Energy security
•Published evaluation methodology
Avista Corp.2021 Electric IRP Appendices 451
5
RFP Communications
•Published on
www.myavista.com
•Press Release
–Local media contacts
–GlobeNewswire
distribution to over 600
national outlets
Avista Corp.2021 Electric IRP Appendices 452
6
Renewable Generation Need
•RFP for up to 300 MW renewables
•2020 IRP’s PRS model
–2022 Montana wind –100 MW
–2022-2023 NW wind –200 MW
•Anticipated proposals –mix of
wind/solar/storage
2020 Avista
Renewable
RFP
Wind
Solar Storage
Repowering
Avista Corp.2021 Electric IRP Appendices 453
7
Bids Received July 22, 2020
•42 projects
•25 developers
•27 solar (many with battery options)
•13 wind (some with battery option)
•1 hydro
•1 biomass
Avista Corp.2021 Electric IRP Appendices 454
8
RFP Initial Reactions
•Good selection of shovel ready and existing
projects
•Good geographic distribution
–Projects throughout Northwest with majority in
Washington, then Montana, Idaho and Oregon
•Prices were higher than 2018 RFP
–Sunsetting PTC
–Increased construction costs
•Multiple capacity projects submitted
–Hydro
–Biomass
Avista Corp.2021 Electric IRP Appendices 455
9
2020 Avista Renewable RFP Evaluation Methodology
General Qualifications
•Compatibility with resource need
•Site control
•Financial plan to bring project to
completion
•Credit requirements
•Procurement plan
•Project completion no later than
December 31, 2023
Evaluation Criteria
•Risk Management -Credit and Developer
Experience
•Net Price -Nominal levelized cost / MWh
•Price Risk -Fixed price, construction, fuel
supply
•Electric Factors -Interconnection,
transmission, technology
•Environmental -Permitting
•Community Impact -Community
involvement, Avista service territory,
vulnerable populations
Avista Corp.2021 Electric IRP Appendices 456
10
2020 Target Schedule (and Milestones Completed)
June 26, 2020 –RFP Released
July 22, 2020 –Preliminary Information Due
July 31, 2020 –Short-list identified and notified (along with other bidders)
August 21, 2020 –Detailed proposals received from short-list
October 16, 2020 –Final bidder(s) selected for continued review
•December 31, 2020 –Contract negotiation(s)
Avista Corp.2021 Electric IRP Appendices 457
11
2020 RFP Next Steps
•Continue to address specific attributes within proposal(s)
•Contract negotiations with successful project(s)
•Continue internal review to make a final determination
Avista Corp.2021 Electric IRP Appendices 458
PRiSM Model Overview
James Gall, Electric IRP Manager
Fourth Technical Advisory Committee Meeting
November 17, 2020
Avista Corp.2021 Electric IRP Appendices 459
What is PRiSM?
•Preferred Resource Strategy Model
•Mixed Integer Program (MIP) used to select new resources to
meet resource needs of our customers
The user interface
The solver interface
The solver
2 Avista Corp.2021 Electric IRP Appendices 460
New PRiSM Features for 2021 IRP
•Significant changes were made to this IRP’s model due to
individual state policies.
–Model purpose: Same as before with additional constraints and options.
–New Constraints: Must meet individual state L&R balance requirements
and clean energy goals.
–New Options: Resources can be added for a specific state or the system.
–New Outputs: State level cost and rate estimates along with resource
strategies.
–Model will be fully available and published on IRP website.
–Model is continually being vetted.
3 Avista Corp.2021 Electric IRP Appendices 461
Objective Function
Minimize: (WA “Societal” NPV2022-45) + (ID NPV2022-45)
Where:
WA NPV2022-45 = Market Value of Load + Existing & Future Resource Cost/Operating Margin + Social Cost of Carbon + EE TRC
ID NPV2022-45 = Market Value of Load + Existing & Future Resource Cost/Operating Margin + EE UTC
Subject to:
Generation Availability & Timing
Energy Efficiency Potential
Demand Response Potential
Winter Peak Requirements
Summer Peak Requirements
Annual Energy Requirements
Clean Energy Goals
T&D Constraints
Optimization Tolerance: 0.0001 or 1,500 seconds (Note: certain studies longer solution times allowed)
4
Intro to linear programing: https://www.youtube.com/watch?v=Uo6aRV-mbeg
Avista Corp.2021 Electric IRP Appendices 462
Optimized Cost vs. Actual Costs
•Objective function includes social
costs that are not part of utility
revenue requirement.
•This is used for resource
optimization only.
•Social costs may include:
–Energy Efficiency
•TRC
•Non-energy benefits
•Power Act 10% adder
•T&D Savings
–Social Cost of Carbon
•Actual costs illustrate expected cost
ratepayers will pay.
•Estimate annual revenue
requirements.
•Estimate average rates.
5 Avista Corp.2021 Electric IRP Appendices 463
Aurora Integration
•Aurora’s price forecast and
resource dispatch are inputs into
PRiSM.
•Each supply resource’s
operations is included by iteration.
–Includes MWh, GHG, Revenue, Fuel
Cost, VOM costs.
•Avista load and existing
contracts are also entered in
totals.
•Energy efficiency load shapes are
marked to market and used for the
energy value of these programs.
•Demand response options are not
modeled in Aurora, but use hourly
price results for a market value.
6 Avista Corp.2021 Electric IRP Appendices 464
Thermal Resources
•Model may retain or exclude specific resources in any year.
–Retirements are for both states (except Colstrip).
–No re-allocation of existing resources between states.
•Includes major future capital spend for continued operation along with O&M costs.
•Resource costs and benefits are allocated using PT ratio (65% WA, 35% ID).
•Lancaster PPA expires in October 2026.
•Northeast assumes retirement in 2035 & Boulder Park in 2040.
•Kettle Falls CT is excluded from retirement option, but is excluded from winter peak
due to pending pipeline review.
•Colstrip must be removed in Washington by 2025.
–Model can remove earlier or retain for Idaho.
–Washington’s share of cost after 2025 are not included in model.
7 Avista Corp.2021 Electric IRP Appendices 465
Hydro Resources
•Available for full length of study.
•Post Falls assumes rebuild in 2025 (found cost effective in 2021 IRP).
•Energy, capacity, and clean energy attributes split between states using PT ratio
(65% WA/35% ID).
8 Avista Corp.2021 Electric IRP Appendices 466
Other Existing “Resources”
•PURPA
–CETA has provision for in-state PURPA generation reducing clean energy obligation.
–For modelling purposes, generation is allocated to each state it qualifies under PURPA.
•Other Wholesale Contracts
–Current PPAs are allocated to each state using PT ratio.
–Except for Adam’s Neilson Solar-fully allocated to Washington.
–PURPA related resales are fully allocated to state it qualifies for under PURPA
•Renewable Energy Credits (RECs)
–Each state receives “RECs” from its “PT ratio” share of resources.
–Model allows for sale of RECs between states subject to limits.
9 Avista Corp.2021 Electric IRP Appendices 467
Energy Efficiency
Washington
•AEG provides EE potential by year and program
–Winter peak savings
–Summer peak savings
–Annual average savings
•Electrical savings are grossed up for T&D losses
•Benefit of T&D Capital Avoidance ($25.35 per kW-yr)
•Total Resource Cost (TRC) test
•Add value for non-energy benefits ($23 per MWh)
•Power Act 10% adder for energy and capacity value
•Social Cost of Carbon using regional incremental
emission rates per MWh
•Included in L&R constraints to avoid new supply
resource options
Idaho
•AEG provides EE potential by year and program
–Winter peak savings
–Summer peak savings
–Annual average savings
•Electrical savings are grossed up for T&D losses
•Benefit of T&D Capital Avoidance ($25.35 per kW-yr)
•Utility Cost Test (UCT) for cost effectiveness
•Included in L&R constraints to avoid new supply
resource options
10 Avista Corp.2021 Electric IRP Appendices 468
Demand Response
•Programs available in each state determined by AEG.
•AEG estimated capital amortized over 5 years and a levelized cost is created by combining
the O&M costs.
•Projects must ramp in over time (except large industrial).
–25 MW of industrial DR for Washington
•Water heating is different between states:
–WA includes CTA-2045
–DLC water heating in ID
•Energy arbitrage and savings is included based on 50% of potential use.
–10% preference adder included for Washington.
•Peak Credit is using 2020 IRP estimate of 60%.
–Additional studies may be available to validate.
–Based on prior IRP-this estimate could be too high.
11 Avista Corp.2021 Electric IRP Appendices 469
Supply-Side Options
•Uses levelized fixed and variable costs for potentially owned resources (i.e.
natural gas, storage).
•Uses PPA $/MWh or $/kW-yr costs for resources.
•All generation costs are available on the IRP website.
•Washington PPA options includes rate of return for clean resources.
•Resources must be added in increments of probable size of actual
acquisition-not any value-this assumption can increase cost or change
resource strategy.
12 Avista Corp.2021 Electric IRP Appendices 470
Clean Energy Goals
•Washington
–100% clean energy (carbon neutral) by 2030
–100% clean energy by 2045
•MAJOR ASSUMPTIONS:
–By 2030, Washington’s clean energy must equal
100% of net retail sales; 20% of this total may
come from RECs.
•Only REC purchases assumed are from Idaho
customers at $7.50/MWh escalating
–2045, 100% goal of all 100% of electrons clean is
not modeled at this time (likely 2024 IRP).
–Between 2030 and 2045 REC transfers decline
to zero.
–Prior to 2030 REC transfers are limited to non-
hydro resources to encourage early acquisition.
•Idaho
–No clean energy requirement.
–Idaho is allowed to sell REC’s to Washington
LSE.
–Other REC sales to other parties are not
modeled.
–Scenarios will show cost of additional renewable
energy acquisition.
13 Avista Corp.2021 Electric IRP Appendices 471
Greenhouse Gas Emissions
•The model estimates the GHG emissions for thermal resource
dispatch.
–Market purchase/sale effects are estimated using the regional average
emission rate.
–Storage resources include a market based GHG adder.
•Societal emissions saved from Energy Efficiency using an incremental
emissions approach are estimated.
•Includes upstream emissions for natural gas resources.
•Construction and operation emissions are included.
14 Avista Corp.2021 Electric IRP Appendices 472
Social Cost of Carbon or Social Cost of Greenhouse Gas
Washington
–Costs are included for resource dispatch of
new thermal & storage options.
–Cost are also included for existing natural
gas-fired resources.
–Energy Efficiency receives a social credit
for emission savings.
–No cost are included for market
transactions, except for storage resources.
•This would give extra incentive to
renewables by valuing the social cost of
carbon on non-Avista resources. [Potential
scenario]
•Model time step doesn’t allow for SCC on
purchases only.
Idaho
–No direct cost of GHG is included.
–Objective function is 65% Washington Cost-
therefore existing resources are influenced
by this cost and could have effects on
Idaho.
–A scenario using the Washington
methodology will be studied.
15 Avista Corp.2021 Electric IRP Appendices 473
Transmission
•Resources have either a capital investment or a wheeling charge.
–Capital investments are based on the transmission cost estimates from the September 2020 TAC 3
meeting.
•Resource options in the Rathdrum, Idaho area are a challenge.
–Approximately 100 MW can be added without significant investment.
–Over 100 MW may either require additional infrastructure or Remedial Action Scheme (RAS).
•RAS has not been studied
–Avista has resource options in the area without new transmission (i.e. Lancaster), but if Lancaster
operates and Avista builds new resources would require an investment or RAS.
–For this analysis no additional Rathdrum transmission is assumed until either Lancaster is ruled out
from an RFP or RAS is determined to not be an option.
•By including the additional transmission cost could either create a portfolio where Idaho must pursue a more costly option-
an RFP needs to decide this rather then an IRP without cost of a Lancaster extension.
16 Avista Corp.2021 Electric IRP Appendices 474
Resource Adequacy Check
•To the furthest extent possible, portfolios will be studied for resource
adequacy for 2025, 2030, and 2040.
–Each study takes 3 days to complete; Avista has only 2 machines capable of this work.
•If a portfolio fails the adequacy test-additional capacity will be required or
noted.
•Avista does not expect to complete all studies for the draft IRP release.
–Although studies will be conducted through February for the final draft portfolios requiring
this work.
–All other studies will need to rely on the planning margin for its resource adequacy test.
•Reliability data input files are still in process and results are not available at
this time.
17 Avista Corp.2021 Electric IRP Appendices 475
Equity Provisions
•Avista previously identified potential areas within its system qualifying for
VP/HIC status, although final determination is still ongoing.
•A baseline analysis for cost and reliability/resilience has been completed.
•Avista is developing an Equity Advisory Group (EAG).
–EAG will determine final VP/HIC determinants.
–Develop outreach plan for each community to understand energy needs and preferences.
–Study solutions and develop programs to meet needs of the communities.
•Process to develop a solid plan for these VP/HIC communities will not be
available for this IRP.
18 Avista Corp.2021 Electric IRP Appendices 476
Least “Reasonable” Cost Strategy & Baseline Analysis
“Not Preferred Resource Strategy Yet”
James Gall, Electric IRP Manager
Fourth Technical Advisory Committee Meeting
November 17, 2020
DRAFT
Avista Corp.2021 Electric IRP Appendices 477
Safe Harbor Statement
This document contains forward-looking statements. Such statements are subject to a variety of risks,
uncertainties and other factors,most of which are beyond the Company’s control, and many of which could
have a significant impact on the Company’s operations, results of operations and financial condition, and
could cause actual results to differ materially from those anticipated.
For a further discussion of these factors and other important factors,please refer to the Company’s reports
filed with the Securities and Exchange Commission.The forward-looking statements contained in this
document speak only as of the date hereof.The Company undertakes no obligation to update any forward-
looking statement or statements to reflect events or circumstances that occur after the date on which such
statement is made or to reflect the occurrence of unanticipated events.New risks,uncertainties and other
factors emerge from time to time, and it is not possible for management to predict all of such factors,nor
can it assess the impact of each such factor on the Company’s business or the extent to which any such
factor, or combination of factors, may cause actual results to differ materially from those contained in any
forward-looking statement.
DRAFT
2 Avista Corp.2021 Electric IRP Appendices 478
Other Caveats
•Clean Energy Transformation Act (CETA) rules and requirements are not complete.
–This is Avista’s best estimate of known requirements.
•Avista is negotiating with the renewable Request for Proposals (RFP) shortlist bidders
–This may change the results of the resource plan due to a potential contract.
•IRP resource options are primarily “new” resource options-RFP will determine whether or
not existing resources can be acquired at similar or lower cost than “new” options.
•Avista may not be able to physically retire or exit certain resources as the IRP PRiSM model
determines.
•No future state specific resource cost allocation agreement has been made.
•Forward looking rates include non-modeled power supply cost escalating at 2% per year-
–DO NOT TAKE THIS AS A RATE FORECAST
–This is for informational purposes only
DRAFT
3 Avista Corp.2021 Electric IRP Appendices 479
Energy Efficiency Results
-
100.0
200.0
300.0
400.0
500.0
600.0
700.0
800.0
900.0
1,000.0
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
GW
h
Washington Energy
2020 IRP
2021 IRP
-
20.0
40.0
60.0
80.0
100.0
120.0
140.0
160.0
180.0
200.0
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
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20
3
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3
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3
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3
3
20
3
4
20
3
5
20
3
6
20
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20
3
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20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
MW
Washington Summer Peak
2020 IRP
2021 IRP
-
20.0
40.0
60.0
80.0
100.0
120.0
140.0
160.0
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
MW
Washington Winter Peak
2020 IRP
2021 IRP
-
100.0
200.0
300.0
400.0
500.0
600.0
700.0
800.0
900.0
1,000.0
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
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20
3
8
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3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
GW
h
Idaho Energy
2020 IRP
2021 IRP
-
20.0
40.0
60.0
80.0
100.0
120.0
140.0
160.0
180.0
200.0
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
MW
Idaho Summer Peak
2020 IRP
2021 IRP
-
20.0
40.0
60.0
80.0
100.0
120.0
140.0
160.0
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
MW
Idaho Winter Peak
2020 IRP
2021 IRP
NOTE:
Energy Efficiency results
do not materially impact
supply resource strategy.
Supply resource strategy
is based on the load
forecast for both energy
and peak.
EE is first estimated, then
added to the load
forecast; the model then
picks economic EE to
have net load equal to the
load forecast
DRAFT
4 Avista Corp.2021 Electric IRP Appendices 480
Cumulative Energy Efficiency End Use Results (GWh)
Appliances 0.7 0.1 6.6 0.8 15.6 2.7
Cooling 6.4 0.5 41.7 2.8 61.2 7.0
Electronics 1.1 0.2 15.2 4.8 27.1 9.3
Exterior Lighting 4.3 1.4 24.8 7.8 37.2 14.3
Food Preparation 0.1 0.0 2.2 0.4 5.9 0.9
Interior Lighting 21.1 13.0 103.6 49.3 176.3 89.6
Miscellaneous 1.5 0.3 16.0 2.8 36.0 5.5
Motors 4.9 3.4 35.3 24.0 41.3 27.0
Office Equipment 0.6 0.0 3.6 0.0 6.2 0.0
Process 0.7 0.1 4.1 1.1 4.5 1.4
Refrigeration 8.3 0.3 60.9 2.3 70.0 2.6
Space Heating 13.1 3.5 122.9 30.3 175.4 39.9
Ventilation 5.3 0.7 31.0 5.2 46.1 12.5
Water Heating 4.6 1.4 65.9 8.3 120.6 9.7
Total 72.7 25.1 533.7 140.0 823.4 222.3
DRAFT
5 Avista Corp.2021 Electric IRP Appendices 481
Cumulative Energy Efficiency Segment Results (GWh)
DRAFT
6
WA ID WA ID WA ID
College 2.7 0.7 13.8 4.2 19.5 7.5
Grocery 6.8 0.2 47.6 1.4 56.6 1.7
Health 2.7 0.9 14.5 4.7 23.0 8.1
Industrial 12.0 7.9 62.5 41.1 91.4 61.1
Large Office 6.6 1.3 43.6 8.8 67.5 16.5
Lodging 1.4 0.6 8.9 2.9 13.2 4.9
Low Income 3.4 1.7 40.4 10.7 60.8 13.2
Miscellaneous 6.1 1.9 41.5 10.7 61.3 19.1
Mobile Home 0.7 0.2 7.2 1.4 14.2 2.1
Multi-Family 0.5 0.2 7.6 1.2 16.6 1.9
Restaurant 2.1 0.2 15.1 1.6 20.2 2.3
Retail 5.6 2.0 35.8 10.3 52.8 17.9
School 3.1 0.1 18.5 0.4 28.7 0.8
Single Family 14.4 5.1 147.6 28.6 250.3 42.8
Small Office 2.4 1.1 16.9 7.4 26.5 13.5
Warehouse 2.4 0.9 12.4 4.7 20.8 8.9
Total 72.7 25.1 533.7 140.0 823.4 222.3
2023 2031 2045
Avista Corp.2021 Electric IRP Appendices 482
Higher Washington Energy Efficiency Goals
More Aggressive Ramp Rates & Higher Avoided Costs
33
73
117
168
226
288
353
417
478
534
107
0
100
200
300
400
500
600
Cumulative Savings
Pro Rata 10
CPA Pro-Rata Share 106,740 72,338
Distribution and Street Light Efficiency 219 504
EIA Target 106,959 72,842
Decoupling Threshold 5,348 3,642
Total Utility Conservation Goal 112,307 76,484
Excluded Programs (NEEA)-14,016 -14,016
Utility Specific Conservation Goal 98,291 62,468
Decoupling Threshold -5,348 -3,642
EIA Penalty Threshold 92,943 58,826
DRAFT
7 Avista Corp.2021 Electric IRP Appendices 483
Stacked 20-Year Levelized Energy Efficiency
Avoided Cost (WA)
DRAFT
8
$0
$20
$40
$60
$80
$100
$120
$140
Le
v
e
l
i
z
e
d

2
0
y
r

$
/
M
W
h
Energy Value
$0
$20
$40
$60
$80
$100
$120
Le
v
e
l
i
z
e
d

2
0
y
r

$
/
k
W
-yr
Capacity Value
Avista Corp.2021 Electric IRP Appendices 484
Stacked 20-Year Levelized Energy Efficiency
Avoided Cost (ID)
DRAFT
9
$0
$20
$40
$60
$80
$100
$120
$140
Le
v
e
l
i
z
e
d

2
0
y
r

$
/
M
W
h
Energy Value
$0
$20
$40
$60
$80
$100
$120
Le
v
e
l
i
z
e
d

2
0
y
r

$
/
k
W
-yr
Capacity Value
Avista Corp.2021 Electric IRP Appendices 485
Demand Response
Program Washington Idaho
Time of Use Rates 2 MW (2024)2 MW (2030)
Variable Peak Pricing 7 MW (2024)6 MW (2030)
Large C&I Program 25 MW (2027)n/a
DLC Smart Thermostats 7 MW (2030)n/a
Third Party Contracts 15 MW (2031)n/a
Behavioral Programs 1 MW (2039)n/a
Total 56 MW 8 MW
Note: DR programs in another state for the benefit of the other state is not modeled
DRAFT
10 Avista Corp.2021 Electric IRP Appendices 486
2022-2025 Supply Side Resource Changes
2022: Economic to exit out of Colstrip 3 & 4 (Both)
2023: 100 MW of Montana Wind (WA)
2024: 50 MW of Montana Wind (WA)
2025: No Action
NOTE: Renewable RFP may change this strategy
DRAFT
11 Avista Corp.2021 Electric IRP Appendices 487
2026-2029 Supply Side Resource Changes
2026: 50 MW Montana Wind (WA)
48 MW NG SCCT (Both)
Lancaster CCCT contract ends (Both)
2026/27: 84 MW NG SCCT (ID)
84 MW NG SCCT (Both)
12 MW Upgrade Kettle Falls (Both)
2028: 50 MW Montana Wind (WA)
2029: 50 MW Solar + 50 MW 4-Hour Storage (Both)
NOTE: Renewable RFP may change this strategy
DRAFT
12 Avista Corp.2021 Electric IRP Appendices 488
2030-2033 Supply Side Resource Changes
2030:No Action
2031:75 MW Hydro Contract Renewal (WA)
2032:No Action
2033:No Action
NOTE: Renewable RFP may change this strategy
DRAFT
13 Avista Corp.2021 Electric IRP Appendices 489
2034-2037 Supply Side Resource Changes
2034:5 MW Rathdrum CT Upgrade (Both)
2035:50 MW Solar + 50 MW 4-Hour Storage (Both)
Northeast Retires (Both)
2036:50 MW Hydrogen SCCT (WA)
55 MW NG SCCT (ID)
2037:No Action
DRAFT
14 Avista Corp.2021 Electric IRP Appendices 490
2038-2045 Supply Side Resource Changes
2038:50 MW Montana Wind (WA)
2039: No Action
2040: 50 MW Solar + 50 MW 4-Hour Storage (Both)
2041: 50 MW Solar + 50 MW 4-Hour Storage (WA)
50 MW Montana Wind (WA)
Boulder Park Retires (Both)
2042:50 MW Montana Wind (WA)
50 MW Solar + 50 MW 4-Hour Storage (Both)
2043:50 MW Solar (WA)
100 MW Solar + 100 MW 4-Hour Storage (Both)
2044:50 MW Solar + 50 MW 4-Hour Storage (ID)
2045:150 MW Solar (WA)
30 MW Storage (ID)
DRAFT
15 Avista Corp.2021 Electric IRP Appendices 491
Least Reasonable Cost Resource Selection (MW)
NG CT 0 0 0 0 48 84 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 50 0 0 0 0 0 50 0 0 0 0 50 0 50 100 0 0
Storage Added to Solar 0 0 0 0 0 0 0 50 0 0 0 0 0 50 0 0 0 0 50 0 50 100 0 0
Wind 0 0 0 0 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 0 0 0 0
Hydrogen 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Other- (Clean Capacity)0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Thermal Upgrade 0 0 0 0 0 12 0 0 0 0 0 0 5 0 0 0 0 0 0 0 0 0 0 0
Hydro 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Washington
NG CT 0 0 0 0 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 50 0 50 0 150
Storage Added to Solar 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 50 0 0 0 0
Wind 0 100 50 0 50 0 50 0 0 0 0 0 0 0 0 0 50 0 0 50 50 0 0 0
Storage 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Hydrogen 0 0 0 0 0 0 0 0 0 0 0 0 0 0 50 0 0 0 0 0 0 0 0 0
Other- (Clean Capacity)0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Thermal Upgrade 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Hydro 0 0 0 0 0 0 0 0 0 75 0 0 0 0 0 0 0 0 0 0 0 0 0 0
DR Capability 0 0 1 4 9 37 37 37 38 42 47 54 56 56 56 56 56 56 56 57 57 56 56 56
EE- Winter Capacity 3 4 5 6 7 7 8 8 7 6 5 4 4 3 2 2 2 1 1 1 1 0 0 0
EE- Summer Capacity 5 5 6 7 8 8 9 8 8 7 6 5 4 3 3 2 2 2 2 0 0 0 0 0
Idaho
NG CT 0 0 0 0 0 84 0 0 0 0 0 0 0 0 55 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 0 0 50 0
Storage Added to Solar 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 50 0
Wind 0 0 0 0 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 0 0 0 30
Hydrogen 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Other- (Clean Capacity)0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Thermal Upgrade 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Hydro 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
DR Capability 0 0 0 0 0 0 0 0 1 3 7 9 10 10 10 10 9 9 9 9 9 9 9 8
EE- Winter Capacity 1 1 2 2 2 2 2 2 2 2 1 1 1 0 0 0 0 0 0 0 0 0 0 0
EE- Summer Capacity 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 0 0 0 0 0 0 0 0 0
DRAFT
16 Note: DR is cumulative due to the small changes year to yearAvista Corp.2021 Electric IRP Appendices 492
Clean Energy Share (aMW)
-
200
400
600
800
1,000
1,200
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
System
Existing Clean Resources RECs New Clean Resources Net Sales
-
200
400
600
800
1,000
1,200
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
Washington
Existing Clean Resources RECs New Clean Resources Net Sales
-
200
400
600
800
1,000
1,200
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
Idaho
Existing Clean Resources RECs New Clean Resources Net Sales
System Clean Resource Percentage
2022: 74.8%
2027: 78.3%
2045: 85.5%
Excludes Clean Market Purchases
DRAFT
17 Avista Corp.2021 Electric IRP Appendices 493
Annual Average Least Reasonable Cost Rate Forecast
NOTE: Estimated rates only using 2% annual rate increase for non-modeled costs
DRAFT
18
0.00
0.02
0.04
0.06
0.08
0.10
0.12
0.14
0.16
0.18
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Do
l
l
a
r
s

p
e
r

K
W
h
Avista Corp.2021 Electric IRP Appendices 494
Greenhouse Gas Forecast
Note: Assumes Colstrip exits the portfolio
DRAFT
19
Mi
l
l
i
o
n

M
e
t
r
i
c

T
o
n
s
Avista Corp.2021 Electric IRP Appendices 495
Baseline Analysis
1.Least Reasonable Cost Strategy: Includes all requirements
2.Baseline Portfolio 1: Excludes CETA’s 2030 and 2045 goals
–Used for incremental cost calculation
3.Baseline Portfolio 2: Baseline Portfolio 1 + removal of SCC
–Energy Efficiency held constant from LCS
–Used to estimate cost of capacity by comparing to Baseline 3
4.Baseline Portfolio 3: Baseline Portfolio 2 + removal of capacity
constraints
–Estimates cost to serve load without new resources
DRAFT
20 Avista Corp.2021 Electric IRP Appendices 496
Resource
Mix
Summary
DRAFT
21
1. LRCS 2. Baseline 1 3. Baseline 2 4. Baseline 3
Shared System Resource
NG CT 132 132 479 0
Solar 300 150 150 0
Storage Added to Solar 300 150 150 0
Wind 0 0 0 0
Storage 0 33 0 0
Hydrogen 0 0 0 0
Other- (Clean Capacity)0 0 0 0
Thermal Upgrade 17 17 17 0
Hydro 0 0 75 0
Washington
NG CT 0 84 0 0
Solar 250 0 0 0
Storage Added to Solar 50 0 0 0
Wind 400 0 0 0
Storage 0 30 0 0
Hydrogen 50 100 0 0
Other- (Clean Capacity)0 0 0 0
Thermal Upgrade 0 0 0 0
Hydro 75 75 0 0
DR Capability 56 55 35 3
EE- Winter Capacity 88 86 88 88
EE- Summer Capacity 101 94 101 101
Idaho
NG CT 139 139 0 0
Solar 50 0 50 0
Storage Added to Solar 50 0 50 0
Wind 0 0 0 0
Storage 30 90 80 0
Hydrogen 0 0 0 0
Other- (Clean Capacity)0 0 0 0
Thermal Upgrade 0 0 0 0
Hydro 0 0 0 0
DR Capability 8 19 19 2
EE- Winter Capacity 24 23 24 24
EE- Summer Capacity 13 13 13 13
Avista Corp.2021 Electric IRP Appendices 497
Cost Comparison of Baseline Scenarios
Cost difference is cost of
clean energy targets
Cost difference is cost of
clean energy targets & SCC
(excludes EE)Cost difference is cost of
capacity
DRAFT
22
Le
v
e
l
i
z
e
d

R
e
v
e
n
u
e

R
e
q
u
i
r
e
m
e
n
t
Avista Corp.2021 Electric IRP Appendices 498
Washington CETA Cost Cap Analysis
(assumes current methodology)
Washington Incremental Cost Calculation 2022 2023 2024 2025
Revenue Requirement w/ SCC 651 669 693 698
Baseline (Total Revenue Requirement Plus SCC)649 657 670 675
Annual Delta 2 12 23 23
Percent Change 0% 2% 3% 3%
Four Year Max Spending 118.4
Annual Max Spending 29.6 29.6 29.6 29.6
Forecasted Spend 59
(59)
Washington Incremental Cost Calculation 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
Revenue Requirement w/ SCC 718 715 735 749 763 775 782 797 810 825 855 861 889 900 914 925 951 984 1,013 1,030
Baseline (Total Revenue Requirement Plus SCC)685 702 713 725 735 754 759 775 786 798 829 834 868 877 887 888 912 936 986 996
Annual Delta 33 13 22 23 28 22 23 22 24 28 25 27 21 23 27 37 39 48 27 34
Percent Change 5% 2% 3% 3% 4% 3% 3% 3% 3% 3% 3% 3% 2% 3% 3% 4% 4% 5% 3% 3%
Four Year Max Spending 127.9 136.8 146.0 158.5 113.2
Annual Max Spending 32.0 32.0 32.0 32.0 34.2 34.2 34.2 34.2 36.5 36.5 36.5 36.5 39.6 39.6 39.6 39.6 37.7 37.7 37.7
Forecasted Spend 91 94 104 108 113
(37) (43) (42) (50) 0
Incremental cost
Annual spending to use cap
Forecasted to be under cap
Avista should hit 2042-44 rate
cap. Increases exceed 2% each year over
baseline, but rate cap is exponential.
DRAFT
23 Avista Corp.2021 Electric IRP Appendices 499
New Supply-Side Resource Avoided Costs
DRAFT
24
Year
Flat
($/MWh)
On-Peak
($/MWh)
Off-Peak
($/MWh)
Clean
Energy
Premium
($/MWh)
Capacity
Premium
($/kW-Yr)
20 yr Levelized $25.86 $25.18 $26.78 $25.27 $57.64
24 yr Levelized $27.18 $26.36 $28.30 $25.33 $62.15Avista Corp.2021 Electric IRP Appendices 500
Least “Reasonable” Cost Strategy & Baseline Analysis
“Not Preferred Resource Strategy Yet”
James Gall, Electric IRP Manager
Fourth Technical Advisory Committee Meeting
November 17, 2020
DRAFT
Avista Corp.2021 Electric IRP Appendices 501
Safe Harbor Statement
This document contains forward-looking statements. Such statements are subject to a variety of risks,
uncertainties and other factors,most of which are beyond the Company’s control, and many of which could
have a significant impact on the Company’s operations, results of operations and financial condition, and
could cause actual results to differ materially from those anticipated.
For a further discussion of these factors and other important factors,please refer to the Company’s reports
filed with the Securities and Exchange Commission.The forward-looking statements contained in this
document speak only as of the date hereof.The Company undertakes no obligation to update any forward-
looking statement or statements to reflect events or circumstances that occur after the date on which such
statement is made or to reflect the occurrence of unanticipated events.New risks,uncertainties and other
factors emerge from time to time, and it is not possible for management to predict all of such factors,nor
can it assess the impact of each such factor on the Company’s business or the extent to which any such
factor, or combination of factors, may cause actual results to differ materially from those contained in any
forward-looking statement.
DRAFT
2 Avista Corp.2021 Electric IRP Appendices 502
Portfolio Scenarios-2021 IRP
1.Preferred Resource Strategy
2.Baseline Portfolio 1 (No CETA renewable targets)
3.Baseline Portfolio 2 (No CETA renewable targets/SCC)
4.Baseline Portfolio 3 (No additions)
5.Clean Resource Plan (100% Portfolio net clean by 2027)
6.Clean Resource Plan (100% Portfolio clean by 2045)
7.Social Cost of Carbon applied to Idaho
8.Least Cost Plan-w/ low load growth
9.Least Cost Plan-w/ high load growth
10.Least Cost Plan-w/ Northwest Resource Adequacy Market Peak Credits
11.Heating Electrification Scenario 1
12.Heating Electrification Scenario 2
13.Heating Electrification Scenario 3
14.Least Cost Plan-w/ climate shift
15.Least Cost Plan-w/ 2x SCC prices
16.Colstrip serves Idaho customers through 2025
17.Colstrip serves Idaho customers through 2035
18.Colstrip serves Idaho customers through 2045
19.If necessary: CETA deliver to customers each hour
20.Social Cost of Carbon “Tax” Least Cost Strategy
21.If necessary: other resource specific scenarios depending on outcome of PRS results
Only black font
scenarios are shown
in this presentation
DRAFT
3 Avista Corp.2021 Electric IRP Appendices 503
Scenario Descriptions
1.Least Reasonable Cost Strategy: Includes all requirements
2.Baseline Portfolio 1: Excludes CETA’s 2030 and 2045 goals
–Used for incremental cost calculation
3.Baseline Portfolio 2: Baseline Portfolio 1 + removal of SCC
–Energy Efficiency held constant from LCS
4.Baseline Portfolio 3: Baseline Portfolio 2 + removal of capacity constraints
–Energy Efficiency held constant from LCS
5.Clean Resource Plan (2027)
–Add constraint to meet or exceed 100% of all retail sales with clean energy
6.Clean Resource Plan (2045)
–Add constraint to meet or exceed 100% of all retail sales with clean energy
–All thermal resources must exit by 2044
–No new thermal resources
7.Social Cost of Carbon applied to Idaho
–Includes SCC as cost adder to generation and savings for EE using same method as
Washington State
DRAFT
4 Avista Corp.2021 Electric IRP Appendices 504
Scenario Descriptions Continued
15.Least Cost Plan-with 2 time SCC prices
–Double of Social Cost of Carbon charge for Washington Only
16.Colstrip serves Idaho customers through 2025
–Colstrip obligated to run through 2025 in both states
17.Colstrip serves Idaho customers through 2035
–Colstrip obligated to run though 2035 for Idaho
18.Colstrip serves Idaho customers through 2045
–Colstrip obligated to run through 2045 for Idaho
DRAFT
5 Avista Corp.2021 Electric IRP Appendices 505
Portfolio Sensitivities
•Portfolio scenarios will be tested with alternative price forecasts
–High Natural Gas Prices
–Low Natural Gas Prices
–Social Cost of Carbon “Tax”
–Climate Shift
•Likely available for draft document, but not TAC presentations
DRAFT
6 Avista Corp.2021 Electric IRP Appendices 506
Scenario Cumulative Resource Selection
NG CT 132 132 479 0 0 0 48 0 132 132 132
Solar 300 150 150 0 650 670 200 100 300 300 300
Storage Added to Solar 300 150 150 0 650 625 200 100 300 300 300
Wind 0 0 0 0 250 550 0 0 0 0 0
Storage 0 33 0 0 0 0 0 0 0 0 0
Hydrogen 0 0 0 0 0 0 0 0 0 0 0
Other- (Clean Capacity)0 0 0 0 0 20 0 0 0 0 0
Thermal Upgrade 17 17 17 0 17 12 17 17 17 17 17
Hydro 0 0 75 0 0 0 75 0 0 0 0
Washington
NG CT 0 84 0 0 48 0 84 144 0 0 0
Solar 250 0 0 0 100 0 350 0 250 250 250
Storage Added to Solar 50 0 0 0 0 0 50 0 75 0 0
Wind 400 0 0 0 200 450 400 600 400 400 400
Storage 0 30 0 0 0 250 0 140 0 10 10
Hydrogen 50 100 0 0 50 100 50 100 50 50 50
Other- (Clean Capacity)0 0 0 0 0 50 0 0 0 0 0
Thermal Upgrade 0 0 0 0 0 0 0 0 0 0 0
Hydro 75 75 0 0 75 75 0 75 75 75 75
DR Capability 56 55 35 3 56 104 56 55 55 57 57
EE- Winter Capacity 88 86 88 88 89 91 90 98 88 91 92
EE- Summer Capacity 101 94 101 101 99 115 116 142 113 100 100
Idaho
NG CT 139 139 0 0 120 0 84 223 139 139 55
Solar 50 0 50 0 300 585 0 0 0 0 50
Storage Added to Solar 50 0 50 0 125 200 0 0 0 0 50
Wind 0 0 0 0 150 50 0 0 0 0 0
Storage 30 90 80 0 0 0 40 50 90 70 130
Hydrogen 0 0 0 0 0 250 50 50 0 0 0
Other- (Clean Capacity)0 0 0 0 0 0 0 0 0 0 0
Thermal Upgrade 0 0 0 0 0 0 0 0 0 0 0
Hydro 0 0 0 0 0 0 0 0 0 0 0
DR Capability 8 19 19 2 19 19 21 7 8 17 20
EE- Winter Capacity 24 23 24 24 25 33 39 23 22 21 23
EE- Summer Capacity 13 13 13 13 18 22 36 12 15 11 15
DRAFT
7 Avista Corp.2021 Electric IRP Appendices 507
Existing Resource “Exits”
1- LRCS
2- Baseline
1
3- Baseline
2
4- Baseline
3 w/ EE
5- Clean
Resource
Plan (2027)
6- Clean
Resource
Strategy
(2045)
7- SCC
Idaho 15- 2x SCC
16- Colstrip
2025
17- Colstrip
2035
18- Colstrip
2045
Coyote Springs 2 - - - - -2044 -2022 - - -
Lancaster 2026 2026 2026 2026 2026 2026 2026 2026 2026 2026 2026
Colstrip (3)2021 2021 2021 2021 2021 2035 2021 -2025 2035 2045
Colstrip (4)2021 2021 2021 2021 2021 2021 2021 2025 2025 2035 2045
Kettle Falls - - - - - - - - - - -
Kettle Falls CT - - - - -2044 - - - - -
Boulder Park 1-6 2040 2037 2026 2040 2040 2040 2040 2030 2040 2040 2040
Rathdrum 1 - - - - -2044 - - - - -
Rathdrum 2 - - - - -2044 - - - - -
Northeast A&B 2035 2035 2026 2035 2035 2035 2035 2035 2035 2035 2035
Note:
Assumes each plant is available through December 31st of the final year;
Exception: Lancaster PPA expires Oct 2026.
Dash indicates no plant exit in the study
DRAFT
8 Avista Corp.2021 Electric IRP Appendices 508
2022-45 Levelized Revenue Requirement
$730 $705 $702 $681
$736 $748 $732
$778
$732 $733 $733
$380 $384 $381 $368
$410 $411 $381 $393 $393 $381 $381
$0
$100
$200
$300
$400
$500
$600
$700
$800
$900
1- LRCS 2- Baseline13- Baseline24- Baseline3 5- CRS(2027)6- CRS(2045)7- LRCS(ID SCC)15- LRCS2x SCC 16- Colstrip202517- Colstrip203518- Colstrip2045
Washington Idaho
DRAFT
9 Avista Corp.2021 Electric IRP Appendices 509
Rate Estimates (Average Annual)
WA-2030 ID- 2030 WA- 2045 ID- 2045
DRAFT
10 Avista Corp.2021 Electric IRP Appendices 510
Annual Greenhouse Gas Emission
Avista Dispatch & Storage Purchases
DRAFT
11
Mi
l
l
i
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n
s

o
f

M
e
t
r
i
c

T
o
n
s
Avista Corp.2021 Electric IRP Appendices 511
Cost vs. GHG Tradeoffs
Change in Levelized Cost vs. Change in Levelized Net Emissions
1-LRCS
2-Baseline 1
3-Baseline 2
4-Baseline 3
5-CRS (2027)
6-CRS (2045)
7-SCC Idaho
15-LRCS 2x SCC
16-Colstrip 2025
17-Colstrip 2035
18-Colstrip 2045
DRAFT
12 Avista Corp.2021 Electric IRP Appendices 512
2030 Risk Analysis
Measures 2030 standard deviation of “modeled” power cost compared to levelized cost
DRAFT
13
$0
$10
$20
$30
$40
$50
$60
$1,040 $1,060 $1,080 $1,100 $1,120 $1,140 $1,160 $1,180
20
3
0

S
t
d
e
v

(
m
i
l
l
i
o
n
s
)
2022-2044 Levelized Revenue Requirement (Millions)
Note: PPA cost are considered “fixed” for this analysis-meaning the cost do not change with changes in delivered energy
Avista Corp.2021 Electric IRP Appendices 513
2045 Risk Analysis
Measures 2045 standard deviation of “modeled” power cost compared to levelized cost
DRAFT
14 Note: PPA cost are considered “fixed” for this analysis-meaning the cost do not change with changes in delivered energy
$0
$20
$40
$60
$80
$100
$120
$140
$160
$1,040 $1,060 $1,080 $1,100 $1,120 $1,140 $1,160 $1,180
20
4
5

S
t
d
e
v

(
m
i
l
l
i
o
n
s
)
2022-2044 Levelized Revenue Requirement (Millions)
Avista Corp.2021 Electric IRP Appendices 514
2045 Upper Tail Risk Analysis
95th percentile power cost minus mean power cost compared to levelized cost
DRAFT
15 Note: PPA cost are considered “fixed” for this analysis-meaning the cost do not change with changes in delivered energy
$0
$50
$100
$150
$200
$250
$300
$1,040 $1,060 $1,080 $1,100 $1,120 $1,140 $1,160 $1,180
20
4
5

T
a
i
l

R
i
s
k

(
m
i
l
l
i
o
n
s
)
2022-2044 Levelized Revenue Requirement (Millions)
Avista Corp.2021 Electric IRP Appendices 515
Next Steps
•Post PRiSM model to website
•Complete other scenarios and sensitivities
•Begin reliability studies
•Update PRiSM model for any modifications
•Select Preferred Resource Strategy
•Re-run scenarios and sensitivities
•Continue reliability studies if necessary
16 Avista Corp.2021 Electric IRP Appendices 516
2021 Electric IRP TAC 4 Meeting – November 17, 2020
Annette Brandon, James Gall, Lori Hermanson, John Lyons, Tom Pardee, Chip Estes,
Dainee Gibson-Webb (ICL), Dean Kinzer, Jody Morehouse, Kevin Keyt, Annie Gannon,
Leona Haley, Clint Kalich, Melissa Kuo (Clearwater), Michael Eldred (IPUC), Mike Louis
(IPUC), Rachel Farnsworth (IPUC), Peter Sawicki (Mitsubishi Power), Jennifer Snyder
(UTC), Terri Carlock (IPUC), Jan Himebaugh (BIAW), Shay Bauman (PC), Joanna
Huang (UTC), Ryan Finesilver, Marissa Warren, Jaime Majure, James McDougal, Joni
Bosh (NWEC) , Amanda Ghering, George Lynch, Katie Ware, Ian McGetrick, John
Chatburn, Amy Wheeless (NWEC), Corey Dahl (Public Counsel), Jorgen Rasmussen,
Jared Hansen, Garrett Brown, Pat Ehrbar, Charlie Inman (PSE), Steve Johnson (UTC),
Terrance Brown, Jared Hansen (IPUC), Chris Drake, Scott Kinney, Jason Thackston,
Darrell Soyars, Sean Bonfield, Thomas Dempsey, Jeff Schlect, Ben Otto (ICL), Meghan
Pinch, Grant Forsyth, Tina Jayaweera, and Tomas Morrissey (PNUCC).
Any notes in italics are short response from the presenter for each topic.

Introductions, John Lyons
No questions

Final Resource Needs Assessment (formerly L&R), John Lyons
Steve Johnson: Are Colstrip and Lancaster the deficits in 2026/27?
James Gall: The loss of Colstrip for 220 MW and Lancaster for 222 MW are the two
major changes from the 2025-2027 period.

2020 Renewable RFP Update, Chris Drake
Steve Johnson: Under proposed CR103 for IRP planning with CETA requirements, if
the deficit is within 4 years you will need an RFP. I notice your capacity need is just over
4 years out. Do you anticipate issuing another RFP after this one?
James Gall: The resource strategy may call for resources ahead of need or it may call
for a renewable or non-capacity need. If this RFP can satisfy those needs that could
push this earlier resource shortage further out. If there’s still a need after this RFP is
complete, we’ll need to do an RFP in the next year or so since it will be close to that 4-
year window if something new needs to be built.
Steve Johnson (Slide 5): I’m concerned with that being late given the general region is
also needing resources around this date and we will be in a capacity crunch. We’re
waiting, but that could pose a problem with coal retirements and everyone else being in
Avista Corp.2021 Electric IRP Appendices 517
the same boat at the same time. Rather, could you smooth purchases out ahead of time
as opposed to buying just before the need?
James Gall: You have the same concerns we do.
Jason Thackston: Can’t time these perfectly. We need to ensure reliability which
guides the timing to early rather than to later acquisition while trying to balance
affordability, etc.

Portfolio Modeling Overview, James Gall
Ben Otto via chat: Avista – can you send out a copy of this portion of the presentation
materials? Thank you. An email was just sent with the updated slide decks. Thanks
John and Lori. The PRiSM slides are the ones I was looking for.
James Gall: It will be sent out shortly to the entire TAC.
Peter Sawicki: How do you look at new technology such as renewable hydrogen?
James Gall: The list of resources included in our model, forecast of costs, and forecast
of how costs change are all on our website and are out there for input from the TAC.
Two renewable hydrogen options were included.
Mike Louis: Quite a bit of additional functionality that you’re building into PRiSM, what
steps are you taking for validation of that model?
James Gall: How would you define validation?
Mike Louis: How well does the model represent operations and how well is the model
producing something that represents reality.
James Gall: That is the benefit of building the model in Excel. It is easy to audit and
how it works is transparent. You can see the L&R balances, if the costs are reasonable,
and it is reviewed by internal and external folks to make sure the model is producing a
result based on the math we intended. There may be some disagreement with
assumptions for inputs, but you can review the math. For operations, we are not
proposing any changes to our operations based on PRiSM modeling. This is a financial
exercise to determine who pays for resources in the future as opposed to how we
currently allocate resources.
Mike Louis: That helps a lot James. At the end of the day with my experience in
modeling, I’d like to see a validation plan to ensure validity for all the tests and the
results to see if they are reasonable. I’d like to see a comprehensive plan of how you
thought of this ahead of time and how you tested it.
James Gall: We’ll talk about a lot of these tests this afternoon. The scenarios test the
validity of the model a lot.
Avista Corp.2021 Electric IRP Appendices 518
Steve Johnson: Is this the model you’d use if you were examining DR in a single
source context? Would you still use this model?
James Gall: No, this is a planning tool. If you were choosing what to acquire, we’d use
something else – a more granular model. You could use this model for capacity value,
etc. You could put in resource options from an RFP to see what it’d pick, but it might be
better to use a more granular tool.
Steve Jonson: This model is enough to give you some value such as capacity value?
James Gall: Yes, it gives you the financial value, but not the reliability value.
Operational value and reliability value, you could put all of that into this tool and let it
pick your options. If you have a large amount of choices that are vastly different, this
tool would work; if the choices are more similar, you’d probably want a different tool.
Michael Eldred: Does that apply to new resources also?
James Gall: New resources are different and can be acquired just for one state or
allocated between both states. Operationally, they are the same, but the payments for
them could be different.
Mike Louis: For Colstrip, are you modeling those units separately?
James Gall: Yes, we are modeling Colstrip units with separate capital and O&M costs.
Ben Otto: Are you saying there is already a certain amount of efficiency in the load
forecast and some can be selected? And what happens if it can choose more than is
out there?
James Gall: We don’t know what energy efficiency is out there so we iterate. We keep
rerunning it until the amount selected and the amounts in the CPA are essentially the
same. Limits of econometric as opposed to end use forecast.
Jennifer Snyder: To make sure I have this correct about end effects for Grant’s load
forecast, no matter how much cost-effective energy efficiency is selected, it’s never
going to reduce it?
James Gall: It’s not going to change significantly. Grant does make assumptions on
how customers change their use through the use per customer numbers.
Grant Forsyth: I’m on the call. There are specific factors that reduce use per customer
and some that can’t be explained, but it could be “efficiency”. There is some amount of
energy efficiency I’m projecting going forward.
Jennifer Snyder: Ok, thank you. A follow up on that. How does that dynamic work with
DR?
James Gall: Good segue to the next slide. We have no historical DR programs [non-
pilot size], so DR doesn’t affect load for the forecast. DR is treated differently from that
point of view. EVs could be a concern.
Avista Corp.2021 Electric IRP Appendices 519
Grant Forsyth: There is nothing explicit for EVs. The load forecast assumed the
amount used per year per customer.
Steve Johnson: I’m trying to understand what kind of assumptions of cost and value
streams you put into your model.
James Gall: We assume Mid-C prices and not necessarily the value of selling any
beyond what goes into California.
Steve Johnson: CPUC regulatory action, that hasn’t been taking into account, but
maybe taking that into account has an impact on price. Would you put that into your
model?
James Gall: We value based on our market at the Mid-C, we’re only trying to value for
intra-hour energy. Other values are outputs based on your choices as compared to
energy-only resources.
Amy Wheeless via chat: Do you make any assumptions about consumers buying CTA
2045 enabled water heaters due to markets (e.g., someone in the CdA area buying a
water heat at a Spokane Lowes)?
James Gall: We’re not considering that.
Ben Otto: How are some results showing a shared system and then some are assigned
for each state?
James Gall: Let’s table that math to this afternoon’s discussion.
Ben Otto: If you sell RECs and return the revenue to Idaho customers, what about
increments of more than 20% being sold to Washington?
James Gall: We could show that. I will add it to the list. It would be available renewable
energy times the REC price.
Charlie Inman via chat (slide 15): For market transactions, the Washington CETA
defines the emission rate of “unspecified market purchases” as 0.437 metric tons per
MWh. Will this be included at all in the modeling process?

James Gall: Not at this time. It is in CETA, but is related to a different use and we’re
looking at this for the future. That default emissions number is based on a gas turbine.
We’re including the average market emissions rate for all purchases and storage. We’re
unable to model general purchases now, but will look at this for the future. There is an opportunity for adjustment.

Jennifer Snyder: I don’t recall what that is in CETA. It’s in section 7. I will read it over
lunch.

Avista Corp.2021 Electric IRP Appendices 520
Steve Johnson: There is not a lot of time for debating when it comes to the evaluation for transmission. For resources, you aren’t including any end-of-life resources past the
end of useful life, have you thought that there is an advantage to someone else
operating a resource, if it isn’t your least cost resource?

James Gall: Transmission costs are levelized; even if a resource does go offline, we
benefit from the available transmission. There is quite a bit of advantage if someone
else operates with all of that transmission interconnection. You’ve identified a head
scratcher of what could happen, but how can you model everything.

After lunch

Ben Otto: James, I thought of a question at lunch. What $/MWh is Avista using for the
social cost of carbon? Is it the Washington UTC adopted numbers?

James Gall: Ben, the social cost of carbon is the Washington adopted value for CETA.
It is available on the website in Excel form by year.

Draft PRS and Scenarios, James Gall
Steve Johnson: We are really on a roll now. This raises questions about whatever
happened to the idea for super freezing air.
James Gall: Liquid air shows up in some scenarios for some options in the future.
Hydrogen showed up rather than liquid air due to the resource assumption differences
for peak credits. Both are about storage, but fuel replacement as well. Hydrogen
assumes no constraints and gets a peak credit; whereas, liquid air has some constraints
– while there is an air storage tank, we might not be able to refill it quickly.
Stave Johnson: Thanks. That’s informative.
Peter Sawicki: What does “both” mean?
James Gall: Both means the resource serves both states. It serves 65% Washington
and 35% Idaho.
Peter Sawicki: For the 2029 resource picks, is that additive? Yes, but we could amend
that later.
James Gall (slide 16): DR is cumulative, but the rest of the resources are shown when
they show up in the portfolio. DR programs need to start earlier than they are needed to
give time to sign customers up for the program.
Darrell Soyars: How are transmission costs built in for each resource like in Montana
where they would be further away?
Avista Corp.2021 Electric IRP Appendices 521
James Gall: It’s complicated, we talked about it briefly earlier today. One avenue is the
Colstrip transmission line where we own rights for a little less than 200 MW. Another is
NorthWestern Energy transmission which could be a wheel. Other resources could be a
wheel request or a capacity build out.
Ben Otto: You said some amount of the gas [generation] is driven by capacity needs.
What is the amount of hours? Is this a capacity shortfall for a few hours or for several
months? What can we see?
James Gall: We looked at 1-hour, multiple hours, etc. When we calculate peak credits,
we run that through an 8760 to get the 5% LOLP. We need resources with long
duration winter generation capability to make sure we have resource adequacy. There
are several hours and they are definitely in the November to February period and during
hours 14 - 18, but I can’t tell you the exact hours. It’s difficult to have a resource
adequate system.
Jennifer Snyder: I’m wondering at the avoided cost in 2022 if on-peak is cheaper than
off-peak, or does it switch partway down.
James Gall: If I’m remembering correctly from the last TAC meeting, the amount of
solar added to the entire system in California, Oregon, Nevada, Arizona and other spots
in the west; the new solar is likely to drive prices in the middle of the day to zero or
negative prices.
Steve Johnson: I have a question or recommendation. Is it possible to add the rate of
return adders to PPAs after the modeling analysis?
James Gall: Yes, it’s possible. I think I’ve heard of 3 to 4 more scenarios today and I
already have 20 more. It can be done, but not sure if they will be done in time to file this
IRP. It depends on whether we’ll have time to fit these all in
Steve Johnson: It might be better to have a portfolio as bid by bidders less the rate of
return adders so we can compare the two.
James Gall: It won’t change the result much, but it will change the avoided cost
Amy Wheeless: Can you remind me of the timeline for next steps?
James Gall: The next meeting is in two to three weeks. We are using the PRS
resources in the current model. There will be a draft IRP out on January 4th. We are
hoping to include new resources if the 2020 Renewable RFP contracts are signed in
time for the draft release in January, but we may need to modify a lot by then.

Avista Corp.2021 Electric IRP Appendices 522
Draft 2021 Preferred Resource Strategy
James Gall, Electric IRP Manager
Technical Advisory Committee Update Meeting
December 16, 2020
DRAFT
Avista Corp.2021 Electric IRP Appendices 523
Safe Harbor Statement
This document contains forward-looking statements. Such statements are subject to a variety of risks,
uncertainties and other factors,most of which are beyond the Company’s control, and many of which could
have a significant impact on the Company’s operations, results of operations and financial condition, and
could cause actual results to differ materially from those anticipated.
For a further discussion of these factors and other important factors,please refer to the Company’s reports
filed with the Securities and Exchange Commission.The forward-looking statements contained in this
document speak only as of the date hereof.The Company undertakes no obligation to update any forward-
looking statement or statements to reflect events or circumstances that occur after the date on which such
statement is made or to reflect the occurrence of unanticipated events.New risks,uncertainties and other
factors emerge from time to time, and it is not possible for management to predict all of such factors,nor
can it assess the impact of each such factor on the Company’s business or the extent to which any such
factor, or combination of factors, may cause actual results to differ materially from those contained in any
forward-looking statement.
DRAFT
2 Avista Corp.2021 Electric IRP Appendices 524
Other Caveats
•Clean Energy Transformation Act (CETA) rules and requirements are not complete.
–This draft PRS uses Avista’s best estimate of known requirements.
•Avista is negotiating with the 2020 renewable Request for Proposals (RFP) shortlist bidders
–This may change the results of the resource if a contract is signed.
•IRP resource options are primarily “new” resource options-RFP will determine whether or
not existing resources can be acquired at similar or lower cost than “new” options.
•Avista may not be able to physically retire or exit certain resources as the IRP PRiSM model
determines because of contract limitations.
•No future state specific resource cost allocation agreement has been made.
•Forward looking rates include non-modeled power supply cost escalating at 2% per year-
–DO NOT TAKE THIS AS A RATE FORECAST
–This is for informational purposes only
DRAFT
3 Avista Corp.2021 Electric IRP Appendices 525
Cumulative Energy Efficiency End Use Results (GWh)
DRAFT
4
WA ID WA ID WA ID
Appliances 0.3 0.1 3.5 0.8 11.6 2.7
Cooling 5.6 0.5 36.8 3.2 53.1 9.1
Electronics 1.1 0.2 14.1 4.8 25.2 9.3
Exterior Lighting 4.1 1.4 24.1 7.8 36.3 14.3
Food Preparation 0.1 0.0 2.2 0.4 5.9 0.9
Interior Lighting 20.3 13.0 100.1 49.3 171.1 89.6
Miscellaneous 1.3 0.3 11.2 2.8 22.9 5.5
Motors 4.9 3.9 35.3 25.6 41.3 28.8
Office Equipment 0.6 0.0 3.3 0.0 5.8 0.0
Process 0.7 0.1 4.1 1.1 4.5 1.4
Refrigeration 8.2 0.3 60.2 2.3 69.4 2.6
Space Heating 12.6 3.6 120.3 30.8 171.1 40.6
Ventilation 5.1 0.7 29.8 5.2 44.8 12.5
Water Heating 4.3 1.5 62.8 8.6 114.2 10.6
Total 69.2 25.6 507.8 142.9 777.1 227.8
2023 2031 2045
Avista Corp.2021 Electric IRP Appendices 526
Cumulative Energy Efficiency Segment Results (GWh)
DRAFT
5
WA ID WA ID WA ID
College 2.1 0.7 11.0 4.2 15.5 7.5
Grocery 6.8 0.2 47.4 1.4 56.3 1.7
Health 2.7 0.9 14.3 5.1 22.8 10.3
Industrial 12.0 8.4 62.5 42.8 91.4 62.9
Large Office 6.5 1.3 43.1 8.8 66.8 16.4
Lodging 1.3 0.6 8.6 2.9 12.5 4.9
Low Income 3.0 1.8 37.3 10.8 53.7 13.5
Miscellaneous 5.1 1.9 35.6 10.7 54.5 19.1
Mobile Home 0.6 0.2 5.5 1.5 8.7 2.3
Multi-Family 0.4 0.2 7.5 1.3 16.3 2.2
Restaurant 2.1 0.2 14.9 1.6 19.8 2.3
Retail 5.6 2.0 35.7 10.3 52.7 17.9
School 2.6 0.1 16.6 0.4 26.5 0.8
Single Family 13.8 5.1 139.6 29.1 234.2 43.7
Small Office 2.2 1.1 16.1 7.4 25.1 13.5
Warehouse 2.3 0.9 12.1 4.7 20.2 8.9
Total 69.2 25.6 507.8 142.9 777.1 227.8
2023 2031 2045
Avista Corp.2021 Electric IRP Appendices 527
31.7 69.2
110.9
159.9
215.1
274.5
336.5
396.9
454.8
507.8
0
100
200
300
400
500
600
2022 2023 2024 2025 2026 2027 2028 2029 2030 2031
Gi
g
a
w
a
t
t

H
o
u
r
s
Selected EE
Pro Rata 10yr
Higher Washington Energy Efficiency Goals
More Aggressive Ramp Rates & Higher Avoided Costs
DRAFT
6
101.6
Biennial Conservation Target
(MWh)
Based on
2021 IRP
Based on
2020 IRP
CPA Pro-Rata Share 101,566 72,338
Distribution & Street Light Efficiency 219 504
EIA Target 101,785 72,842
Decoupling Threshold 5,119 3,642
Total Utility Conservation Goal 106,904 76,484
Excluded Programs (NEEA)-12,896 -14,016
Utility Specific Conservation Goal 94,008 62,468
Decoupling Threshold -5,119 -3,642
EIA Penalty Threshold 88,889 58,826
Avista Corp.2021 Electric IRP Appendices 528
24-yr Levelized Avoided Cost for Energy Efficiency
DRAFT
7
$0
$20
$40
$60
$80
$100
$120
Le
v
e
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i
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d

2
0
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r

$
/
M
W
h
Energy Value
$0
$20
$40
$60
$80
$100
$120
$140
$160
Le
v
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d

2
0
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$
/
k
W
-yr
Capacity Value
$0
$20
$40
$60
$80
$100
$120
$140
Le
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d

2
0
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$
/
M
W
h
Energy Value
$0
$20
$40
$60
$80
$100
$120
$140
Le
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d

2
0
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$
/
k
W
-yr
Capacity Value
Washington Idaho
Avista Corp.2021 Electric IRP Appendices 529
Winter (January) Capacity Position (MW)
Assumes Colstrip 3 & 4 are removed from the portfolio from 2022 to 2041 due to economic results of this study
8
Item 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041
New Load Estimate 1,706 1,712 1,716 1,720 1,725 1,729 1,733 1,738 1,743 1,748 1,753 1,758 1,764 1,770 1,775 1,782 1,790 1,798 1,807 1,816
Planning Margin 273 274 275 275 276 277 277 278 279 280 280 281 282 283 284 285 286 288 289 291
Reserves + Regulation 137 137 136 136 136 137 137 137 137 138 138 138 139 139 139 140 140 141 141 138
Oper. Reserves Hydro Credit -17 -17 -13 -13 -13 -13 -12 -12 -12 -8 -8 -8 -8 -7 -7 -7 -7 -7 -7 -7
Net Requirement 2,099 2,106 2,114 2,119 2,125 2,130 2,135 2,141 2,147 2,158 2,164 2,170 2,177 2,184 2,192 2,200 2,210 2,220 2,231 2,238
Long Term Sales -101 -101 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Long Term Purchases 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Clark Fork River 798 798 798 798 798 798 798 798 798 798 798 798 798 798 798 798 798 798 798 798
Spokane River 163 163 163 153 165 165 165 165 165 165 165 165 165 165 165 165 165 165 165 165
Mid-Columbia Contracts 228 227 147 146 145 144 142 135 135 63 63 64 64 64 64 64 64 64 64 64
PURPA Contracts 78 78 78 78 78 78 78 78 78 78 78 78 78 78 78 78 78 78 78 78
Palouse 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5
Rattlesnake Flats 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 8 0
Adams Nielson Solar 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Placeholder 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Placeholder 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Coyote Springs 2 318 318 318 318 318 318 318 318 318 318 318 318 318 318 318 318 318 318 318 318
Lancaster 283 283 283 283 283 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Colstrip (3)0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Colstrip (4)0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Kettle Falls 47 47 47 47 47 47 47 47 47 47 47 47 47 47 47 47 47 47 47 47
Kettle Falls CT 11 11 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Boulder Park 1-6 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 0
Rathdrum 1 88 88 88 88 88 88 88 88 88 88 88 88 88 88 88 88 88 88 88 88
Rathdrum 2 88 88 88 88 88 88 88 88 88 88 88 88 88 88 88 88 88 88 88 88
Northeast A&B 66 66 66 66 66 66 66 66 66 66 66 66 66 66 0 0 0 0 0 0
Net Position 5 -4 -2 -17 -12 -301 -307 -320 -326 -409 -415 -421 -428 -435 -509 -517 -527 -536 -547 -587
Avista Corp.2021 Electric IRP Appendices 530
Demand Response
Program Washington Idaho
Time of Use Rates 2 MW (2024)2 MW (2024)
Variable Peak Pricing 7 MW (2024)6 MW (2024)
Large C&I Program 25 MW (2027)n/a
DLC Smart Thermostats 7 MW (2031)n/a
Third Party Contracts 14 MW (2032)8 MW (2024)
Behavioral 1 MW (2041)n/a
Total 56 MW 15 MW
Notes:
1) Programs in another state for the benefit of the other state are not modeled
2) Operationally programs are likely for both states regardless of timing
3) 2027 start date is effectively 11/1/2027
DRAFT
9 Avista Corp.2021 Electric IRP Appendices 531
2022-2025 Supply-Side Resource Changes
2022: Economic to exit out of Colstrip 3 & 4 (Both States)
2023: 100 MW of Montana Wind (WA)
2024: 100 MW of Montana Wind (WA)
2025: No Action
NOTE: Renewable RFP may change this strategy
DRAFT
10 Avista Corp.2021 Electric IRP Appendices 532
2026-2029 Supply-Side Resource Changes
2026/27:12 MW Upgrade Kettle Falls (Both States)
283 MW Lancaster CCCT contract ends Nov 2026 (Both States)
126 MW NG SCCT (Both States)
85 MW NG SCCT (ID)
2028: 100 MW Montana Wind (WA)
2029:No Action
NOTE: Renewable RFP may change this strategy
DRAFT
11 Avista Corp.2021 Electric IRP Appendices 533
2030-2033 Supply-Side Resource Changes
2030:No Action
2031:75 MW Hydro Contract Renewal (WA)
2032:No Action
2033:No Action
DRAFT
12 Avista Corp.2021 Electric IRP Appendices 534
2034-2037 Supply-Side Resource Changes
2034:No Action
2035:5 MW Rathdrum CT Upgrade (Both States)
66 MW Northeast Retires (Both States)
2036:87 MW NG SCCT (Both States)
2037:No Action
DRAFT
13 Avista Corp.2021 Electric IRP Appendices 535
2038-2041 Supply-Side Resource Changes
2038:100 MW Solar + 50 MW 4-hour Lithium-ion Battery (Both States)
2039:No Action
2040:No Action
2041:25 MW Boulder Park Retires (Both States)
100 MW Montana Wind (WA)
36 MW Natural Gas Reciprocating Engine (ID)
DRAFT
14 Avista Corp.2021 Electric IRP Appendices 536
Draft Preferred Resource Strategy Selection (MW)
DRAFT
15
Note: Storage resources include 16-Hour Liquid Air Energy Storage and 4-Hour Lithium-ion.
Does not include results of 2020 Renewable RFP.
Nameplate MW 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 Total
Shared System Resource
NG CT - - - - - 126 - - - - - - - - 87 - - - - - - - - - 213
Solar - - - - - - - - - - - - - - - - 100 - - - - - - - 100
Storage Added to Solar - - - - - - - - - - - - - - - - 50 - - - - - - - 50
Wind - - - - - - - - - - - - - - - - - - - - - - - - -
Storage - - - - - - - - - - - - - - - - - - - - - - - - -
Hydrogen - - - - - - - - - - - - - - - - - - - - - - - - -
Other- (Clean Capacity)- - - - - - - - - - - - - - - - - - - - - - - - -
Thermal Upgrade - - - - 12 - - - - - - - - 5 - - - - - - - - - - 17
Hydro - - - - - - - - - - - - - - - - - - - - - - - - -
Washington
NG CT - - - - - - - - - - - - - - - - - - - - - - - - -
Solar - - - - - - - - - - - - - - - - - - - - 117 122 - 149 388
Storage Added to Solar - - - - - - - - - - - - - - - - - - - - 58 61 - 75 194
Wind - 100 100 - - - 100 - - - - - - - - - - - - 100 - - - - 400
Storage - - - - - - - - - - - - - - - - - - - - - - 12 - 12
Hydrogen - - - - - - - - - - - - - - - - - - - - - - - - -
Other- (Clean Capacity)- - - - - - - - - - - - - - - - - - - - - - - - -
Thermal Upgrade - - - - - - - - - - - - - - - - - - - - - - - - -
Hydro - - - - - - - - - 75 - - - - - - - - - - - - - - 75
Idaho
NG CT - - - - - 85 - - - - - - - - - - - - - 36 - - - - 122
Solar - - - - - - - - - - - - - - - - - - - - - - - - -
Storage Added to Solar - - - - - - - - - - - - - - - - - - - - - - - - -
Wind - - - - - - - - - - - - - - - - - - - - - - - - -
Storage - - - - - - - - - - - - - - - - - - - - - - - 10 10
Hydrogen - - - - - - - - - - - - - - - - - - - - - - - - -
Other- (Clean Capacity)- - - - - - - - - - - - - - - - - - - - - - - - -
Thermal Upgrade - - - - - - - - - - - - - - - - - - - - - - - - -
Hydro - - - - - - - - - - - - - - - - - - - - - - - - -
Avista Corp.2021 Electric IRP Appendices 537
Draft State Total Resource Selection (MW)
DRAFT
Nameplate MW 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 Total
Washington
NG CT - - - - - 83 - - - - - - - - 57 - - - - - - - - - 140
Solar - - - - - - - - - - - - - - - - 66 - - - 117 122 - 149 454
Storage Added to Solar - - - - - - - - - - - - - - - - 33 - - - 58 61 - 75 227
Wind - 100 100 - - - 100 - - - - - - - - - - - - 100 - - - - 400
Storage - - - - - - - - - - - - - - - - - - - - - - 12 - 12
Hydrogen - - - - - - - - - - - - - - - - - - - - - - - - -
Other- (Clean Capacity)- - - - - - - - - - - - - - - - - - - - - - - - -
Thermal Upgrade - - - - 8 - - - - - - - - 3 - - - - - - - - - - 11
Hydro - - - - - - - - - 75 - - - - - - - - - - - - - - 75
Idaho
NG CT - - - - - 128 - - - - - - - - 30 - - - - 36 - - - - 195
Solar - - - - - - - - - - - - - - - - 34 - - - - - - - 34
Storage Added to Solar - - - - - - - - - - - - - - - - 17 - - - - - - - 17
Wind - - - - - - - - - - - - - - - - - - - - - - - - -
Storage - - - - - - - - - - - - - - - - - - - - - - - 10 10
Hydrogen - - - - - - - - - - - - - - - - - - - - - - - - -
Other- (Clean Capacity)- - - - - - - - - - - - - - - - - - - - - - - - -
Thermal Upgrade - - - - 4 - - - - - - - - 2 - - - - - - - - - - 6
Hydro - - - - - - - - - - - - - - - - - - - - - - - - -
16 Avista Corp.2021 Electric IRP Appendices 538
Clean Energy Shares (aMW)
System Clean Resource Percentage
2022: 74.8%
2027: 78.3%
2045: 85.5%
Excludes Clean Market Purchases
DRAFT
17
Av
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System
Av
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Washington
Av
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Idaho
Avista Corp.2021 Electric IRP Appendices 539
Annual Average Least Reasonable Cost Rate Forecast
NOTE: Estimated rates only using 2% annual rate increase for non-modeled costs
DRAFT
18
0.000
0.020
0.040
0.060
0.080
0.100
0.120
0.140
0.160
0.180
0.200
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Do
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p
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K
W
h
Avista Corp.2021 Electric IRP Appendices 540
Greenhouse Gas Forecast with Draft PRS
Note: Assumes Colstrip exits the portfolio in 2022
DRAFT
19
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Avista Corp.2021 Electric IRP Appendices 541
New Supply-Side Resource Avoided Costs
DRAFT
20
Year
Flat
($/MWh)
On-Peak
($/MWh)
Off-Peak
($/MWh)
Clean
Energy
Premium
($/MWh)
Capacity
Premium
($/kW-Yr)
20 yr Levelized $25.85 $25.20 $26.72 $14.04 $80.3
24 yr Levelized $27.18 $26.39 $28.22 $14.50 $86.6Avista Corp.2021 Electric IRP Appendices 542
Portfolio Scenario and Market Sensitivity Analysis
James Gall, Electric IRP Manager
Technical Advisory Committee Update Meeting
December 16, 2020
DRAFT
Avista Corp.2021 Electric IRP Appendices 543
Safe Harbor Statement
This document contains forward-looking statements. Such statements are subject to a variety of risks,
uncertainties and other factors,most of which are beyond the Company’s control, and many of which could
have a significant impact on the Company’s operations, results of operations and financial condition, and
could cause actual results to differ materially from those anticipated.
For a further discussion of these factors and other important factors,please refer to the Company’s reports
filed with the Securities and Exchange Commission.The forward-looking statements contained in this
document speak only as of the date hereof.The Company undertakes no obligation to update any forward-
looking statement or statements to reflect events or circumstances that occur after the date on which such
statement is made or to reflect the occurrence of unanticipated events.New risks,uncertainties and other
factors emerge from time to time, and it is not possible for management to predict all of such factors,nor
can it assess the impact of each such factor on the Company’s business or the extent to which any such
factor, or combination of factors, may cause actual results to differ materially from those contained in any
forward-looking statement.
DRAFT
2 Avista Corp.2021 Electric IRP Appendices 544
Scenario Descriptions
1.Least Reasonable Cost Strategy: Includes all requirements
2.Baseline Portfolio 1: Excludes CETA’s 2030 and 2045 goals
–Used for incremental cost calculation
3.Baseline Portfolio 2: Baseline Portfolio 1 + removal of SCC
–Energy Efficiency held constant from LCS
4.Baseline Portfolio 3: Baseline Portfolio 2 + removal of capacity constraints
–Energy Efficiency held constant from LCS
5.Clean Resource Plan (2027)
–Add constraint to meet or exceed 100% of all retail sales with clean energy
6.Clean Resource Plan (2045)
–Add constraint to meet or exceed 100% of all retail sales with clean energy
–All thermal resources must exit by 2044
–No new thermal resources
7.Social Cost of Carbon applied to Idaho
–Includes SCC as cost adder to generation and savings for EE using same method as Washington
State
DRAFT
3 Avista Corp.2021 Electric IRP Appendices 545
Scenario Descriptions (Continued)
8.Least Cost Plan-with low load growth
–Loads decline by 0.11% per year vs. +0.31% per year
9.Least Cost plan-with high load growth
–Loads increase by 0.73% per year vs. +0.31% per year
10.Least Cost Plan-w/ Northwest Resource Adequacy Market Peak Credits
–Use Regional Planning Margin of 12% & Regional Peak Credits
11.Heating Electrification Scenario 1
–WA customers electrify with exiting heating technology
12.Heating Electrification Scenario 2
–WA customers electrify using hybrid systems (i.e. NG furnace & electric HP & HPWH)
13.Heating Electrification Scenario 3
–WA customer electrify using technology without COP rates not falling below freezing temperatures
14.Least Cost Plan-with 2 time SCC prices
–Double of Social Cost of Carbon charge for Washington Only
DRAFT
4 Avista Corp.2021 Electric IRP Appendices 546
Scenario Descriptions (Continued)
15.Colstrip serves Idaho customers through 2025
–Colstrip obligated to run through 2025 in both states
16.Colstrip serves Idaho customers through 2035
–Colstrip obligated to run though 2035 for Idaho
17.Colstrip serves Idaho customers through 2045
–Colstrip obligated to run through 2045 for Idaho
18.CETA delivers by the hour
–Approximates resource selection requiring clean energy delivery by hour
19.Social Cost of Carbon applied to net purchases/sales
–Includes SCC planning penalty on the net of market purchases/sales (2020 IRP assumption)
20.Average Market Emissions Rate applied to Energy Efficiency SCC
–Replaces incremental market emissions for average market emissions for SCC on EE (2020 IRP
assumption)
DRAFT
5 Avista Corp.2021 Electric IRP Appendices 547
Scenario Descriptions (Continued)
1a. Least Cost Plan with Climate Shift
–Re-optimized PRS with alternate load and generation forecast assuming warming temperatures
1b. Least Cost Plan with Social Cost of Carbon “Tax”
–Re-optimized PRS with market carbon tax on fossil fuel generation
6 Avista Corp.2021 Electric IRP Appendices 548
Scenario & Sensitivity List
Number Scenario Expected
Case
High N.
Gas
Price
Low N.
Gas
Price
Social
Cost
Carbon
Tax
Climate
Shift
1 Preferred Resource Strategy X X X X
2 Baseline Portfolio 1 (No CETA renewable targets)X
3 Baseline Portfolio 2 (No CETA renewable targets/SCC)X X X X
4 Baseline Portfolio 3 (No Capacity Constraints)X
5 Clean Resource Plan (100% Portfolio net clean by 2027)X X X X
6 Clean Resource Plan (100% Portfolio clean by 2045)X X X X
7 Social Cost of Carbon applied to Idaho X
8 Least Cost Plan-w/ low load growth X
9 Least Cost Plan-w/ low load growth X
10 Least Cost Plan-w/ Northwest Resource Adequacy Market Peak Credits X
11 Heating Electrification Scenario 1 X
12 Heating Electrification Scenario 2 X
13 Heating Electrification Scenario 3 X
14 Least Cost Plan-w/ 2x SCC prices X
15 Colstrip serves Idaho customers through 2025 X X X X
16 Colstrip serves Idaho customers through 2035 X X X X
17 Colstrip serves Idaho customers through 2045 X X X X
18 CETA deliver each hour X
19 Social Cost of Carbon applied to net Purchases/Sales X
20 Avg market emissions rate applied to SCC for EE X
1a Least Cost Plan-w/ climate shift X
1b Least Cost Plan-w/ SCC “Tax”X7Avista Corp.2021 Electric IRP Appendices 549
Scenario Cumulative Resource Selection
DRAFT
8
1-
Preferred
Resource
Strategy
2- Baseline
1
3- Baseline
2
4- Baseline
3
5- Clean
Resource
Plan (2027)
6- Clean
Resource
Plan (2045)
7- SCC
Idaho
8- Low
Load
Forecast
9- High
Load
Forecast
10- RA
Market
11-
Electrificati
on 1
12-
Electrificati
on 2
13-
Electrificati
on 3
14- 2x SCC 15- Colstrip
Exit 2025
16- Colstrip
Exit 2035
17- Colstrip
Exit 2045
18- Clean
Energy
Delivered
Each Hour
19- SCC on
Net P/S
20- Use
Avg Mrkt
for EE SCC
1a- LCP w/
Climate
Shift
1b- LCP w/
SCC
Shared System Resource
NG CT 213 132 132 0 84 0 223 65 84 88 84 84 84 196 213 125 211 126 250 86 172 247
Solar 100 0 0 0 549 899 0 104 0 100 0 0 0 100 100 100 100 100 0 101 - 411
Storage Added to Solar 50 0 0 0 275 450 0 52 0 50 0 0 0 50 50 50 50 50 0 50 - 206
Wind 0 0 0 0 0 200 0 0 0 0 0 0 0 0 0 0 0 0 0 0 - 323
Storage 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 - 9
Hydrogen 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 - -
Other- (Clean Capacity)0 0 0 0 20 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 - -
Thermal Upgrade 17 17 17 0 17 12 17 17 21 17 17 17 17 17 17 17 17 17 17 17 21 17
Hydro 0 75 75 0 0 75 75 0 0 0 0 0 0 0 0 0 0 0 0 0 - 75
Washington
NG CT 0 144 147 0 48 0 0 48 92 49 200 159 200 0 0 51 0 0 0 84 - -
Solar 388 0 0 0 26 0 496 131 493 552 277 536 425 379 388 388 387 788 120 389 372 -
Storage Added to Solar 194 0 0 0 0 0 248 0 246 94 138 268 212 189 194 194 194 369 60 194 111 -
Wind 400 0 0 0 400 400 400 400 514 300 894 628 796 400 400 400 400 700 616 400 400 350
Storage 12 68 68 0 24 312 22 0 113 0 486 279 474 23 12 22 13 512 22 12 21 865
Hydrogen 0 0 0 0 0 75 0 0 0 0 397 84 199 0 0 0 0 0 0 0 - -
Other- (Clean Capacity)0 0 0 0 0 96 0 0 20 0 20 20 20 0 0 0 0 100 0 0 - -
Thermal Upgrade 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 - -
Hydro 75 0 0 0 75 0 0 75 75 75 75 75 75 75 75 75 75 75 75 75 75 -
DR Capability 56 104 97 3 56 104 57 49 49 34 49 49 49 57 56 56 56 56 49 56 49 35
EE- Winter Capacity 86 85 86 86 89 92 86 86 86 85 118 114 114 88 86 86 86 86 85 81 86 87
EE- Summer Capacity 92 92 92 92 100 101 93 92 92 96 121 97 99 94 92 92 92 92 92 79 97 115
Idaho
NG CT 122 97 97 0 148 0 57 135 194 148 91 132 91 127 122 165 73 158 92 169 120 -
Solar 0 0 0 0 200 250 0 0 0 0 0 0 0 0 0 0 0 0 0 0 5 -
Storage Added to Solar 0 0 0 0 0 50 0 0 0 0 0 0 0 0 0 0 0 0 0 0 - -
Wind 0 0 0 0 194 200 0 0 0 0 0 0 0 0 0 0 0 0 0 0 - 327
Storage 10 20 33 0 0 20 10 0 28 49 26 16 26 29 10 24 24 10 34 10 - 176
Hydrogen 0 50 50 0 0 232 50 0 50 0 100 50 100 0 0 0 0 0 0 0 - -
Other- (Clean Capacity)0 0 0 0 0 20 0 0 0 0 0 0 0 0 0 0 0 0 0 0 - -
Thermal Upgrade 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 - -
Hydro 0 0 0 0 0 68 0 0 0 0 0 0 0 0 0 0 0 0 0 0 - -
DR Capability 15 18 20 2 16 20 19 8 16 19 19 18 19 18 15 9 9 15 15 19 16 8
EE- Winter Capacity 24 29 24 24 31 37 38 24 24 24 32 29 32 25 24 22 21 24 29 25 24 39
EE- Summer Capacity 13 13 13 13 26 30 35 13 13 20 15 13 15 13 13 11 11 13 13 13 35 53
Avista Corp.2021 Electric IRP Appendices 550
Existing Resource “Exits”
Note:
Assumes each plant is available through December 31st of the final year;
Exception: Lancaster PPA expires Oct 2026.
Dash indicates no plant exit in the study
DRAFT
9
1-
Preferred
Resource
Strategy
2-
Baseline
1
3-
Baseline
2
4-
Baseline
3
5- Clean
Resource
Plan
(2027)
6- Clean
Resource
Plan
(2045)
7- SCC
Idaho
8- Low
Load
Forecast
9- High
Load
Forecast
10- RA
Market
11-
Electrifica
tion 1
12-
Electrifica
tion 2
13-
Electrifica
tion 3
14- 2x
SCC
15-
Colstrip
Exit 2025
16-
Colstrip
Exit 2035
17-
Colstrip
Exit 2045
18- Clean
Energy
Delivered
Each
Hour
19- SCC
on Net
P/S
20- Use
Avg Mrkt
for EE
SCC
1a- LCP
w/
Climate
Shift
1b- LCP
w/ SCC
Coyote Springs 2 - - - - -2044 - - - - - - - - - - - - - - - -
Lancaster 2026 2026 2026 2026 2026 2026 2026 2026 2026 2026 2026 2026 2026 2026 2026 2026 2026 2026 2026 2026 2026 2026
Colstrip (3)2021 2021 2021 2021 2021 2044 2021 2021 2021 2021 2021 2021 2021 2021 2025 2035 -2021 2021 2021 2021 2021
Colstrip (4)2021 2021 2021 2021 2021 2021 2021 2021 2022 2021 2021 2021 2021 2021 2025 2035 -2021 2021 2021 2021 2021
Kettle Falls - - - - - - - - - - - - - - - - - - - - - -
Kettle Falls CT - - - - -2044 - - - - - - - - - - - - - - - -
Boulder Park 1-6 2040 2040 2040 2040 2040 2040 2040 2040 2040 2037 2040 2040 2040 2040 2040 2040 2040 2040 2039 2040 2040 2040
Rathdrum 1 - - - - -2044 - - - - - - - - - - - - - - - -
Rathdrum 2 - - - - -2044 - - - - - - - - - - - - - - - -
Northeast A&B 2035 2035 2035 2035 2035 2035 2035 2035 2035 2035 2035 2035 2035 2035 2035 2035 2035 2035 2035 2035 2035 2035
Avista Corp.2021 Electric IRP Appendices 551
2022-45 Levelized Revenue Requirement Delta from PRS
DRAFT
10 Avista Corp.2021 Electric IRP Appendices 552
Avg Energy Rate Delta from PRS (2030 & 2045)
DRAFT
11
Washington Idaho
Avista Corp.2021 Electric IRP Appendices 553
Annual Greenhouse Gas Emission
Avista Dispatched GHG Emissions
DRAFT
12 Avista Corp.2021 Electric IRP Appendices 554
Cost vs. GHG Tradeoffs
Change in Levelized Cost vs. Change in Levelized Net Emissions
DRAFT
13
-$80
-$60
-$40
-$20
$0
$20
$40
$60
$80
$100
$120
$140
-0.3 -0.2 -0.1 0 0.1 0.2 0.3 0.4 0.5
Ch
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Change in Levelized GHG Emissions from LRCS (MMT)
Avista Corp.2021 Electric IRP Appendices 555
2030 Risk Analysis
Measures 2030 standard deviation of “modeled” power cost compared to levelized cost
DRAFT
14 Note: PPA cost “fixed” for this analysis-meaning the PPA cost does not change with changes in delivered energy
$0
$10
$20
$30
$40
$50
$60
$1,040 $1,060 $1,080 $1,100 $1,120 $1,140 $1,160 $1,180 $1,200 $1,220 $1,240 $1,260
20
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)
2022-2044 Levelized Revenue Requirement (Millions)
Avista Corp.2021 Electric IRP Appendices 556
2045 Upper Tail Risk Analysis
95th percentile power cost minus mean power cost compared to levelized cost
DRAFT
15 Note: PPA cost “fixed” for this analysis-meaning the PPA cost does not change with changes in delivered energy
$0
$50
$100
$150
$200
$250
$300
$1,040 $1,060 $1,080 $1,100 $1,120 $1,140 $1,160 $1,180 $1,200 $1,220 $1,240 $1,260
20
4
5

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2022-2044 Levelized Revenue Requirement (Millions)
Avista Corp.2021 Electric IRP Appendices 557
Portfolio Results Summary
16
Scenario WA- PVRR
($ Mill)
ID-PVRR ($
Mill)
WA 2030
Rate
($/kWh)
WA 2045
Rate
($/kWh)
ID 2030
Rate
($/kWh)
ID 2045
Rate
($/kWh)
2030 Stdev
($ Mill)
2045 Stdev
($ Mill)
2045 Tail
Risk ($ Mill)
2045 GHG
Emissions
(MT)
Avista Corp.2021 Electric IRP Appendices 558
Reoptimized Portfolios with Market Changes
•Studies how PRS would change given fundamental shift in energy
planning future.
•Stochastics are not modeled
–1a: Climate Shift
–1b: SCC Tax
Deterministic Scenario WA- PVRR
($ Mill)
ID-PVRR ($
Mill)
WA 2030
Rate
($/kWh)
WA 2045
Rate
($/kWh)
ID 2030
Rate
($/kWh)
ID 2045
Rate
($/kWh)
2045 GHG
Emissions
(MT)
17 Avista Corp.2021 Electric IRP Appendices 559
Sensitivity Comparative Analysis
Portfolio High NG
Prices
Low NG
Prices
SCC High NG
Prices
Low NG
Prices
SCC
1- Preferred Resource Strategy 6.1% -2.1% 5.5%-18% 16% -18%
3- Baseline 2 8.8% -3.0% 11.5%-18% 17% -18%
5- Clean Resource Plan (2027)3.6% -1.3% -0.1%-18% 16% -18%
6- Clean Resource Plan (2045)2.6% -0.9% 0.0%-12% 6% -25%
15- Colstrip Exit 2025 5.7% -2.0% 5.7%-14% 11% -23%
16- Colstrip Exit 2035 5.2% -1.8% 6.6%-11% 5% -30%
17- Colstrip Exit 2045 4.8% -1.7% 7.3%-10% 3% -31%
Portfolio High NG
Prices
Low NG
Prices
SCC High NG
Prices
Low NG
Prices
SCC
3- Baseline 2 1% -3% 4%1% 1% 1%
5- Clean Resource Plan (2027)1% 5% -2%-1% -2% -1%
6- Clean Resource Plan (2045)2% 7% 0%33% 13% 13%
15- Colstrip Exit 2025 0% 0% 0%23% 13% 11%
16- Colstrip Exit 2035 0% 1% 1%59% 32% 25%
17- Colstrip Exit 2045 -1% 1% 2%75% 41% 34%
Change in PVRR vs Expected Case Change in Levelized GHG MT vs
Expected Case
Change in PVRR vs PRS Change in Levelized GHG MT vs PRS
18 Avista Corp.2021 Electric IRP Appendices 560
2021 Electric IRP TAC 4.5 Meeting Notes, December 16, 2020
Shawn Bonfield, Lori Hermanson, Kein Keyt, Mike Morrison, Morgan Brummund, Dean
Sprattt, Amanda Ghering, Grant Forsyth, Clint Kalich, James McDougall, Jason
Thackston, Scott Kinney, Logan Callen, Corey Dahl, Dainee Gibson-Webb, Fred
Heutte, Jared Hansen, Ian McGetrick, John Chatburn, Jorgen Rasmussen, Katie Ware,
Michael Eldred, Mike Morrison, Rachelle Farnsworth, Shay Bauman, Jennifer
SnyderShelly McNeilly, Ricky Davis, Marrisa Warren, Joni Bosh, and Katie Pagan.
Notes in italics are the short resonses from the presenter.
Mike Morrison via chat: Please explain how Cumulative Energy Efficiency is
determined. (The Cumulative Part.)
James Gall: It is the total amount acquired to date of the prorata period.
Mike Morrison: What about retirements?
James Gall: The AEG forecast includes those retirements, so it’s included this in.
Energy efficiency trails off at the end of 2045 due to this.
Mike Morrison: What would be relevant are the cumulative amounts of what’s still in
place [for energy efficiency].
James Gall: I think that’s what is included here, but we should confirm with AEG.
Mike Morrison: What about capacity savings?
James Gall: Coming up.
Mike Morrison: Were the planning margin forecasts computed assuming increased
renewable use?

James Gall: Two ways to address that issue. Can either increase your planning margin
or decrease the peak credit on renewables. We chose to decrease the renewable peak credit.

Fred Huette: On DR, can you speak to water heaters, heat pumps, etc., and what it
looks like in terms of cost effectiveness?

James Gall: I was surprised that one wasn’t picked up. I would imagine that when we
do our plan in 4 years, it’ll probably get selected. I think it was on the margin for this
IRP.

Fred Heutte: We will be recommending to move on this anyway.

Jennifer Snyder: A pilot CTA – 2045 program would likely make sense in the CEIP.
Yes.
Avista Corp.2021 Electric IRP Appendices 561

Fred Heutte: You may already know this, but today in the Spokesman was a great
headline regarding Rattlesnake Flat Wind going online – congratulations.

James Gall: Thank you!

Mike Morrison: A couple of slides ago, planning margin reserves and regulation for
new renewable resources. Can you walk through the Montana wind and what it was
before and after you derate it?

James Gall: For 35% capacity credit at 200 MW, there is 70 MW of reliable energy. We exchange a gas CT for wind and then determine at what level we reach the LOLP of
5%. We then compare that amount of wind with the gas CT to get to the 5% LOLP. We
had to discount wind by 35% to get to the same capacity. It declines as you get more
wind.

Mike Morrison: What about diversity of wind farms located all over?

James Gall: In Montana there is a large probablity of wind when it’s cold in Spokane,
unlike northwest wind. Adding more wind decreases the capacity peak credit. Wind diversity helps with regulation, but there is still a capacity issue.

Mike Morrison: Your critical need seems to be in the winter. Why are you focusing on
winter?

James Gall: Sometimes those events aren’t Avista-driven. There was one summer event in 2004. Winter is really our concern.

Mike Morrison: I think your IRP mentions others. Summer curtailments – you’ve had
three events in the summer.

Fred Heutte: Montana wind capacity factor is 35-40%, but you’re using ELCC to arrive
at 35% peak capacity credit under stress conditions, is that correct? Yes. It’s a big state
and that doesn’t seem out of range. Have you considered matching wind with storage?

James Gall: We have not modeled matching wind with storage together, even though we have modeled them separately. We have modeled solar plus storage. In our last
renewable RFP, we only had one combined solar plus storage proposal so we may look
at this for the next IRP. It may be more reduction or integration cost, we will look at this
in the next IRP.

Fred Heutte: You’re mostly hydro so you have more flexibility versus a stand alone
resource and some opportunities.
Avista Corp.2021 Electric IRP Appendices 562

James Gall: Potentially

Fred Heutte: Clean energy premium would be added to the first three columns for
Washington?

James Gall: Yes, for example a new flat PPA would get both the clean energy premium
and a capacity premium based on the profile of the resource.

Fred Heutte: What will happen with the off-peak and on-peak price flips?

James Gall: With all of the new solar in California and across the west, this causes the
prices to flip during the day with the result being no market to sell into during our
daytime peak. We have a super-peak price too in the evening peak.

Fred Heutte: On slide 15, in 2027 you have a CT for Washington and Idaho. How is this one allocated to the states?

James Gall: It could be either. We tried to illustrate the driver for the resource need.

Jennifer Snyder: Baseline portfolio 2, you ran it four times.

James Gall: We used that scenario with different market variables to show how that
portfolio would do in a high or low gas price market, etc. This helps us understand the
limitations of that portfolio in different market futures.

Fred Heutte: What is the purpose of portfolio 18?

James Gall: If the commisssion decides by 2030 for clean energy needing to be
delivered to load by hour. This case was done to determine our best guess of how to do that. It shows the cost impacts of that change from matching generation to load by the hour.

Fred Heutte: Our understanding is it is not hour by hour, but it is interesting to look at.

Jennifer Snyder: What is the cost difference in Washington based on differing exit
dates for Colstrip from 2022 to 2025?

James Gall: Because we have a shared system, the resource choices Idaho makes
may impact Washington. Idaho may be long and may decide not to participate in some of the resources. That is why the costs could be lower or higher in Washington. It depends on if they stand alone on a resource choice versus splitting the costs with
Idaho customers.
Avista Corp.2021 Electric IRP Appendices 563

Fred Heutte: What are the minimum machine requirements to run PRiSM?

James Gall: There are not any machine minimums, but software requirements. Must
have a license and a modern machine with 4-8 gigs of RAM to probably solve in about 8 hours. Could get that down to minutes or to an hour with a better machine.

Fred Heutte: That gives a sense of the feasability so thanks for doing this.

Fred Heutte: I would like to try a scenario with a lot of batteries, DR, etc. and see what
it takes to max out the system. Run one scenario with high performance, flexible and clean resources.

Mike Morrison: Could you explain ARAM?

James Gall: After the Janaury 4, 2021 filing we could schedule a one hour meeting to
go through that.
Avista Corp.2021 Electric IRP Appendices 564

2021 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 5 Agenda
Thursday, January 21, 2021 Virtual Meeting
Topic Time Staff
Introductions 9:00 Lyons
Review Draft 2021 IRP 9:15 Lyons

Draft Resource Plans and Scenarios 9:45 Gall

2021 IRP Action Items 10:45 Lyons

Lunch 11:30

ARAM Model Overview 12:30 Gall

Break 1:30

Clean Energy Implementation Plan and
Clean Energy Action Plan Discussion 1:45 Gall/Lyons

Draft IRP Comments from TAC 2:15

Adjourn 3:30 .........................................................................................................................................
 Join Skype Meeting Trouble Joining? Try Skype Web App Join by phone [phone] (Spokane) English (United States) Find a local number Conference ID: 67816
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Avista Corp.2021 Electric IRP Appendices 565
2021 Electric IRP
TAC Introductions and IRP Process Updates
John Lyons, Ph.D.
Fifth Technical Advisory Committee Meeting
January 21, 2021
Avista Corp.2021 Electric IRP Appendices 566
Updated TAC Meeting Guidelines
•IRP team working remotely through the rest of this IRP, but still
available by email and phone for questions and comments
•Some processes are taking longer remotely
•Virtual IRP meetings until able to hold large group meetings again
•Joint Avista IRP page for gas and electric:
https://www.myavista.com/about-us/integrated-resource-planning
–TAC presentations
–Documentation for IRP work
–Past IRPs
2 Avista Corp.2021 Electric IRP Appendices 567
Virtual TAC Meeting Reminders
•Please mute mics unless speaking or asking a question
•Use the Skype chat box to write questions or comments
or let us know you would like to say something
•Respect the pause
•Please try not to speak over the presenter or a speaker
who is voicing a question or thought
•Remember to state your name before speaking for the
note taker
•This is a public advisory meeting –presentations and
comments will be recorded and documented
3 Avista Corp.2021 Electric IRP Appendices 568
Integrated Resource Planning
•Required by Idaho and Washington* every other year
•Guides resource strategy over the next twenty + years
•Current and projected load & resource position
•Resource strategies under different future policies
–Resource choices
–Conservation measures and programs
–Transmission and distribution integration for electric
–Gas and electric market price forecasts
•Scenarios for uncertain future events and issues
•Key dates for modeling and IRP development are
available in the Work Plans
4 Avista Corp.2021 Electric IRP Appendices 569
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
–Help with soliciting new members
•Open forum while balancing need to get through all of the topics
•Welcome requests for studies or different assumptions.
–August 1, 2020 was the electric study request deadline for the 2021
IRP, new requests will be taken up in the 2023 IRP
•Planning team is available by email or phone for questions or
comments outside of TAC meetings
5 Avista Corp.2021 Electric IRP Appendices 570
2021 Electric IRP TAC Schedule
•TAC 1: Thursday, June 18, 2020
•TAC 2: Thursday, August 6, 2020 (Joint with Natural Gas TAC)
•TAC 2.5: Tuesday, August 18, 2020 Economic and Load Forecast
•TAC 3: Tuesday, September 29, 2020
•TAC 4: Tuesday, November 17, 2020
•TAC 4.5: Wednesday, December 16, 2020 –PRS & Scenarios
•TAC 5: Thursday, January 21, 2021
•Public Outreach Meeting: February 2021 (Do we still need this?)
•WUTC Public IRP Open Meeting: February 23, 2021
•TAC agendas, presentations, meeting minutes and IRP files
available at:
https://myavista.com/about-us/integrated-resource-planning
6 Avista Corp.2021 Electric IRP Appendices 571
IRP Documentation Available
•Draft 2021 IRP
•Avista Resource Emissions Summary
•Load Forecast
•CPA Measures
•Avista 2020 Electric CPA –Summary and
IRP Inputs
•Home Electrification Conversions
•Named Populations
•Natural Gas Prices
•Social Cost of Carbon
•High and Low Natural Gas Prices
•Market Modeling Results
•Climate Shift Scenario Inputs
•2021 IRP New Resource Options
•1 – Preferred Resource Strategy
•2 –Baseline 1 No CETA Renewable
Targets
•3 –Baseline 2 No CETA Renewable
Targets/SCC7
•4 – Baseline Portfolio 3 No Additions
•5 –Clean Resource Plan (2027)
•6 –Clean Resource Plan (2045)
•7 –Social Cost of Carbon Idaho
•8 & 9 – High and Low Load Forecasts
•10 –RA Program
•11 – 13 – Electrification 1, 2 & 3
•14 –2x SCC
•15 –Colstrip Serves Idaho through 2025
•16 –Colstrip Serves Idaho through 2035
•17 –Colstrip Serves Idaho through 2045
•18 –Clean Energy Delivery by Hour
•19 – SCC on Net Power Supply
•20 – Use Average Market for EE & SCC
•PRiSM Draft Results (12/7/20)
Avista Corp.2021 Electric IRP Appendices 572
Process Updates
•January 4, 2021 –draft IRP released to TAC
•February 23, 2021 –WUTC hearing about draft IRP
–Discussion about need for another public outreach meeting
•March 1, 2021 –Comments from TAC on draft IRP due
•March 2021 –final IRP editing, printing and compilation of Appendices
–Inclusion of 2020 Renewable RFP results?
•April 1, 2021 –publication and submission of the 2021 Electric IRP with the
Idaho and Washington Commissions
–IRP and appendices will also be available on the Avista web site
•Commissions will schedule hearings and accept comments about 2021 IRP
8 Avista Corp.2021 Electric IRP Appendices 573
Today’s TAC Agenda
9:00 Introductions, Lyons
9:15 Review Draft 2021 IRP, Lyons
9:45 Draft Resource Plans and Scenarios, Gall
10:45 2021 IRP Action Items, Lyons
11:30 Lunch
12:30 ARAM Model Overview, Gall
1:30 Break
1:45 Clean Energy Implementation Plan and Clean Energy
Action Plan Discussion, Gall and Lyons
2:15 Draft IRP Comments from TAC
3:30 Adjourn
9 Avista Corp.2021 Electric IRP Appendices 574
2021 Electric IRP
Document Overview
John Lyons, Ph.D.
Fifth Technical Advisory Committee Meeting
January 21, 2021
Avista Corp.2021 Electric IRP Appendices 575
2021 Electric IRP Chapters
1.Executive Summary
2.Introduction, IRP Requirements, and Stakeholder Involvement
3.Economic and Load Forecast
4.Existing Supply Resources
5.Energy Efficiency
6.Demand Response
7.Long-Term Position
8.Transmission & Distribution Planning
9.Supply-Side Resource Options
10.Market Analysis
11.Preferred Resource Strategy
12.Portfolio Scenarios
13.Energy Equity
14.Action Plan
15.Clean Energy Action Plan
2 Avista Corp.2021 Electric IRP Appendices 576
2021 Electric IRP Chapters 1 –3
•Chapter 1: Executive Summary
–High level summary of 2021 IRP and PRS
•Chapter 2: Introduction, IRP Requirements, Stakeholder
Involvement
–TAC overview and rules guiding IRP development
–Major changes from the 2017 and 2020 IRPs
•Chapter 3: Economic and Load Forecast
–Economic conditions in Avista’s service territory
–Avista’s energy and peak forecasts
–Load forecast scenarios
3 Avista Corp.2021 Electric IRP Appendices 577
2021 Electric IRP Chapters Ch. 4 –6
•Chapter 4: Existing Supply Resources
–Avista’s resources
–Contractual resources and obligations
–Avista’s natural gas pipeline rights overview
•Chapter 5: Energy Efficiency
–Conservation Potential Assessment
–Energy efficiency modeling and selection
•Chapter 6: Demand Response
–Demand response potential study
–Overview of past demand response pilot programs
4 Avista Corp.2021 Electric IRP Appendices 578
2021 Electric IRP Chapters Ch. 7 –8
•Chapter 7: Long-Term Position
–Reliability adequacy and reserve margins
–Resource requirements
–Reserves and flexibility requirements
•Chapter 8: Transmission and Distribution Planning
–Overview of Avista’s Transmission System
–Future Upgrades and Interconnections
–Transmission Construction Costs and Integration
–Merchant Transmission Plan
–Overview of Avista’s Distribution System
–Future Upgrades and Interconnections (includes project
evaluated with DER alternative)
5 Avista Corp.2021 Electric IRP Appendices 579
2021 Electric IRP Chapters Ch. 9 –10
•Chapter 9: Generation and Storage Resource Options
–New resource option costs and operating characteristics
–Potential Avista plant upgrades
•Chapter 10: Market Analysis
–Fuel price forecasts
–Regional resource additions
–Regional greenhouse gas emissions forecast
–Market price forecast
–Scenario analysis
6 Avista Corp.2021 Electric IRP Appendices 580
2021 Electric IRP Chapters Ch. 11 –13
•Chapter 11: Preferred Resource Strategy
–Resource Selection Process
–Preferred Resource Strategy
–Avoided cost
•Chapter 12: Portfolio Scenarios
–Portfolio Scenarios
–Portfolio cost, risk and environmental comparisons
•Chapter 13: Energy Equity
–Vulnerable populations
–Highly impacted communities
–Equity Advisory Group7Avista Corp.2021 Electric IRP Appendices 581
2021 Electric IRP Chapters Ch. 14 –15
•Chapter 14: Action Plan
–Progress made on Action Items from the 2017 and 2020 IRPs
–IRP projects identified for the 2023 IRP
•Chapter 15: Clean Energy Action Plan
–Action items for CETA compliance between this and the 2023
IRPs
8 Avista Corp.2021 Electric IRP Appendices 582
2021 Electric Integrated Resource Plan Overview
James Gall, Electric IRP Manager
Fifth Technical Advisory Meeting, 2021 IRP
January 21, 2021
Avista Corp.2021 Electric IRP Appendices 583
Planning Environment
65% of load
2030/2045 clean energy mandate
Eliminate coal generation by 2025
Greenhouse gas emission penalties
Electrification push
Climate change considerations
Energy Equity
Distributed energy resource planning
35% of load
Least cost planning
Cost allocation
Market effects
State policy on Avista’s resources
2
CS2 Noxon
Colstrip
Avista Corp.2021 Electric IRP Appendices 584
Avista Reliability Needs
•Meet average coldest day’s peak hour load,
required reserves, and a 16% planning margin.
•Maintain 5 percent Loss of Load Probability.
•Regional effort to “pool” resources by creating
resource adequacy market may lower resource
need.
•~300 MW needed Nov-2026 (expiration of
Lancaster PPA)
•Additional 200 MW by 2036
•Aging Infrastructure & state policy pressuring
existing resources to close:
•Colstrip: 2025 (WA)
•Northeast CT: 2035
•Boulder Park: 2040
•Coyote Springs 2 CCCT/Rathdrum CTs ???
•Load growth & changes
•0.3% annual average growth.
•Large potential increases with electrification.
•Climate change might lower winter and increase
summer peak growth. (required study in next IRP)
-
500
1,000
1,500
2,000
2,500
3,000
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Load & Resource Balance
3 Avista Corp.2021 Electric IRP Appendices 585
Washington Clean Energy
Requirements
Non-Hydro Transfer Limit Hydro Transfer Limit
Total Existing Resources (Share)Retail Sales
Proposal Compliance Target
•Avista must create glidepath to 2030 clean
energy requirements.
•By 2030, 100% of “net” Washington retail
sales must “use” clean energy.
•20% can be met with unbundled RECs.
•might require real-time clean energy delivery.
•Resource Allocation
•Washington customers “buy” Idaho clean
energy share.
•Assumes Idaho’s wind/biomass may be sold
to WA without limitation.
•Assumes Idaho’s hydro purchases limited to
20% of sales beginning in 2030, then
declining.
•By 2045, 100% of Washington sales must
be served with clean energy.
•May require real-time clean energy delivery.
Washington Retail Sales &
Clean Resource Balance
4 Avista Corp.2021 Electric IRP Appendices 586
Avista’s Clean Energy Targets
•In 2022, Avista generates clean energy
equal to 75% of retail sales.
•To meet 100% clean energy by 2027,
Avista must acquire ~320 aMW.
•800-1,000 MW of wind or 1,800 MW solar
(DC).
•Increases to over 510 aMW by 2045.
•Driven by load growth and expiring
contracts
•Avista goal is 100% real-time clean
energy delivery by 2045.
•Requires substantial investments in
energy storage to meet winter loads.
•Electrification of space & water heating
compound these issues.
Av
e
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a
g
e

M
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a
w
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System Annual Average
Sales & Clean Resource Balance
5 Avista Corp.2021 Electric IRP Appendices 587
Resource Options
Clean Resources
Wind
Solar
Biomass
Hydro
Geothermal
Nuclear
Fossil Fuel Resources
Natural gas peaker
Natural gas baseload
Coal (retention)
Customer generation
Demand Resources
Energy efficiency
Conservation
Load control
Rate programs
Fuel switching
Co-generation
Storage
Pumped hydro
Lithium-ion batteries
Liquid air energy storage
Flow batteries
Hydrogen
•Multiple factors drive resource
selection
•Cost or price
•Clean vs. fossil fuel
•Capacity value or “peak credit”
•Storage vs. energy production
•Location
•Availability (new vs. existing)
•Resource retirements
•Future capital investment
•Operating & maintenance cost/availability
•Fuel availability
•Carbon pricing risk
6 Resources in italics were not directly modeled for this IRP
Avista Corp.2021 Electric IRP Appendices 588
IRP’s Preferred Resource
Strategy -Supply Resources Resource Type Year State Capability
(MW)
Colstrip 2021 System (222)
Montana wind 2023 WA 100
Montana wind 2024 WA 100
Lancaster 2026 System (257)
Kettle Falls upgrade 2026 System 12
Natural gas peaker 2027 ID 85
Natural gas peaker 2027 System 126
Montana wind 2028 WA 100
NW Hydro Slice 2031 WA 75
Rathdrum CT upgrade 2035 System 5
Northeast 2035 System (54)
Natural gas peaker 2036 System 87
Solar w/ storage 2038 System 100
4-hr storage for solar 2038 System 50
Boulder Park 2040 System (25)
Natural gas peaker 2041 ID 36
Montana wind 2041 WA 100
Solar w/ storage 2042-2043 WA 239
4-hr storage for solar 2042-2043 WA 119
Liquid air energy storage 2044 WA 12
Liquid air energy storage 2045 ID 10
Solar w/ storage 2045 WA 149
4-hr storage for solar 2045 WA 75
Supply-side resource net total (MW)1,024
Supply-side resource total additions (MW)1,581
•IRP focuses on state goals and system
reliability to find lowest reasonable cost to
serve customer load.
•Develop resource needs assessment for
each state.
•State policies drive resource choices.
•Cost allocation based on state policies.
•Rate forecasts.
•Does not include resources in current RFP.
•Limits existing resources acquisition to 75
MW of additional regional hydro after 2031.
•Resources are selected either as system
resource (65%/35%) or state resource.
•Resources economically or contractually
expected to leave the Avista resource mix
are in green, natural gas-fired are in orange,
energy storage are in blue and clean
resources are in black.
7
Supply-Side Resource Changes
Avista Corp.2021 Electric IRP Appendices 589
IRP’s Preferred Resource
Strategy -Demand Resources
8
Energy Efficiency End Use Targets
Program Washington Idaho
Time of Use Rates 2 MW (2024)2 MW (2024)
Variable Peak Pricing 7 MW (2024)6 MW (2024)
Large C&I Program 25 MW (2027)n/a
DLC Smart Thermostats 7 MW (2031)n/a
Third Party Contracts 14 MW (2032)8 MW (2024)
Behavioral 1 MW (2041)n/a
Total 56 MW 15 MW
Demand Response
•63% of EE programs are C&I.
•77% of EE savings are from Washington.
•Washington avoided cost are $106/MWh plus
$151/kW-year for capacity.
•Driven by social cost of carbon and clean energy
avoided costs.
•Idaho avoided cost are $30/MWh plus $137/kW-
year for capacity.
•EE reduces winter peak by a 101% ratio to energy
savings and 97% ratio for summer.
•Washington 2022-23 target is 89,000 MWh; 50%
higher then previous biennium and higher than the
IRP’s two year cost effective acquisition amount.
•10-year target is 651 GWh or 74 aMW.
•Time of use and variable peak pricing requires
significant rate design effort leveraging metering
infrastructure.
•Demand response has limited reliability benefits
due to duration and call limitations.
Washington Idaho
Space Heating
Interior Lighting
Water Heating
Refrigeration
Cooling
Motors Ventilation
Exterior Lighting
Electronics
Miscellaneous
Process
Appliances
Office
Equipment
Food Preparation
Interior Lighting
Space Heating
Motors
Water Heating
Exterior Lighting
Ventilation
Electronics
Cooling
Miscellaneous
RefrigerationProcess
Appliances
Food
PreparationOffice
Equipment
Avista Corp.2021 Electric IRP Appendices 590
Preferred Resource Strategy
Costs and Rates
•Existing and new costs are allocated
between the states Avista serves.
•Washington rates are ~1 cent (12%) higher
per kWh today.
•Spread increases to 1.7 cents (15%) by 2030
and 2.0 cents by 2035.*
•Power costs rise well above inflation over
first 8 years due to clean energy and
capacity additions.
* Non-power related cost such as non-generation transmission,
distribution, and administration, are not directly modeled in the IRP and
assume a 2% annual growth rate.
9
0.000
0.020
0.040
0.060
0.080
0.100
0.120
0.140
0.160
0.180
0.200
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Do
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W
h
Overall Energy Rates
7%
5%
2%3%
2%
4%
4%
5%
6%
0%
2%2%
6%
3%
-1%
0%
1%
2%
3%
4%
5%
6%
7%
8%
2022-2025 2025-2029 2029-2033 2033-2037 2037-2041 2041-2045 2022-2045
WA ID
Power Cost Rate Change
Avista Corp.2021 Electric IRP Appendices 591
Clean Energy Shares (aMW)
•By 2030, Washington customers will have
clean energy equal to 100 percent of its
retail sales.
•Idaho’s clean energy share will lower both
Idaho and Washington rates.
•46% clean by 2030 and 60% clean by 2045.
•Clean energy as percent of system sales
increase to 78% by 2027 and 86% by
2045.
•Short-term clean energy purchase may
increase these estimates.
•Avista could purchase RECs to meet
2027 goals.
•Idaho customers have opportunity to sell
excess hydro RECs to reduce rates.
DRAFT
10
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Clean Energy Forecast
Avista Corp.2021 Electric IRP Appendices 592
Greenhouse Gas Emissions
Forecast
•2020 emissions were ~2.7 million metric
tons.
•Colstrip responsible for >1 million tons.
•Colstrip emissions would fall regardless as the
plant dispatch decreases over time.
•By 2030, emissions fall by 76 percent.
•Emissions from natural gas upstream
operations and construction are included
in this IRP.
•Washington load portion includes these
emissions priced at the social cost of carbon.
•WUTC recently ruled these emissions
accounting is encouraged but not required.
•Net emissions include market purchases
and sales at the regional emission
intensity rate.
DRAFT
11
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Annual Greenhouse Gas Types
Avista Corp.2021 Electric IRP Appendices 593
IRP Insights given uncertainty
•WUTC’s rulemaking regarding “use” of energy may
require significant market transformation and require
additional clean and storage resources.
•Electrification of Washington’s space and water heat
will significantly increase winter peak (up to ~700
MW) and annual energy (155 aMW) needs.
–New winter load will require significant investment in winter
capacity-such as natural gas turbines or long-duration storage.
–Energy rates from power acquisition rise 8% excluding non-power
costs such as T&D and home owner costs.
•Water heater load control may offer opportunities if
program costs decline (55+ MW).
–AC control is low cost option if summer peaks significantly
increase.
–Electric vehicle control is cost prohibitive now, but costs are
falling.
•Hydrogen-fired turbines show potential to be lowest
overall cost resource to serve winter loads in a 2045
100% clean energy future.
–Liquid air energy storage (LAES) and pumped hydro are better
nearer term options with intermediate energy duration options.
–Lithium-ion is low cost when coupled with solar or need for short
durations.
•A regional resource adequacy program is needed to
address regional reliability risk and lower Avista’s new
resource needs and costs (<1%).
–Resource mix could favor solar and hydro.
•Retaining Colstrip through 2025 increases cost by
1%.
–Tradeoff is higher power cost risk with an early exit.
•Meeting the clean energy goals increases total cost
by 5%.
–Idaho rates are 10% higher in 2027/ 28% higher in 2045.
–Washington rates are 4% higher in 2027/ 20% higher in 2045.
•Energy equity public engagement in Washington may
lead to new programs, resources, or investments.
–Equity budget requirements and limitations are unknown.
•Climate change (warmer temperatures) reduces
power costs and resource needs
–Hydro runoff better matches winter peaks and spill is less.
•Policy requirements with high carbon “taxes” support
higher clean energy levels and conservation
investments.
12 Avista Corp.2021 Electric IRP Appendices 594
Highlights
From the Preferred Resource Strategy
•Avista needs new clean resources to
comply with CETA.
•New capacity resources are required to
maintain reliability.
•Avista will need to pursue demand
response, rate design, and increase
energy efficiency.
•Exiting Colstrip is economic, but higher
risk.
•Long-duration storage is critical to meeting
100% clean energy objectives.
From Scenario Analysis
•Climate change lowers power costs.
•State/national policies will increase both rates
and costs.
•Electrification will significantly increase power
supply requirements. T&D and homeowner
costs are not estimated at this time.
•Real-time clean energy delivery will be
challenging for industry and current market
structure.
•Meeting Avista’s clean energy goals will be a
challenging without new technology or
increasing rates.
13 Avista Corp.2021 Electric IRP Appendices 595
Extra Slides
DRAFT
Tables & figures from Draft IRP of potential interest
Avista Corp.2021 Electric IRP Appendices 596
Scenario Analysis
Sorted by System PVRR (highest to lowest)
11- Electrification 1 14.7 10.1 4.5 0.131 0.188 0.109 0.158 34 88 132 0.57
13- Electrification 3 14.4 9.9 4.5 0.128 0.181 0.109 0.158 34 85 129 0.57
12- Electrification 2 14.0 9.5 4.5 0.127 0.176 0.109 0.155 34 71 115 0.56
6- Clean Resource Plan (2045)13.9 9.0 5.0 0.130 0.209 0.122 0.196 25 35 48 0.00
18- Clean Energy Delivered Each Hr 13.7 9.2 4.6 0.127 0.207 0.110 0.155 40 115 162 0.50
5- Clean Resource Plan (2027)13.7 8.8 4.9 0.129 0.176 0.121 0.166 24 56 100 0.50
9- High Load Forecast 13.5 8.9 4.6 0.123 0.164 0.104 0.142 38 70 122 0.56
7- SCC Idaho 13.3 8.7 4.6 0.126 0.175 0.112 0.161 39 82 143 0.50
17- Colstrip Exit 2045 13.3 8.7 4.6 0.127 0.173 0.108 0.154 34 72 127 0.89
16- Colstrip Exit 2035 13.3 8.7 4.6 0.127 0.174 0.108 0.153 34 85 148 0.53
19- SCC on Net P/S 13.3 8.7 4.6 0.126 0.174 0.110 0.153 40 84 148 0.54
15- Colstrip Exit 2025 13.3 8.7 4.6 0.127 0.173 0.110 0.153 40 87 150 0.54
14- 2x SCC 13.3 8.7 4.5 0.127 0.174 0.110 0.152 40 85 147 0.53
1- Preferred Resource Strategy 13.2 8.7 4.5 0.127 0.173 0.110 0.153 40 87 150 0.54
20- Use Avg Mrkt for EE SCC 13.2 8.7 4.5 0.126 0.172 0.108 0.153 40 88 154 0.54
10- RA Market 13.2 8.7 4.5 0.126 0.174 0.109 0.152 43 94 171 0.50
8- Low Load Forecast 13.1 8.6 4.5 0.130 0.186 0.113 0.163 44 101 178 0.48
3- Baseline 2 13.0 8.4 4.6 0.121 0.168 0.110 0.151 55 148 253 0.56
2- Baseline 1 13.0 8.4 4.6 0.121 0.168 0.110 0.152 54 148 254 0.56
4- Baseline 3 12.5 8.1 4.4 0.117 0.158 0.106 0.141 55 162 276 0.33
15 Avista Corp.2021 Electric IRP Appendices 597
$0 $2 $4 $6 $8 $10 $12 $14 $16 $18
4- Baseline 3
17- Colstrip Exit 2045
8- Low Load Forecast
16- Colstrip Exit 2035
20- Use Avg Mrkt for EE SCC
15- Colstrip Exit 2025
19- SCC on Net P/S
1- Preferred Resource Strategy
14- 2x SCC
10- RA Market
7- SCC Idaho
2- Baseline 1
3- Baseline 2
5- Clean Resource Plan (2027)
9- High Load Forecast
6- Clean Resource Plan (2045)
18- Clean Energy Delivered Each Hour
12- Electrification 2
13- Electrification 3
11- Electrification 1
PVRR (Bill $)
PV Tail 95 (Bill $)
Quantitative Risk PVRR + PV TailVar95 Risk
2030 Standard Deviation vs
Levelized Revenue Requirement
16 Avista Corp.2021 Electric IRP Appendices 598
Avoided Costs
2022 $20.37 $21.66 $18.65 $0.00 $0.00
2023 $18.71 $19.34 $17.89 $13.27 $0.00
2024 $18.73 $19.04 $18.32 $13.54 $0.00
2025 $19.99 $20.05 $19.92 $13.81 $0.00
2026 $23.74 $23.68 $23.82 $14.09 $0.00
2027 $24.63 $24.27 $25.12 $14.37 $115.10
2028 $25.67 $24.99 $26.58 $14.65 $117.40
2029 $26.65 $25.77 $27.83 $14.95 $119.80
2030 $26.46 $25.48 $27.78 $15.25 $122.20
2031 $27.63 $26.48 $29.15 $15.55 $124.60
2032 $28.02 $26.86 $29.57 $15.86 $127.10
2033 $29.30 $27.96 $31.08 $16.18 $129.70
2034 $29.42 $27.98 $31.33 $16.50 $132.20
2035 $30.47 $28.81 $32.68 $16.83 $134.90
2036 $32.10 $30.38 $34.41 $17.17 $137.60
2037 $31.95 $30.08 $34.45 $17.51 $140.30
2038 $34.46 $32.26 $37.39 $17.86 $143.10
2039 $34.77 $32.31 $38.04 $18.22 $146.00
2040 $35.67 $33.15 $39.01 $18.58 $148.90
2041 $38.23 $35.77 $41.52 $18.96 $151.90
2042 $38.71 $36.40 $41.79 $19.34 $154.90
2043 $39.27 $36.92 $42.40 $19.72 $158.00
2044 $46.82 $44.18 $50.34 $20.12 $161.20
2045 $46.45 $44.31 $49.28 $20.52 $164.40

17 Avista Corp.2021 Electric IRP Appendices 599
PRS Greenhouse Gas Intensity
18 Avista Corp.2021 Electric IRP Appendices 600
Initial Vulnerable Population
Areas
19 Avista Corp.2021 Electric IRP Appendices 601
Energy Forecast
(percent)
Expected Case 0.30
High Growth 0.70
Low Growth -0.10

20 Avista Corp.2021 Electric IRP Appendices 602
2021 Electric IRP
Action Items
John Lyons, Ph.D.
Fifth Technical Advisory Committee Meeting
January 21, 2021
Avista Corp.2021 Electric IRP Appendices 603
Summary of 2017 IRP Action Plan
•Generation Resource Related Analysis
–Continue to review existing facilities for opportunities to upgrade capacity and efficiency
–Model specific commercially available storage technologies
–Upgrade the TAC concerning the EIM study and Avista’s plan of action
–Monitor regional winter and summer resource adequacy, additional LOLP studies
–Post Falls redevelopment update
–Ancillary services valuation for storage and peaking technologies using intra hour
modeling capabilities
–Monitor state and federal environmental policies affecting Avista’s generation fleet
•Energy Efficiency and Demand Response
–Consider moving T&D benefits from historical to forward looking values
–Decide on potential and cost study for winter and summer residential DR programs
–Use the UCT methodology for Idaho energy efficiency programs
–Share list of energy efficiency measures with TAC prior to CPA completion
2 Avista Corp.2021 Electric IRP Appendices 604
Summary of 2017 IRP Action Plan
•Transmission and Distribution Planning
–Maintain existing Avista transmission rights
–Continued participation in BPA transmission rate proceedings
–Participate in regional and sub-regional efforts to expand
transmission system
–Coordinate IRP and T&D planning to evaluate alternative
technologies to solve T&D constraints
3 Avista Corp.2021 Electric IRP Appendices 605
2020 Resource Acquisition Action Items
•Determine plan for Long Lake expansion and file with
appropriate agencies concerning if the project meets CETA
and licensing issues
•Continued pursuit of pumped storage opportunities
•Conduct transmission network and air permitting studies for
contingency CTs if pumped hydro is not available
•2020 RFP for renewable energy capacity (2022-2023 online)
•2021 RFP for capacity resources (on-line by 2026)
•Additional studies for the eventual shutdown of Northeast CT
in 2035
4 Avista Corp.2021 Electric IRP Appendices 606
2020 Analytical & Process Action Items
•Continued study of costs of intermittent resources, and financial
costs and capabilities of different resources to meet the variability
•Include greenhouse gas emissions from resource construction,
manufacturing and operations
•Investigate third-party market price forecast for use with future
IRPs
•Participate in CETA rulemaking
•Participate in development of regional resource adequacy
program
5 Avista Corp.2021 Electric IRP Appendices 607
2021 IRP Action Items
•Continue 2020 Action Items with shortened 2021 IRP
•Investigate consultant for hydro and load shift from climate
•Investigate integration of resource dispatch, resource selection
and reliability verification functions in IRP modeling
•Study natural gas supply issues and options for Kettle Falls CT
•Determine if distribution planning should be separate process
•Form an Equity Advisory Group
•Conduct existing resource market potential estimate of
amount and timing of existing resources through 2045
•Additional DR peak credit analysis
•Partner with a third-party to identify NEI benefits
6 Avista Corp.2021 Electric IRP Appendices 608
2021 Electric IRP
Modeling Process Overview
James Gall, IRP Manager
Fifth Technical Advisory Committee Meeting
January 21, 2021
Avista Corp.2021 Electric IRP Appendices 609
IRP Planning Models
Aurora
PRiSM
“Reliability”
Model (ARAM)
PowerWorld Synergi
Load
Forecast
Resource
Options
Transmission & Distribution Models will be discussed in TAC 3
Discuss in TAC 2
Supply-side: Today
Demand Side: TAC 2
2 Avista Corp.2021 Electric IRP Appendices 610
What is Reliability Planning
•Estimate the probability of failure to serve all load
–Avista’s reliability target is 95% of all simulations serve 100% of load and reserve
requirements
•Model randomizes events
–Hydro, weather (load, wind, resource capacity), forced outages
•Typically large sample size 1,000 simulations
•Can be used to validate if a portfolio is reliable
–Estimate the required planning reserve margin (PRM)
–May be used to estimate peak credits for new resources (ELCC)
•Gold standard: regional wide program with enforced requirements to
each utility
–Set required methodology, planning margin, and resource contribution
based on regional model
3 Avista Corp.2021 Electric IRP Appendices 611
2021 IRP Table 7.1: LOLP Reliability
Study Results without New Resources

Jan 0.6% 2.7% 10.5% 32.7%
Feb 0.1% 0.6% 4.2% 15.0%
Mar 0.0% 0.0% 0.5% 2.9%
Apr 0.0% 0.0% 0.0% 0.0%
May 0.0% 0.0% 0.0% 0.0%
Jun 0.0% 0.0% 0.0% 0.1%
Jul 0.0% 0.3% 1.7% 33.0%
Aug 0.0% 0.1% 0.6% 30.5%
Sep 0.0% 0.0% 0.0% 0.9%
Oct 0.0% 0.0% 0.0% 0.5%
Nov 0.0% 0.0% 0.7% 5.0%
Dec 0.8% 3.2% 7.1% 17.1%
Annual 1.4% 6.3% 21.2% 81.4%

4 Avista Corp.2021 Electric IRP Appendices 612
Table 11.5: Reliability Metrics of PRS
LOLP 4.6% 5.4% 8.8% 5.2%
LOLH 1.45 hours 1.74 hours 2.89 hours 1.89 hours
LOLE 0.12 0.14 0.21 0.15
EUE 233 MWh 266 MWh 548 MWh 316 MWh
Total Events 126 148 228 160

5 Avista Corp.2021 Electric IRP Appendices 613
Scenario Analysis
# Scenario Year
Studied
LOLP LOLH LOLE EUE
1 PRS 2030 5.4%1.74 0.14 266
5 Clean Resource Plan (2027)2030 5.7%1.66 0.13 250
6 Clean Resource Plan (2045)2040 7.5%2.98 0.22 643
10 Resource Adequacy Program 2030 6.4%2.67 0.2 510
16 Colstrip Exit 2035 2030 5.7%1.77 0.14 287
11 Electrification Scenario 1 2040 TBD TBD TBD TBD
•Due to limited time, focus on scenarios with reliability implications
•Any other scenario we should look at?
6 Avista Corp.2021 Electric IRP Appendices 614
2021 Electric IRP
Clean Energy Action Plan
John Lyons, Ph.D.
Fifth Technical Advisory Committee Meeting
January 21, 2021
DRAFT
Avista Corp.2021 Electric IRP Appendices 615
Clean Energy Action Plan
The CEAP must:
1.identify and be informed by the utility’s ten-year cost-effective conservation potential
assessment;
2.if applicable, establish a resource adequacy requirement;
3.identify the potential cost-effective demand response and load management programs that
may be acquired;
4.identify renewable resources, non-emitting electric generation and distributed energy
resources that may be acquired and evaluate how each identified resource may be
expected to contribute to meeting the utility’s resource adequacy requirement;
5.identify any need to develop new, or expand or upgrade existing bulk transmission and
distribution facilities; and identify the nature and possible extent to which the utility may
need to rely on alternative compliance options, if appropriate.
•CEAP is available in chapter 15 of the 2021 IRP
2 Avista Corp.2021 Electric IRP Appendices 616
Energy Efficiency Savings
•508 GWh of cumulative energy efficiency or 61.3 aMW with T&D line loses.
•Reduce winter peak 64.3 MW and summer peak 69.5 MW.
3
Figure 15.1: Washington 10-year Energy Efficiency Target
Avista Corp.2021 Electric IRP Appendices 617
Resource Adequacy
•Participating in development of a regional resource adequacy program.
–16 percent winter peak and 7 percent summer peak planning margins, plus operating
reserves and regulation requirements.
–A resource adequacy program could reduce Avista’s new capacity needs by up to 70 MW in
2031 based on the current draft program design.
–Could reduce future resource acquisitions if successfully implemented.
•2021 IRP identifies 83 MW of natural gas-fired capacity for Washington by
November 1, 2026 to replace Lancaster PPA and maintain reliability.
•Future RFP may identify a lower cost clean resource.
4 Avista Corp.2021 Electric IRP Appendices 618
Demand Response and Load Management Programs
•CEAP identifies new programs with the potential to reduce load by 37.6 MW by 2031.
•Begin in 2024 with time of use and variable peak pricing opt-in programs, estimated to be 12 MW by 2031.
•25 MW large commercial customer program offering is likely before the Lancaster PPA ends in 2026.
•Heating and cooling program starts in 2031 with 0.6 MW of savings and grows to over 6 MW by 2045.
•Future RFPs may identify other DR opportunities.
5
Program Washington
Time of Use Rates 3.1 MW (2024)
Variable Peak Pricing 8.9 MW (2024)
Large C&I Program 25.0 MW (2027)
DLC Smart Thermostats 0.6 MW (2031)
Total 37.6 MW (2031 Total)
Table 15.1: Demand Response and Load Management Programs
Avista Corp.2021 Electric IRP Appendices 619
Planned Clean Energy Acquisitions
6
2022 2023 2024 2025 2026 2027 2028 2029 2030 2031
Retail Sales 647 650 651 655 657 658 658 661 662 663
PURPA 22 22 22 22 22 22 22 22 22 22
Solar Select 6 6 6 6 6 6 0 0 0 0Net Requirement 619 623 624 628 629 631 636 640 641 642
Target Clean %80 80 85 85 90 90 95 95 100 100
Clean Energy Goal 496 498 530 534 567 568 604 608 641 642
Owned Hydro 292 288 288 285 292 289 292 289 291 291Contract Hydro 96 95 65 66 65 64 63 58 59 23
Kettle Falls 24 23 23 21 23 21 22 20 21 19
Palouse Wind 24 24 24 24 24 24 24 24 24 24
Rattlesnake Flat Wind 36 36 36 36 36 36 36 36 36 36
Adams Neilson Solar 0 0 0 0 0 0 6 6 6 6Available Resources 473 466 436 431 439 434 441 433 436 399
Shortfall 23 33 94 103 127 134 163 174 204 242
Resource ForecastMontana Wind 0 48 96 96 96 96 144 144 144 144
Kettle Falls Upgrade 0 0 0 0 6 6 6 6 5 5
Regional Hydro 0 0 0 0 0 0 0 0 0 31
ID AVA Ren. Purchase 23 0 0 7 25 32 13 25 42 41
ID AVA Hydro Purchase 0 0 0 0 0 0 0 0 13 21Total Energy/RECs 23 48 96 103 127 134 163 175 204 242
Net Position 0 15 2 0 0 0 0 1 0 0
Total Clean Resource Need
23 48 96 103 127 134 163 175 191 180
Table 15.2: 2022-2031 Washington Clean Energy Targets (aMW)
Avista Corp.2021 Electric IRP Appendices 620
Transmission & Distribution Improvements
•2021 IRP did not identify any significant transmission or distribution
improvements.
•Future transmission investment follows the 10-year plan in Appendix G.
•Two interconnection requests to Avista transmission to evaluate up to 200 MW
in Rathdrum and additional capacity at Kettle Falls.
–Kettle Falls interconnection request does not require any significant improvements.
–Rathdrum results will not be available until later in 2021.
•Reviewed potential resource acquisitions that could defer distribution
investments, but none were selected in this IRP.
•Will begin designing a public process for distribution planning in 2021.
7 Avista Corp.2021 Electric IRP Appendices 621
Energy Equity
•Developing plan for equitable distribution of benefits and reduced burdens on highly impacted
communities and vulnerable populations.
•Washington is identifying highly impacted communities and guidance on cost premiums.
–Avista developed methodology to identify vulnerable populations and will finalize after forming Equity
Advisory Group (EAG) in 2021.
–EAG will guide determination of communities and help design outreach and engagement to distinguish
and prioritize indicators and solutions.
–Committed to energy efficiency program pilot for vulnerable populations starting in 2021.
•Enhancements to energy efficiency cost effectiveness test include non-energy benefits.
•Avista prioritizes efficiency projects to improve resiliency and increase energy security in these
communities and gives a preference to renewable projects in vulnerable areas.
•Future request for proposals may yield more beneficial renewable resources.
8 Avista Corp.2021 Electric IRP Appendices 622
Cost Analysis
•IRP compares PRS cost to baseline portfolio without CETA requirements to show if
alternative compliance (2% cost cap) will be required.
•Avista expects to be below cap by $64 and $61 million for first two of the four-year
compliance periods.
9
Table 15.3: 2022-2024 Washington Cost Cap Analysis (millions $)
2021 2022 2023 2024 2025 Total
Revenue Requirement w/ SCC 651 651 669 700 705
Baseline 650 657 672 678
Annual Delta 1 11 28 27 67
Percent Change 0.2%1.7%4.2%4.0%2.5%
Four Year Max Spending 33 33 33 33 132
Comparison vs Annualized Cost Cap (32)(22)(5)(6)(64)
Table 15.4: 2025-2028 Washington Cost Cap Analysis (millions $)
2024 2025 2026 2027 2028 Total
Revenue Requirement w/ SCC 705 714 718 744 755
Baseline 688 709 721 731
Annual Delta 26 9 23 23 81
Percent Change 3.8%1.3%3.2%3.2%2.9%Four Year Max Spending 36 36 36 36 143
Comparison vs Annualized Cost Cap (10)(27)(13)(12)(61)
Avista Corp.2021 Electric IRP Appendices 623
2021 Electric IRP
Clean Energy Implementation Plan (CEIP)
James Gall, Electric IRP Manager
Fifth Technical Advisory Meeting
January 21, 2021
Avista Corp.2021 Electric IRP Appendices 624
CEIP Overview
•File by October 1, 2021. (draft by Aug 15, 2021)
•Include current clean energy mix (2020).
•Set targets for energy efficiency, demand response and clean energy acquisition using median hydro
conditions.
•Include an assessment of indicators of Highly Impacted Communities and Vulnerable Populations
through work with the Equity Advisory Group.
•Include specific actions the utility will make to meet clean energy goals; including resource adequacy
and equity considerations.
•Calculate incremental costs.
•Create public participation plan (due on May 1, 2021).
•Interested parties have 60 days to provide written comments to the Commission.
•Commission will set an open public meeting; after adjudication, Commission will approve, reject or
approve with condition the utility’s CEIP or CEIP update.
2 Avista Corp.2021 Electric IRP Appendices 625
Public Participation
•A public participation plan must be filed with the WUTC on May 1, 2021.
•Avista will begin public participation on the CEIP toward the end of May
2021.
•All TAC members are welcome to join; please contact John Lyons at
[e-mail] or 509-495-8515 to be on the CEIP email list.
•Equity Advisory Group is currently forming.
–Ana Matthews leads this effort
–Contact her at 509-495-7979 or [e-mail] for more
information
Avista Corp.2021 Electric IRP Appendices 626
Clean Energy Implementation Plan (CEIP)
Details of Requirements
Avista Corp.2021 Electric IRP Appendices 627
WAC 480-100-640
CEIP Content –Filing Requirements, Interim Targets
1.Utility must file with the commission a CEIP by October 1, 2021, and every
four years thereafter; must describe the utility's plan for making progress
toward meeting the clean energy transformation standards
2.Interim targets.
a)Utility must propose a series of interim targets that
i.Demonstrate utility’s reasonable progress toward meeting the standards.
ii.Consistent with WAC 480-100-610 (4).
–EE, DR, Safety, Reliability, Balancing system, Equity
iii.Interim targets must be proposed in the form of the percent of forecasted retail sales of
electricity supplied by nonemitting and renewable resources prior to 2030 and from 2030-2045
b)Must include utility’s percentage of retail sales of electricity supplies by nonemitting and
renewable resources in 2020 in the first CEIP it files.
c)Each interim target must be informed by the utility’s historic performance under median
water conditions
5 Avista Corp.2021 Electric IRP Appendices 628
3) CEIP Content –Specific Targets
a)Utility must specific targets for energy efficiency, demand response and
renewable energy.
i.EE target much encompass all other EE and conservation targets and goals required by
the Commission; must be described in the BCP; utility must provide forecasted distribution
of energy and nonenergy costs and benefits
ii.Must provide proposed program details, budget, measurement and verification protocols,
target calculations, forecasted distribution of energy and nonenergy costs and benefits for
the utility’s demand response target.
iii.Must propose the renewable energy target as a percent of retail sales of electricity
supplied by renewable resources, details of renewable energy projects or programs,
budgets, forecasted distribution of energy and nonenergy costs and benefits
b)Must provide description of technologies, data collection, processes,
procedures and assumptions used to develop targets
6 Avista Corp.2021 Electric IRP Appendices 629
4) CEIP Content –Customer Benefit Data
a)Identify highly impacted communities using the cumulative impact analysis
pursuant to RCW 19.405.140 combined with census tracts (Indian country).
b)Identify vulnerable populations based on adverse socioeconomic and
sensitivity factors developed through the Equity Advisory Group (EAG) process
and public participation plan; describe changes from the utility’s most recently
approved CEIP.
c)Include proposed or updated customer benefit indicators and associated
weighting factors related to WAC 480-100-610(4)(c) such as energy benefits,
nonenergy benefits, reduction of burdens, public health, environment,
reduction in cost, energy security and resiliency. Customer benefit indicators
and weighting factors must be developed consistent with the EAG process and
public participation; describe any changes from the most recently approved
CEIP.
7 Avista Corp.2021 Electric IRP Appendices 630
5) CEIP Content –Specific Actions
Include specific actions the utility will take over the implementation period; actions
must meet and be consistent with the clean energy transformation standards and
be based on the utility’s CEAP and interim/specific targets; specific action items
must be presented in a tabular format providing
a)General location, if applicable, proposed timing, estimated cost, whether resource will be
located in a highly impacted community, will be governed by, serve or benefit highly
impacted communities or vulnerable populations in part or in whole.
b)Metrics related to the RA including contributions to capacity or energy needs.
c)Customer benefit indicator values, or a designation as nonapplicable, for every customer
benefit indicator described in section (4) (c)
8 Avista Corp.2021 Electric IRP Appendices 631
6) CEIP Content –Narrative Description of Specific
Actions
CEIP must describe how the specific actions:
a)Demonstrate progress toward meeting the standards.
b)Demonstrate consistency with the standards in 480-100-610(4)
i.An assessment of current benefits and burdens on customers, by location and population, and
the projected impact of specific actions on the distribution of customer benefits and burdens
during the implementation period.
ii.Description of how the specific actions in the CEIP mitigate risks to highly impacted communities
and vulnerable populations and are consistent with the longer-term strategies and actions
described in the utility’s most recent IRP and CEAP
c)Consistent with proposed interim and specific targets;
d)Consistent with the IRP;
e)Consistent with the resource adequacy requirements and a narrative describing how the
resources identified in the most recent RA assessment conducted or adopted by the utility
demonstrates that the utility will meet its RA standard;
9 Avista Corp.2021 Electric IRP Appendices 632
6) CEIP Content –Narrative Description of Specific
Actions (continued)
f)Demonstrate how the utility is planning to meet the clean energy transformation standards
at the lowest reasonable cost such as
i.Utility’s approach to identifying lowest cost portfolio of specific actions that meet the requirements
as well as its methodology for weighting considerations
ii.Utility’s methodology for selecting the investments and expenses it plans to make over the next 4
years that are directly related to the utility’s compliance with clean energy transformation
standards and demonstrate investments represent a portfolio approach to investment plan
optimization
iii.Supporting documentation justifying each specific action identified in the CEIP
10 Avista Corp.2021 Electric IRP Appendices 633
CEIP Content
7.Include a projected incremental cost as outline in WAC 480-100-660 (4).
8.Detail the extent of TAC/EAG or other public participation in the development
of the CEIP.
9.Describe any utility plans to rely on alternative compliance mechanisms as
described in RCW 19.405.040 (1) (b)
10.If the utility proposes to take the early action coal credit, it must satisfy the
requirements in that statutory provision by
–Demonstrate the proposed action constitutes early action by presenting the analysis by
detailing with and without the proposed early action
–Compare both the proposed early action and the alternative against the same proposed
interim and specific targets
11 Avista Corp.2021 Electric IRP Appendices 634
11) CEIP Content –Biennial CEIP Update
•Utility must make a biennial CEIP update filing on or before November 1 of
each odd-numbered year that the utility does not file a CEIP.
•CEIP update may be limited to the BCP requirements.
•Must file its biennial CEIP update in the same docket as its most recently filed
CEIP and include an explanation of ow the update will modify targets in its
CEIP.
•Utility may file in the update other proposed changes to the CEIP as a result of
the IRP progress report.
12 Avista Corp.2021 Electric IRP Appendices 635
480-100-645
CEIP Review Process
1.Interested parties may file written comments with the Commission within 60
days of the utility’s filing.
2.Commission will set an open public meeting; after adjudication, Commission
will approve, reject or approve with condition the utility’s CEIP or CEIP update;
Commission may order, recommend or require more stringent targets.
a)Commission may adjust or expedite interim or specific target timelines.
b)Parties requesting the commission make existing targets more stringent or adjust the
existing timelines has the burden of demonstrating the utility can achieve the targets or
timelines.
13 Avista Corp.2021 Electric IRP Appendices 636
2021 Electric IRP TAC 5 Meeting Notes, January 21, 2021
Meeting Attendees: Andres Alvarez; Shawn Bonfield, Avista; Annette Brandon, Avista;
Terrence Browne, Avista; Corey Dahl; Thomas Dempsey, Avista; Grant Forsyth, Avista;
Annie Gannon, Avista; Amanda Ghering, Avista; Dainee Gibson-Webb, Idaho
Conservation League; Michael Gump, Avista; James Gall, Avista; Lori Hermanson,
Avista; Fred Heutte, NEWC; Clint Kalich, Avista; Kevin Keyt, IPUC; Scott Kinney,
Avista; John Lyons, Avista; Jaime Majure, Avista; James McDougall, Avista; Ben Otto,
Idaho Conservation League; Tom Pardee, Avista; Lance Kaufman (AWEC); Marissa
Warren, Idaho Office of Energy Resources; Michael Eldred, IPUC; Mike Louis, IPUC;
Mike Morrison, IPUC; Montoya Lina; Morgan Brummell; Rachel Farnsworth, IPUC; Shay
Bauman; Jennifer Snyder, WUTC; Terri Carlock, IPUC; Tina Jayaweera, NW Power
Council; Yao Yin, IPUC; Chip Estes; Joni Bosh, NWEC; Katie Pegan; Katie Ware.
Notes in italics are responses made by the presenter.

Introductions and 2021 IRP Process Updates, John Lyons
John Lyons (slide 6): Is the public open meeting that is scheduled for February 2021
still needed now that we have an open public meeting at the WUTC on February 23,
2021?
Rachel Farnsworth: What was going to be covered in the public outreach meeting?
Probably a high level overview of the draft IRP and an opportunity for the public to
comment before publishing it. I’m not sure I agree with not having that public meeting,
but will discuss it with our Idaho team. There was a lot of interest in participation for the
last IRP, so take that into consideration.
Ben Otto: I think providing a public opportunity to comment on the draft IRP before it is
finalized is a good idea.
James Gall (slide 7): If you want to run scenarios, get a hold of me because you’ll
need Gurobi and What’s Best licenses to make the models work. You can review the
results from the model runs without the licenses.
John Lyons: We do not have signed contracts yet for the successful bidders of the
2020 Renewables RFP and those contracts will change the near term PRS if signed.
For the results of the 2020 renewable RFP, what’s the cut-off to include them and
rewrite the IRP? Is it the end of January, sometime in February, or some other time?
Jennifer Snyder: If possible, at all, it’d be great to have it included, time allowing. If
there is only time for a letter or appendices about the contracts, that’d be ok too.
Ben Otto: What is the likelihood and scale of changes to the PRS that could come from
the RFP?
Avista Corp.2021 Electric IRP Appendices 637
James Gall: It doesn’t change the resource need, but it changes the resource mix in
the early years.
John Lyons: We are hoping to be finished with contracts by end of the first quarter.

Review Draft 2021 IRP, John Lyons
Jennifer Snyder: Chapter 13, the EAAG is referred to as the EEAG.

Draft Resource Plans and Scenarios, James Gall
Mike Morrison: Could we further discuss the definition of a 5% LOLP?
James Gall: Let’s defer that to the ARAM discussion.
Joni Bosh: What do the green and blue stand for?
Lori Hermanson: Green resources are being retired and blue storage resources are
being added.
Thomas Dempsey: Why is there a 2021 retirement of Colstrip?
James Gall: Models show retirement when it’s cost-effective, but it doesn’t mean
Colstrip will retire in 2021.
Katie Ware: Did you explore the sensitivity of a mix of lithium-ion and long-duration
storage?
James Gall: Excellent question. Lithium-ion and long-duration storage are all resource
options, so the model when looking at capacity need can choose from any of those
resources. Longer duration resources have a higher peak credit which is why it is
selected over lithium-ion, even though lithium-ion could be a cheaper resource. Lithium-
ion is lowest cost when combined with solar, but liquid air is best for long term storage.
Katie Ware: Is there a scenario of storage mixes. Yes, we’ll discuss it in detail later.
Yao Yin: Based on the table and modeling, there are different needs for different
resources. How does the company reconcile this when acquiring resources?
James Gall: It’s a real challenge for us. We identify the need, then need to determine
who [which state or system] is driving the need and who is paying for it. We definitely
need a company strategy on how to assign responsibility for recovery of new resources
and we need to figure out how to do that with the commissions.
Yao Yin: How do you decide what resource to acquire in reality when it comes to
operational decisions?
Avista Corp.2021 Electric IRP Appendices 638
James Gall: If we acquire all of these, we’ll operate them to meet load if needed.
Actual acquisitions are decided through a competitive process like an RFP.
Tina Jayaweera: Are DR impacts for both summer and winter? Yes, many impacts for
both summer and winter.
Yao Yin: For the DR and energy efficiency programs in the preferred program, are they
based on the third-party or the study?
James Gall: The third party determines the price and the potential and our model
selects the measures.
Yao Yin: Are they bundled? No. Is DR the same way?
James Gall: Yes, each individual measure, about 7,000 of them, can be selected. This
is the same by DR and by state.
Fred Heutte: I’m wondering about DR, CT2045 for new water heaters and heat pumps,
electric resistance, why didn’t these show up?
James Gall: The costs were given by AEG, it was the next resource in [just missed
being selected in this IRP]. The potential was quite large, but it was not competitive. If
the pricing comes down about 20% in the next plan, it’ll be selected.
Fred Heutte: I’m going to investigate AEG’s numbers as it doesn’t seem this would be
that expensive. In my view, utilities in Washington should just acquire these.
Tina Jayaweera: Thermostats may not save the same amount in summer as in winter,
is the 7 MW in the summer or winter?
James Gall: It’s the winter savings. I have the summer savings available too, but didn’t
show them here. They are in the supporting documents. Feel free to dig into them.
Jennifer Snyder: Have you done any analysis on bill impacts? The Washington rate is
higher but so is energy efficiency, does it make the comparison any different?
James Gall: Great question, I don’t have the answer. Maybe that’s something we can
investigate.
Fred Heutte: About the below the zero sales, can you walk through the math? My
sense is there will always be gas in the market, about half of a coal plant.
James Gall: There’s several methodologies, you’ve described one. We sell system
power, then incremental cost and emissions change. I try to keep things simple here.
For every MW sold, we estimate the amount of emissions the NW emits. It’s really an
unknown and I try to show it both ways. It goes away in 2025.
Fred Heutte: It’s a net sales, but if you didn’t sell, what’s the marginal analysis?
Avista Corp.2021 Electric IRP Appendices 639
James Gall: I agree. I’ve done it and it’s difficult. Average hourly emissions by our
system and the regional emissions. However, we can’t do that to that level with the
models we have. Maybe we can in the future. We have annual models so I don’t know
how much we bought or sold each hour.

Fred Heutte: Agreed, this is a first cut and gives us a sense. It’s not easy to do this
hourly. Ultimately, we need to land there. Hydro complicates this too.
Joni Bosh: So system power is unspecified power?
James Gall: Two types of power – Avista’s system power, sales and purchases. We
don’t know what we’re buying each hour so we’d have to determine a mix of this.
Mike Morrison: Do the liquid air energy storage systems currently in your portfolio
assume the existence of waste heat from thermal plants? Is this waste heat generated
by hydrogen or biomass? If so, does your modeling include these costs?
Thomas Dempsey: 100% renewable is not available yet.
Mike Morrison: You assume the use of waste heat to power the high temp side of the
engine, but the efficiency was above this.
Thomas Dempsey: I believe we provided an answer for that question, but I don’t have
that in front of me.
James Gall: Or we used a lower efficiency in this plan, but I’ll need to get back to you
on that.

2021 IRP Action Items, John Lyons
Fred Heutte: The Power Pool is having an update on resource adequacy next Friday.
I’ll add a link. [NWPP Resource Adequacy Program public webinar next Friday, Jan. 29,
1-2:30 pacific time https://www.nwpp.org/events/86 ]

John Lyons: Thanks for sharing that around.

Jennifer Snyder: I wanted to know if you are looking at other DER investments and
how are you planning on doing those in the future?

James Gall: We currently evaluate those DER resource options in the plan. The
challenge is they’re not getting selected from an economic point of view. Are there
additional economic or equity benefits that we need to study? Unless there’s a specific
reason to pick DERs due to a locational benefit to help with the economics, they’re not going to be economic and will not be chosen. This takes quite a bit of time to study.

Avista Corp.2021 Electric IRP Appendices 640
Jennifer Snyder: Other values will have to drive it to be accepted.

ARAM Model Overview, James Gall
Mike Morrison: What is your definition of LOLP?
James Gall: I’ll explain it when I open the model.
Lance Kaufman: If you’re unable to meet your load requirements, it counts as a loss of
load event. Can you explain this further?
James Gall: We track both ways – if we can’t meet our reserve obligations to WECC or
we can’t meet our load, both can occur at the same time.
Scott Kinney: It’s a NERC requirement that you have to maintain your operating
reserves to avoid blackouts across the whole system. For example, in California this
summer during the heat wave, they had to start shedding load. You have to shed load
to save the entire interconnection.
Thomas Dempsey: Can you clarify the question I thought I heard? Suppose we’re
carrying 100 MW of reserves, but we need 50 MW. If we have already used it, we no
longer have the 100 MW of reserve. Is that situation an event?
Scott Kinney: We can call on other reserves in the region.
Yao Yin: For existing and/or new resources, how do we determine the capacity?
James Gall: For both existing and new resources, and we will get to the capacity later
in the presentation.
Lance Kaufman: Can you explain the dispatch logic? Are things being co-optimized?
How is thermal, hydro/storage being re-dispatched?
James Gall: The model is not concerned with cost but with availability. It will dispatch
based on a priority of economics. Each resource is trying to serve that load equally but
in a high load event everything will run.
Lance Kaufman: Will you cover storage logic later?
James Gall: Yes. This is a reliability model. The first version was with no economics.
This model now has economics included.
Mike Louis: If the market is used to meet reserves, is the amount constrained?
James Gall: Essentially, from a market point of view, we’re using our reserves to meet
the load. We could buy from the market in the future to meet reserves.
Lance Kaufman: Is there a risk of having that flat so that it misrepresents reliability?
Avista Corp.2021 Electric IRP Appendices 641
James Gall: I haven’t tested that. There could be a couple of months where there could
be a reliability problem. I’m leaning toward it not being a big impact, but I don’t know for
sure without testing.
Andreas Alvarez: What timeframe is the model optimizing these storage resources?
James Gall: All 8760 at the same time. The model has perfect foresight, which is more
than reality.
Yao Yin: Where is the 16% planning margin located?
James Gall: It’s not an actual input or output. We’re going to talk about this more later.
Andreas Alvarez: When it’s storing, is it seeing a price for charging?
James Gall: Yes, there’s an economic charge for charging and dispatching storage. It
is set up with a very high price to not serve load, so it is optimizing to serve load. Really
only focusing on hours where there will be an hour needed.
Andreas Alvarez: It’s charged for that hour to avoid the $5,000.
Mike Morrison: How are storage efficiencies determined?
James Gall: Determined by what storage resource was chosen.
Mike Morrison: How does it keep track of when storage devices are charging and
dispatching?
James Gall: Showed the dispatching versus charging in the model. It can’t draw more
than what the limits are.
Mike Morrison: Is the model smart enough to say the battery isn’t charged enough or
what needs to be charged?
James Gall: The power of the What’s Best program is that it creates a linear equation
to solve for the parameters, subject to constraints, to minimize the cost to serve load.
Lance Kaufman: Could you clarify for the hourly load forecast, when you say you’re
looking at historical years, are you taking historic temperatures and putting them into the
current forecast?
James Gall: Yes. Load forecast with weather using actual data for a particular year. In
theory. We have to create a regression to create an hourly load shape and match that
with weather.
Lance Kaufman: Where would we look to see the details of this by year?
James Gall: Historical hourly loads are used to create a regression equation which is
used to multiply the historical daily temperatures to estimate the hourly loads included in
the model. Since the ARAM model includes proprietary data it can’t be shared.
Avista Corp.2021 Electric IRP Appendices 642
Lance Kaufman: On the years tab, have you done analysis between the water year
and the load year?
James Gall: Yes, on an annual basis. On an annual basis there is no correlation, but on
a weekly basis, there could be correlation. We’re varying these inputs on an annual
basis. We chose not to put a correlation in there.
Andreas Alvarez: Is Montana wind assumed to be central or eastern?
James Gall: It is eastern Montana wind. I don’t recall which wind turbine was used.
James Gall: Yao asked earlier how this relates to planning margin. We are trying to get
as close to 5% LOLP as possible. So the question is how many resources or how much
market availability do I have to add to achieve this? Here we will put a constraint on how
much can come from the market. We’re concerned with really hot or cold days – those
are the days we’re concerned about market availability. If the temperature is above 80
or below 2 degrees, it triggers a market availability constraint. The 16% planning margin
is the amount of extra resources needed above our load assuming this constrained
market availability.
Andreas Alvarez: Will you be going over peak capacity contributions?
James Gall: If I reduced gas and increased wind to come up with the same LOLP that
would result in a 25% peak credit. The difficulty is when you add more wind the value of
the peak credit degrades.

Clean Energy Implementation Plan and Clean Energy Action Plan, James Gall
Yao Yin: Is there a separate preferred portfolio for each state?
James Gall: Our PRS identifies what resources are driven by each state, but all
resources are needed.
Yao Yin: In the ARAM model, do we look at the entire system? Yes.
Jennifer Snyder: Is John the main contact? Are you considering the CEIP being the
same team makeup as the IRP?
James Gall: We have not decided yet. We’ll be working on that.

Draft IRP Comments from TAC
Mike Morrison: I’ve perused the draft. You definitely listened to some of our last
comments and incorporated them. I appreciate that. I’ll be really looking at the capacity
calculations and making sure the assumptions make sense. Anything you can do to
Avista Corp.2021 Electric IRP Appendices 643
enlighten me would be helpful. Keep up the good work. This has been a really helpful
presentation.
James Gall: John is taking notes and we’ll be putting these on our website. We’ll
respond where we can today if possible and for sure later in the final IRP.
Yao Yin: A clarifying question, for the preferred portfolio on the list of system need and
by Idaho and Washington, did you mean that the final list includes all resources and this
slide identifies the drivers?
James Gall: Correct. The slide includes all preferred resources needed to serve the
system and the color of each resource identifies the driver as being system, Idaho or
Washington.
Jennifer Snyder: The UTC doesn’t necessarily expect you to meet everything in this
IRP since the rules just came out. Can you add in some narrative on the maximum
customer benefit scenario and what that might look like to help with the discussion
going forward?
James Gall: I don’t know if the drafters of the rule have an expectation of what they’re
expecting for that scenario. The definition of the maximum customer benefit scenario is
what I am challenged by. I’m puzzled on what it means.
Jennifer Snyder: You and I are right there on that. PSE is doing 150% of cost-
effectiveness for energy efficiency. I don’t necessarily think this is the way to go. If you
were going to increase the customer benefit, how would you maximize things?
James Gall: What is the meaning of customer benefit – reliability, financial, etc.? We’re
already solving for the maximum financial benefit. We’ll mull it over. I think we already
have the scenario like PSE.
Shawn Bonfield: The newly formed equity advisory group may inform this scenario
from that perspective. I see this as a narrative of how we’ll use that group.
Yao Yin: On the slide about all the chapter content, for chapter 13 on the use of the
preferred portfolio in determining avoided costs, did you mean for PURPA or for energy
efficiency?
James Gall: We meant for both. Avoided cost of our preferred strategy which could be
used for PURPA, energy efficiency or a supply-side resource. We will be adding the
estimated avoided costs showing how folks can calculate the avoided costs of their
particular resource.
Yao Yin: What is your justification of using the preferred portfolio of new resources
instead of existing resources?
James Gall: We have an existing resource stack, but if we had a new resource to
consider the cost we are avoiding would be from acquiring a new resource.
Avista Corp.2021 Electric IRP Appendices 644
2021 Integrated Resource Planning
February 24, 2021
Avista Corp.2021 Electric IRP Appendices 645
Meeting Format
•5:00 to 6:00
–Welcome-Jason Thackston, SVP of Energy Resources
–Overview of Avista’s Electric Resource Plan-James Gall
–Overview of Avista’s Natural Gas Resource Plan-Tom Pardee
•6:00 to 6:30
–Attend first breakout session
•6:30 to 7:00
–Attend second breakout session
•This meeting will be recorded
2 Avista Corp.2021 Electric IRP Appendices 646
Objectives of Today’s
Meeting
•Overview of Avista’s electric and natural gas systems.
•Learn about considerations when planning to meet customer load.
•Explore Avista’s proposed resource plan for natural gas and
electric supply.
•Opportunity to ask questions and provide feedback in breakout
sessions.
•Poll questions to provide instant feedback.
3 Avista Corp.2021 Electric IRP Appendices 647
Avista also owns Alaska
Light & Power in
Juneau, AK
4 Avista Corp.2021 Electric IRP Appendices 648
Maintaining Balance is
Important
EnvironmentReliability
Affordability
5
Poll
Avista Corp.2021 Electric IRP Appendices 649
Avista’s Clean Electricity Goal
Avista’s goal is to serve our
customers with 100 percent clean
electricity by 2045 and to have a
carbon-neutral supply of electricity
by the end of 2027
We will maintain focus on
reliability
and affordability
Natural gas is an important part of
a clean energy future
Technologies and associated
costs need to emerge and mature
in order for us to achieve our stated
goals
It’s not just about generation
6 Avista Corp.2021 Electric IRP Appendices 650
Providing Cleaner Natural Gas
•We are committed to reducing greenhouse gas emissions in our natural gas business too
•Achieving reductions requires an “all-of-the-above” approach:
•Gas supply and distribution opportunities like renewable natural gas
•Upstream strategies like targeted sourcing with suppliers
•Engagement with customers to increase energy efficiency, demand response, and voluntary
programs
•Just like our clean electricity goals, reducing greenhouse gas emissions in our natural gas system will
require advances in technology and reductions in the cost of those technologies
•Affordability will guide our decisions
7 Avista Corp.2021 Electric IRP Appendices 651
What is the Purpose of an IRP?
•Understand supply needs to serve
our customers over the next 20
years.
•Evaluate resource options to meet
future needs.
•Determine which resources are
best suited to meet customer need.
•Sets course for acquisition of
resources.
•Required to be filed with our
state regulating commissions
every two years.
•Allows for public feedback and
participation.
•Commissions acknowledge
plans but do not approve the
plans.
8 Avista Corp.2021 Electric IRP Appendices 652
Electric Integrated Resource Plan
Avista Corp.2021 Electric IRP Appendices 653
Production, $0.2763
Storage, $0.0236 Distribution, $0.2395
Common, $0.1682
What makes up your energy
rate?
Fixed Charge
Monthly connection
charge
Demand Charge
The highest use
over an hour in the
last 12 months
Energy Charge
The amount of
energy used over
the month
Begins with Cost
to Serve All
Customers Residential
Commercial
Large
Commercial
Industrial
Water
Pumping
Street
Lighting
Customer Type Pricing Type
El
e
c
t
r
i
c
Na
t
u
r
a
l

G
a
s
Production, $0.0412
Transmission,
$0.0087
Distribution, $0.0216
Common, $0.0172
Poll
10 Avista Corp.2021 Electric IRP Appendices 654
What fuels our generating
resources?
11 Avista Corp.2021 Electric IRP Appendices 655
Why does Avista need new
electric resources?
Resources
Load without EE + Contingency
Load with EE + Contingency
Meet System Winter Peak
Load
Non-Hydro Transfer Limit Hydro Transfer Limit
Total Existing Resources (Share)Retail Sales
Proposal Compliance Target
Meet Washington Clean Energy
Requirements
12
Avista also plan to meet summer peak conditions & to ensure it generates
enough energy over the course of the year in poor hydro conditions.Avista Corp.2021 Electric IRP Appendices 656
What are the available options
to meet our electric customer
obligations?
Clean Resources
Wind
Solar
Biomass
Hydro
Geothermal
Nuclear
Fossil Fuel Resources
Natural gas peaker
Natural gas baseload
Coal (retention)
Customer generation
Demand Resources
Energy efficiency
Conservation
Load control
Rate programs
Fuel switching
Co-generation
Storage
Pumped hydro
Lithium-ion batteries
Liquid air energy storage
Flow batteries
Hydrogen
13 Resources in italics were not directly modeled for this IRP
Avista Corp.2021 Electric IRP Appendices 657
Electric IRP’s Preferred
Resource Strategy over the
next 10 years
14
Generation
Portfolio
By end of 2025: Exit Colstrip
2023-24: Add new renewables
(i.e. wind, solar, hydro)
2026-2027: Replace Lancaster
natural gas plant (natural gas generation is lowest cost option) &
increase capacity at the Kettle Falls
Generating Station & Post Falls
2028: Add new renewable resources (Montana wind)
2031: Acquire existing Northwest
Hydro Capacity
2035: Replace Northeast natural gas
plant with upgrades to Rathdrum CT and acquire new capacity
Energy
Efficiency
Energy Efficiency meets 68% of
future load growth
Industrial & commercial customers provide 2/3 of savings
Residential Single family home
is largest single segment
Washington top targets: Lighting, space heating, water heating, refrigeration, and
cooling
Idaho to targets: Lighting, space heating, and motors
Demand
Response
2024: Offer new rate programs
(opt-in)
(Time of use rates & variable
peak pricing)
2026/27: Industrial load
control
2031-32: Smart thermostat
controls and commercial load
control
Avista Corp.2021 Electric IRP Appendices 658
Avista’s Cleaner Future
-
200
400
600
800
1,000
1,200
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Existing Clean Resources RECs New Clean Resources Net Sales
-1.0
-0.5
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Current Resources
New Resources
Net Market Transactions
Upstream/Construction/Operations
Net Emissions
2019 Generated Emissions
Dispatched Emissions w/ Colstrip Operating to 2025
•Clean energy percent of system sales
increase to 78% by 2027 and 86% by
2045.
•By 2030, Avista’s greenhouse gas emissions fall
by 76 percent.
•2019 Northwest power emissions were 57 million
metric tons (Avista is 5.2% of those emissions).
•Power is 20% of all NW greenhouse gas
emissions.
15
Greenhouse Gas Emission Forecast
Clean Energy Forecast
Avista Corp.2021 Electric IRP Appendices 659
Natural Gas Integrated Resource Plan
Avista Corp.2021 Electric IRP Appendices 660
Existing Resources vs.
Peak Day Demand
-
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
90,000
100,000
MM
B
t
u
JP TF-2 Existing GTN Existing NWP Forecasted Peak Demand - Medford/Roseburg
-
50,000
100,000
150,000
200,000
250,000
300,000
350,000
MM
B
t
u
Existing GTN JP TF-2 Existing NWP Spokane Supply Forecasted Peak Demand for ID and WA
Idaho and Washington
Medford and Roseburg
17 Avista Corp.2021 Electric IRP Appendices 661
What are the available options
to meet our natural gas
customer obligations?
Clean Resources
Renewable Natural Gas
Hydrogen
Power to Gas
Fossil Fuel Resources
Natural gas
Coal gasification
Demand Resources
Energy efficiency
Conservation
Load control
Rate programs
Fuel switching
Storage
Jackson Prairie Storage Facility
Liquified Natural GasCompressed Natural Gas
18 Resources in italics were not directly modeled for this IRP
Avista Corp.2021 Electric IRP Appendices 662
Natural Gas System Cost vs
Carbon Adder
19
Poll
Avista Corp.2021 Electric IRP Appendices 663
Avista Natural Gas –A Cleaner
Future
2019 Retail Energy Delivered
Carbon Reduction Goals
(Oregon & Washington
Mi
l
l
i
o
n
s

o
f

M
T

C
O
2
e
Emissions with Climate Goals and EO
Expected Emissions MTCO2e
8,400
8,600
8,800
9,000
9,200
9,400
9,600
9,800
10,000
10,200
260
270
280
290
300
310
320
330
340
350
Electric Natural Gas
Th
o
u
s
a
n
d
s

o
f

M
W
h
Mi
l
l
i
o
n
s

o
f

T
h
e
r
m
s
Therms MWh
20
Oregon -Executive Order 20-04
•80% reduction by 2050
Washington -Goal
•95% reduction by 2050
Avista Corp.2021 Electric IRP Appendices 664
How do I get involved with the
IRP?
•Breakout rooms today
•Provide written comments to Avista’s planning
team by March 5th.
•Provide written comments to your state’s
commission
•Join Avista’s Technical Advisory Committees
–Electric IRP
–Natural Gas IRP
–Energy Efficiency
•Future participation opportunities
–Equity
–Energy Assistance
–Distribution Planning
How to learn more:
https://myavista.com/about-us/integrated-
resource-planning
Email: [e-mail]
Washington UTC
www.utc.wa.gov
Electric Docket: UE-200301
Natural Gas Docket: UG-190724
Idaho PUC
https://puc.idaho.gov/
Oregon PUC
www.oregon.gov/puc
21 Avista Corp.2021 Electric IRP Appendices 665
Breakout Sessions •Generation Resource Selection &
Reliability
–Stay here or use registration link
–Webinar ID: 82608251 3174
•Energy Efficiency & Demand
Response
–https://us02web.zoom.us/j/82664724856?pwd=QzdUMk9zUE1n
RjViYTlXRkJ5S2p5UT09
–Meeting ID: 826 6472 4856
•Affordability & Equity
–https://us02web.zoom.us/j/88435288369?pwd=bGtNK3JYbTBCcktCV
2JMRE1sT09CZz09
–Meeting ID: 884 3528 8369
•Environmental Topics
–https://us02web.zoom.us/j/89096065417?pwd=M0FzYWZHdjhT
QlRRR2xwOSs4M1ByZz09
–Meeting ID: 890 9606 5417
•Natural Gas Service
–https://us02web.zoom.us/j/84369554229?pwd=YkZJc0ZrUm91N
VFSanNJNmxPaVB4UT09
–Meeting ID: 843 6955 4229
•Two 30 minute break out room
opportunities.
•You can access breakout rooms
by using the links in the chat box
or stay in this session
•Passcode: Avista
•Short presentation by Avista staff
(5 minutes)
•Opportunity to ask Avista staff
questions or provide comments.
•Any questions not answered today
will be available on the IRP Avista
website by March 12.
•Limit of 300 participants in each
room
22 Avista Corp.2021 Electric IRP Appendices 666
Breakout Session Ground
Rules
•Due to the large response to this public meeting, please limit oral comments and questions to 30
seconds.
•Avista will try to answer all questions.
•Avista will also provide written responses if we cannot fully address the question.
•Comments will be acknowledged and recorded.
•If you would like to make a comment or ask a question.
•Use the “raise hand” feature in the meeting controls.
•We will call upon each person to speak.
•Please comment on areas within the breakroom topic
•Please do not repeat questions or comments.
•If you have the same comments-please indicate in the chat box or send an email to [e-mail] with
your comment
•In the event we do not get to your comment or question in the allotted time, please email
[e-mail]
•Please limit comments or questions to resource planning-this means in relation to the energy we serve
and not the delivery of energy. If you have these questions or any others please see.
•http://myavista.com/smartmeters
•[e-mail]23Avista Corp.2021 Electric IRP Appendices 667
Resource Selection & Reliability Breakout Room
James Gall
Thomas Dempsey
Damon Fisher
Avista Corp.2021 Electric IRP Appendices 668
Resource Options
Clean Resources
Wind
Solar (utility and customer)
Biomass
Hydro
Geothermal
Nuclear
Fossil Fuel Resources
Natural gas peaker
Natural gas baseload
Coal (retention)
Customer generation
Demand Resources
Energy efficiency
Conservation
Load control
Rate programs
Fuel switching
Co-generation
Storage
Pumped hydro
Lithium-ion batteries (utility & customer)
Liquid air energy storage
Flow batteries
Hydrogen
•Multiple factors drive resource selection
•Cost or price
•Clean vs. fossil fuel
•Capacity value or “peak credit”
•Storage vs. energy production
•Location
•Availability (new vs. existing)
•Resource retirements
•Future capital investment
•Operating & maintenance cost/availability
•Fuel availability
•Carbon pricing risk
•Non-energy costs & benefits
•Social cost of carbon
•Locational siting
•Health, economic, and other benefits (still to
come)
25 Resources in italics were not directly modeled for this IRP
Avista Corp.2021 Electric IRP Appendices 669
Supply-Side Resource
Changes
Resource Type Year State Capability (MW)
Colstrip (Coal)By end of 2025 System (222)
Montana wind 2023 WA 100
Montana wind 2024 WA 100
Lancaster (Natural Gas)2026 System (257)
Post Falls Modernization (Hydro)2026 System 8
Kettle Falls upgrade (Wood-Biomass)2026 System 12
Natural gas peaker 2027 ID 85
Natural gas peaker 2027 System 126
Montana wind 2028 WA 100
NW Hydro Slice 2031 WA 75
Rathdrum CT upgrade (Natural Gas)2035 System 5
Northeast (Natural Gas)2035 System (54)
Natural gas peaker 2036 System 87
Solar w/ storage 2038 System 100
4-hr storage for solar 2038 System 50
Boulder Park (Natural Gas)2040 System (25)
Natural gas peaker 2041 ID 36
Montana wind 2041 WA 100
Solar w/ storage 2042-2043 WA 239
4-hr storage for solar 2042-2043 WA 119
Liquid air energy storage 2044 WA 12
Liquid air energy storage 2045 ID 10
Solar w/ storage 2045 WA 149
4-hr storage for solar 2045 WA 75
Supply-side resource net total (MW)1,032
Supply-side resource total additions (MW)1,589
•Long-term acquisition of new resources
will be conducted with a public request for
proposals (RFP).
•Avista recently added the Rattlesnake Flat
Wind project in 2020.
•Avista is currently working with clean
energy proposals from is most recent
RFP-this RFP will determine a portion of
the resource need in 2023-2024.
•New resource selection is determined by
deliverability and lowest economic cost
subject to resource policy requirements of
each state
26 Avista Corp.2021 Electric IRP Appendices 670
Energy Efficiency and Demand Response Breakout
Room
Ryan Finesilver
Leona Haley
Avista Corp.2021 Electric IRP Appendices 671
Energy Efficiency &
Demand Response
Energy Efficiency Program
Program designed to “incent” customers to make energy efficiency choices
Integrated Resource
Planning
Preferred Resource Strategy selects “measures” and sets target
Conservation Potential
Study to determine overall
conservation potential
4.4
6.1
7.5
10.0
10.0
11.5
19.0
21.9
31.9
35.4
42.0
60.9
62.7
64.3
135.3
Appliances (Res)
Miscellaneous (C&I)
Water Heating (C&I)
Interior Lighting (Res)
Miscellaneous (Res)
Other (C&I)
Electronics (Res)
Space Heating (C&I)
Exterior Lighting (C&I)
Ventilation (C&I)
Cooling (C&I)
Motors (C&I)
Refrigeration (C&I)
Water Heating (Res)
Space Heating (Res)
Interior Lighting (C&I)
10-YEAR GWH
CONSERVATION
POTENTIAL
Demand Response
Program Washington Idaho
Time of Use Rates 2 MW (2024)2 MW (2024)
Variable Peak Pricing 7 MW (2024)6 MW (2024)
Large C&I Program 25 MW (2027)n/a
DLC Smart Thermostats 7 MW (2031)n/a
Third Party Contracts 14 MW (2032)8 MW (2024)
Behavioral 1 MW (2041)n/a
Total 56 MW 15 MW
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Capacity
Energy Use
DR EventsDR Events
28 Avista Corp.2021 Electric IRP Appendices 672
Natural Gas Energy
Efficiency
Residential,
57%
Commercial,
41%
Industrial,
2%
0.03
0.04
0.16
0.33
0.42
1.27
4.8
5.14
5.78
0 1 2 3 4 5 6 7
HVAC
Appliances
Process Heating
Cooking
Ventilation
Other
Weatherization
Water Heating
Space Heating
Millions of Therms
29 Avista Corp.2021 Electric IRP Appendices 673
Affordability and Equity Breakout Room
Ana Matthews
Shawn Bonfield
Renee Coelho
Lisa McGarity
Avista Corp.2021 Electric IRP Appendices 674
Energy Rate Forecasts
Electric Rates:
•To meet Avista’s reliability requirements
and Washington clean energy policies
electric rates will increase.
•Today, Washington rates are ~1 cent
(12%) higher per “average” kWh.
•Going forward the difference between
Washington and Idaho rates will
continue to separate.
•Both Idaho and Washington customers
financially benefit by lower rates unless Idaho’s
share of clean resources are kept in Idaho.
Natural Gas Rates:
•Natural gas rate increases are driven by
increases in the price to acquire the
natural gas commodity and general
inflation to operate the system.
31
Electric Power Cost Rate Changes
Annual Average Natural Gas Rate Forecast
$1.0748
$1.0748 Idaho Washington Oregon
Note: Assumes 2%
annual increase in
non-energy
resource costs
Av
e
r
a
g
e

C
h
a
n
g
e
Avista Corp.2021 Electric IRP Appendices 675
Energy Equity and Energy
Assistance Overview Bill Assistance
LIRAP Heat
LIRAP Senior/Disabled Outreach
Emergency Assistance
LIRAP Emergency Share
COVID-19 Hardship
Rate Discount
Senior/Disabled
To Be Implemented
Percent of Income Payment Plan
Arrearage Management Program
Conservation Education
Energy Fairs
Workshops
General and Mobile Outreach
Energy Efficiency
Low-Income Weatherization
•Washington State’s recently passed
legislation CETA (Clean Energy
Transformation Act) requires
•equitable distribution of energy benefits and
reduction of burdens to vulnerable
populations and highly impacted
communities;
•long-term and short-term public health,
economic, and environmental benefits and
the reduction of costs and risks;
•and energy security and resiliency.
•It is the intent of the legislature that in
achieving this policy for Washington,
there should not be an increase in
environmental health impacts to highly
impacted communities.
Low-Income Rate Assistance Program (LIRAP)
32 Avista Corp.2021 Electric IRP Appendices 676
Environmental Topics Breakout Room
John Lyons
Bruce Howard
Avista Corp.2021 Electric IRP Appendices 677
Avista’s Environmental
Footprint
-1.0
-0.5
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
20
4
3
20
4
4
20
4
5
Current Resources
New Resources
Net Market Transactions
Upstream/Construction/Operations
Net Emissions
2019 Generated Emissions
Dispatched Emissions w/ Colstrip Operating to 2025
•By 2030, Avista’s greenhouse gas
emissions fall by 76 percent.
•2019 Northwest power emissions were
57 million metric tons (Avista is 5.2% of
those emissions).
•Power is 20% of all NW greenhouse gas
emissions.
•Total emissions are determined by utilization of
facilities and control technology.
•NOx emissions fall by over 50% due to smart burn
technology at Colstrip coal fired facility,
•VOC emission rise is due to increased plant
utilization and new testing at the Kettle Falls
Biomass facility,
34
-75%
-50%
-25%
0%
25%
50%
CO2 SO2 NOx Hg VOC
Total Change in Air Emissions Since 2015
Greenhouse Gas Emissions Forecast
Avista Corp.2021 Electric IRP Appendices 678
Natural Gas Breakout Room
Tom Pardee
Michael Whitby
Jody Morehouse
EnvironmentReliability
Affordability
Avista Corp.2021 Electric IRP Appendices 679
Carbon Reduction
Pathways
Power to Gas with Hydrogen
•Renewable electricity converts water to hydrogen
•Hydrogen is combined with waste CO2 to make RNG
•RNG flows through existing natural gas pipelines to
end users
Renewable Natural
Gas (RNG)
•Biogas from
decomposing waste
streams is captured
•The gas is scrubbed to
pipeline quality RNG
•RNG flows through
existing natural gas
pipelines to end users
36 Avista Corp.2021 Electric IRP Appendices 680
Natural Gas is Critical to a
Clean Energy Future
•In the right applications, direct use of natural gas is best use
•Natural gas generation provides critical capacity as renewables expand until utility-scale
storage is cost effective and reliable
•Full electrification can lead to unintended consequences:
•Creates new generation needs that can increase carbon emissions
•Drives new investment in electric distribution infrastructure, causing bill pressure
•Home and business conversion costs borne by customers
•Puts at risk energy reliability and resilience, energy choice, and affordability
•Customers have paid for a vast pipeline infrastructure that can utilized for a cleaner future by
transitioning the fuel and keeping the pipe
•A comprehensive view of the energy ecosystem leads to a diversified approach to
energy supply that includes natural gas
37 Avista Corp.2021 Electric IRP Appendices 681

Avista Corp.2021 Electric IRP Appendices 682

2021 Electric Integrated
Resource Plan

Appendix B – 2021 Electric IRP
Work Plan

Avista Corp.2021 Electric IRP Appendices 683

1

Work Plan for Avista’s
2021 Electric Integrated Resource Plan

For the Washington Utilities and Transportation Commission &
Idaho Public Utility Commission

April 1, 2020

Avista Corp.2021 Electric IRP Appendices 684

2

2021 Electric Integrated Resource Planning (IRP) Work Plan
This Work Plan is submitted in compliance with the Washington Utilities and Transportation
Commission’s Integrated Resource Planning (IRP) rules (WAC 480-100-238). It outlines the
process Avista will follow to develop its 2021 Electric IRP for filing with the Washington and Idaho Commissions by April 1, 2021. Avista uses a public process to solicit technical expertise and feedback throughout the development of the IRP through a series of Technical Advisory
Committee (TAC) meetings and uses a combination of social media and public outreach event to
include the general public.
The 2021 IRP process will be similar to those used to produce the previous IRPs, but with changes to better align assumptions with the Natural Gas IRP. Exhibit 1 shows the planned 2021 IRP
timeline for work products. Avista plans to use Aurora for electric market price forecasting,
resource valuation and for conducting Monte-Carlo style risk analyses of the electric marketplace.
Aurora modeling results will be used to select the Preferred Resource Strategy (PRS) and alternative scenario portfolios using Avista’s proprietary PRiSM model. This tool fills future capacity and energy (physical/renewable) deficits using an efficient frontier approach to evaluate
quantitative portfolio risk versus portfolio cost while accounting for environmental laws and
regulations. Qualitative risk evaluations involve separate analyses. Avista plans to utilize its
proprietary Avista Decision Support System (ADSS) model to conduct analyses to evaluate reserve products such as ancillary services and intermittent generation. Avista also plans to use its Avista Reliability Assessment Model (ARAM) to validate resource adequacy and resource peak
contributions (ELCC) as introduced in the 2020 IRP. Avista contracted with Applied Energy
Group (AEG) to conduct energy efficiency and demand response potential studies.
Avista intends to use both detailed site-specific and generic resource assumptions in development of the 2021 IRP. The assumptions will utilize Avista’s research of similar generating technologies,
engineering studies, and the Northwest Power and Conservation Council’s studies. Avista will rely
publically available data to the maximum extent possible and provide its cost and operating
characteristic assumptions publically. The IRP may model certain resources as Power Purchase Agreements (PPA) rather than Company owned because these third party provided resources are more likely to be lower cost.

Avista intends to create a PRS using market and policy assumptions based on the results of newly
implemented rules from the Clean Energy Transformation Act (CETA) for Washington and using the least cost planning methodology in Idaho. The plan will also include sections outlining the key components of the Washington Clean Energy Action Plan and an Idaho Preferred Resource
Strategy. The IRP will include a limited number of scenarios to address alternative futures in the
electric market and public policy. TAC meetings help determine the underlying assumptions used
in the IRP including market scenarios and portfolio studies. Although, Avista will also engage the general public using social media and a public outreach event. The IRP process is very technical and data intensive; public comments are welcome and we encourage timely input and participation
for inclusion into the process so the plan can be submitted according to the proposed schedule in
this Work Plan. Avista will make all data available to the public except where it contains market
intelligence or proprietary information. The planned schedule for this data is shown in Exhibit 2.
Avista Corp.2021 Electric IRP Appendices 685

3

Avista intends to release data prior to its discussion at its 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 the TAC members. This shortened IRP cycle will only
include five public meetings. The timeline and proposed agenda items for TAC meetings follows:

• TAC 1: Thursday, June 18, 2020: o TAC meeting expectations and IRP process overview, o Review of 2020 IRP Idaho acknowledgement,
o Update on CETA rulemaking process,
o Modeling process overview, including Aurora, ARAM, ADSS, PRiSM,
and assumption overview, o Generation options (cost, assumptions, ELCC), o Highly impacted community discussion (WA- CETA).

• TAC 2: Thursday, August 6, 2020 (joint with Natural Gas IRP TAC): o Demand and economic forecast, o Conservation Potential Assessment (AEG),
o Demand Response Potential Assessment (AEG),
o Natural gas market overview and price forecast,
o Regional energy policy update, o Gas/Electric coordinated studies, o Highly impacted community proposals.

• TAC 3: Tuesday, September 29, 2020: o IRP Transmission planning studies, o Distribution planning within the IRP,
o Discuss market and portfolio scenarios,
o Existing resource overview,
o Electric market forecast and scenarios.

• TAC 4: Tuesday, November 17, 2020: o Final resource needs assessment and resource adequacy,
o Ancillary services and intermittent generation analysis, o Review draft resource plans for each state and scenarios.
• TAC 5: Thursday, January 21, 2021:
o Review draft IRP,
o Final state resource plans and scenarios, o Draft Clean Energy Implementation Discussion,
o 2021 IRP Action Items,
o Initial comments from TAC participants.

• Public Outreach Meeting, February X, 2021
Avista Corp.2021 Electric IRP Appendices 686

4

2021 Electric IRP Draft Outline
This section provides a draft outline of the expected major sections in the 2021 Electric IRP.
This outline may change based on IRP study results, CETA rulemaking, and input from the
TAC. 1. Executive Summary 2. Introduction, Stakeholder Involvement, and Process Changes
3. Economic and Load Forecast a. Economic Conditions
b. Avista Energy & Peak Load Forecasts
c. Load Forecast Scenarios 4. Existing Supply Resources a. Avista Resources
b. Contractual Resources and Obligations 5. Energy Efficiency Potential Study 6. Demand Response Potential Study
7. Long-Term Position a. Reliability Planning
b. Resource Requirements
c. Reserves and Flexibility Assessment 8. Transmission Planning
a. Overview of Avista’s Transmission System b. Future Upgrades and Interconnections c. Transmission Construction Costs and Integration
d. Merchant Transmission Plan 9. Distribution Planning a. Overview of Avista’s Distribution System
b. Future Upgrades and Interconnections 10. Supply Side Resource Options a. New Resource Options
b. Avista Plant Upgrades 11. Market Analysis a. Wholesale Natural Gas Market Price Forecast
b. Wholesale Electric Market Price Forecast c. Scenario Analysis
12. Washington- Clean Energy Action Plan
a. Preferred Resource Strategy b. Highly Impacted Community Analysis
13. Idaho- Preferred Resource Strategy a. Preferred Resource Strategy 14. Portfolio Scenarios
a. Resource Selection Process b. Efficient Frontier Analysis
a. Portfolio Scenarios
b. Resource Avoided Cost 15. Action Plan

Avista Corp.2021 Electric IRP Appendices 687

5

Draft IRP will be available to TAC members on January 4, 2021. Comments from TAC
members are expected back to Avista by March 1, 2021. 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: 2021 Electric IRP Timeline
Task Target Date

Due date for study requests from TAC members August 1, 2020
Writing Tasks
Comments and edits from TAC due March 1, 2021

Exhibit 2: Public Data Release Schedule
Task Targeted Release
Annual Capacity Needs Assessment

Avista Corp.2021 Electric IRP Appendices 688

2021 Electric Integrated
Resource Plan

Appendix C – Public
Participation Comments

Avista Corp.2021 Electric IRP Appendices 689
Appendix C: TAC Comments Page 1
Appendix C:
Public Participation Comments
IRP Comments Provided by Technical Advisory Committee Members

Commenter Comment Avista Response
Conservation
League
1. We request Avista compare the results of this Idaho-
specific study to the results of the same analysis at the system-wide level. 2. We request Avista compare the results of this Idaho-specific study to the results of the same analysis at the system-wide level. 3. We also request a study that documents the costs to
implement, monitor and document the state-specific addition of resources to an interconnected system
energy by 2045.
2. Avista split resources and costs between its jurisdictions to understand the effect to each state. 3. All costs to meet resource requirements by state is included in the PRiSM model. The model is publicly available in Appendix I. Also, summary level information is provided in the IRP Chapter 11 and 12.
Conservation League 1. We request Avista study a scenario that applies the Social Cost of Carbon to all resources, including those that serve Idaho, as offered in the first TAC meeting. 2. We request Avista study scenarios for Colstrip costs that reflect the changing ownership shares currently
being considered by co-owners Puget Sound Energy, Northwestern Energy, and Talen. Further, we request a study of likelihood and scale of increases to Avista’s share of common plant costs, remediation costs, and fuel supply costs, including minimum fuel supply and generation off-take, attributable to both the closure of Units 1 and 2 and the changing ownership share of Units 3 and 4.
3. We request a study of the accuracy of Avista wholesale natural gas price forecasting methodology by comparing forecasted prices in prior IRPs to prices Avista actually paid. We request this study include a comparison of the accuracy of consultant-supplied forecast to publicly-available forecasts covering the
2. Regarding the change in ownership percentages for Units 3 and 4, there are no changes to Avista’s responsibilities or modeling inputs to alter because Avista’s 15 percent share of both units remains static under the Colstrip ownership agreement. Avista’s financial responsibility for the plant
remains the same regardless of the non-Avista ownership or ownership percentages for Units 3 and 4. As in the last IRP, Avista is accounting for the shift (increase) in previously shared costs that are a result of the closure of units 1 and 2. Those costs increased, but Avista’s share of those costs did not change. Avista has zero responsibility for the remediation costs associated with Units 1 and 2. The closure of those units did not end the financial responsibility of those remediation
costs for the owners of those units (Puget Sound Energy and Talen). Avista’s fuel contract is separate from the contracts that supplied Units 1 and 2. Avista’s fuel contract and any subsequent mine remediation costs with our share of coal are already included in the prices being modeled in the 2021 IRP, consistent with past IRPs.
Avista Corp.2021 Electric IRP Appendices 690
Appendix C: TAC Comments Page 2
3. The natural gas price forecast beyond the shorter term forward markets is always an area of concern because of the potential for volatility, timing and magnitude of outside events,
much like the current pandemic we are now experiencing. It is in our own best interests to use good forecasts. Avista publishes its natural gas price forecasts in each IRP; including both consultant forecasts on an annual average basis. Actual natural gas prices are also publicly available. The consultants that we use work on a national as well as an international basis. They already perform their own internal analyses to make their forecasts as accurate as possible to maintain and
grow their business. We are paying for their expertise and research into the natural gas market. Avista has not seen any evidence indicating that there are better forecasts available and we do not possess the resources to develop comprehensive fundamentals based natural gas forecast on our own. Some forecasts, like those provided by the Energy Information Administration, supply some more details about the fundamentals they are using, but they are also more dated
and do not provide the level of granularity into specific trading hubs. These consultants would not be able to remain in business if they had to give away all of their research for free. Please let us know if you have found other evidence or research indicating better forecasts. Avista includes the
Conservation League 1. We request Avista model loads and generation at the sub-hourly level. We recognize Avista began pursuing
sub-hourly modeling in the 2017 IRP and further refined the ADSS system in the 2019 IRP. We request Avista fully implement sub-hourly modeling for all IRP studies and processes. 2. We request Avista study the optimal pairing of generation resources with storage of different technologies and lengths of supplying services. For example: pairing local solar or wind with Li-Ion 4hr, 6hr,
and 12hr batteries; pairing pump hydro resources with regional solar, wind, and wholesale markets; pairing long term storage like hydrogen electrolysis and
complexity and data availability. Further, modeling all sub-hourly periods is not technologically possible. Presently,
modeling at one-hour granularity requires thousands of hours of computer processing time. Moving to intra-hour modeling would cause an exponential increase in solution time even if the data was available. ADSS and other modeling techniques are used to evaluate intra-hour values, and generally rely on sampling of relevant time periods. This is specifically the case with the complexity of modeling storage resources. Avista is working on this issue and is hopeful it will be available in
future IRPs and will be added as an Action Item in the 2021 IRP if not completed for this plan. 2. As described in the first TAC meeting and distributed to the
Avista Corp.2021 Electric IRP Appendices 691
Appendix C: TAC Comments Page 3
associated hydrogen storage with Avista’s own resources and wholesale market generation.” 3. We request Avista study the emission reductions
possible from pairing storage with specific clean generation options along with the Proposal presented to the TAC to apply the average emissions rate of the region for storage paired to generic wholesale market resources.
and combined renewables plus storage options. The options being modeled include distribution scale 6-hour Lithium-ion; 4-
, 8- and 16-hour Lithium-ion; 4-hour Vanadium flow, 4-hour Zinc Bromide flow batteries; 16-hour 100 MW share pumped storage; and 100 MW solar photovoltaic with Lithium-Ion batteries. Avista is also modeling hydrogen using fuel cells or converted combustion turbines. Each of the hydrogen options will include long duration storage facilities as a backup to real-time deliveries. Avista’s IRP modeling includes the benefits from a portfolio optimization in its current process between
storage and renewable resources. Avista acknowledges there could be a benefit to pairing storage with renewables from a transmission perspective. The economic estimates of the IRP are exclusive of T&D investments. Although the locational benefits of storage paired with resources may not be optimal when considering other “better” locations to locate the storage. Avista agrees with this
concept and is trying to determine the best methodology to model these potential benefits, but the modeling of this concept may not be available in time for this IRP. It will be added as an Action Item if we are not able to develop the concept and include it in the 2021 IRP. 3. Avista includes regional emissions for storage not connected to a facility; for paired resources, Avista does not include the
emissions when using the paired resources. Although, over time as paired solar/storage resources are no longer obligated to use the paired resources storage technology to satisfy tax credit requirements will likely use a combined grid/local power for optimization of the system. [Avista’s PRS did not include storage emissions, but scenarios were conducted to
Conservation
League
1. To help encourage the optimal growth of DERs on the
Avista system, we request a Hosting Capacity Analysis. This analysis could support a distributed energy resource interconnection map that identifies where
on a public process for this type of planning. This process will
likely be separate from the IRP process, but will inform the IRP. More details of this process and its findings will be shared with the TAC as they develop.
Avista Corp.2021 Electric IRP Appendices 692
Appendix C: TAC Comments Page 4
benefit from energy storage or specific demand responses. This Hosting Capacity Analysis would
benefit the IRP’s load forecasting and overall integration of distributed energy within the IRP. We recommend Avista define DERs broadly for this study to include: customer-sited generation and storage, utility-sited generation and storage at substations or other locations on the distribution grid, as well as public and private electric vehicle charging stations.” 2.We request Avista incorporate different load shapes
that are indicative of customer generated power as wellas the charging of electric vehicles to ensure accuracyin the load shapes for supply-side resource planning.The Smart Electric Power Alliance has an informativeset of resources to help with this effort: https://sepapower.org/knowledge/proposing-a-new-
collected from its local system for both solar photovoltaics andelectric vehicles.
Conservation
League
1.With the technological changes of a modern grid
system, including flexibility in both supply and demandstudies is essential as we look to the future of electricservice areas. As shown in the pilot program with the Catalyst Building, the savings from energy efficiencyand flexible building loads can be extremely beneficialfor the electric grid as a whole. Similarly, the micro-transaction grid project in the Spokane UniversityDistrict is demonstrating the value of flexible loads and
new market opportunities for customers to manage theirpower bills. To fully explore the value that flexibilitybrings to Idaho customers, we request Avista study thepotential to expand similar projects in the Idaho serviceterritory. At minimum, a study to see the perspective ofcustomers’ willingness to participate in such a pilot
test bed for future projects and will take this under
advisement. Avista utilizes the University of Idaho for severalR&D efforts through a competitive grant process for a total of$270,000 to study efforts related to energy efficiency andflexible building loads. Example projects from the 2019/20academic year include: a program design for energy tradingsystem for consumers, using infrared cameras for buildingcontrols and gamification of energy use.
Conservation
League
1. Loads - study changes to both long-term load forecast
and the peak load forecast attributable to climatechange. The 2020 IRP mentions a 1-degree increase in
scenario, which was covered in the special TAC meeting on
August 8, 2020 after receiving this letter. Further, all loadforecast scenario data is available on the IRP website
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climate change is factored into the peak load forecast. The 2020 IRP also cites a temperature data set from 2013, which we recommend Avista update to the most
currently available set. 2. Hydro - study the potential changes to hydroelectric power generation that could result from climate-caused changes to precipitation type and timing. This study should document the range of impacts to power costs that result from the changes in hydroelectric power generation. 3. Thermal plants - study potential changes to expected
generation and production costs due to temperature changes. This study should include changes to expected generation and fuel costs as output varies with ambient temperatures and the impacts to cooling water needs due to changes in precipitation and water temperatures. The study should document the range of impacts to power costs due to the change in expected generation output, fuel needs, and cooling water
presentation. 2. We have obtained the climate adjustments developed by the
Power Council and included a scenario with these adjustments in Chapter 12. 3. Avista agrees temperature changes will impact the amount of production from its natural gas-fired facilities. This impact will was included in the climate change scenario.
Conservation League 1. The load forecast includes the baseline projection of electric charging services, as forecasted in the 2020 TEP. We also request scenarios that consider higher penetration of EV, especially for commercial fleets, delivery vehicles, and public transportation. 2. A study of how to optimize charging behaviors, including customer load management, and how to
optimize the location of public and workplace charging stations to avoid distribution grid overload while maximizing grid flexibility and benefits to the system. For example, the TEP identified that the $1,206 in electric system benefits per EV could “be increased by another $463 per EV when load management shifts
this time, Avista needs to focus on other scenarios for this IRP because of the limited amount of time available for modeling. 2. Avista is updating its EV and demand response program assumptions and this will be discussed at the September TAC meeting. Avista welcomes this discussion at the upcoming meeting to ensure it has robust assumptions for this IRP.
Solutions ductless heat pumps and water heater heat pumps. This is
in regards to the electrification scenarios. See attached letter in Appendix C- “Climate Solutions- Electrification End
Further detail regarding these comments are included in Appendix
C- “Climate Solutions Email Response.pdf”
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Northwest Power & Conservation
Council
diverge from the pricing regime shown in this draft IRP. While understanding the underlying cause of that
divergence would take a deep dive into our respective AURORA runs, given our work thus far we would expect that it’s related to allowing AURORA to construct new natural gas generation outside the Northwest to replace expected retirements in the WECC thermal generation fleet (and the associated volume of those retirements). We were given guidance from the Council and from our
advisory committees to limit the potential for new natural gas generation both inside and outside the region. In doing so, we see a wave of solar and wind generation construction that depresses future market prices substantially lowering them from prices seen today. While this is largely outside of the control of the region, it presents substantial risk to regional utilities making decisions consistent with market prices that assume natural gas
resources will set the marginal price. We’d encourage all the utilities in the Northwest, including Avista, to test any IRP-based decisions against an aggressively low market price forecast. Many things are uncertain about the future of the power system in the WECC. We would not want to represent any forecast, including our own, as certain. But we do think it’s a risk to
consider and one that will be developing rapidly over the next few years. While we’re still working on the 2021 Power Plan, we’d be happy to share an AURORA archive file of the work done to date.
extremely volatile, more than Aurora can quantify, much of this volatility will depend on how much and whether capacity resources
will be developed or not. It is appropriate to understand the risk of higher and lower prices. From analysis in the short term, Avista’s price forecasts are too low- specifically not including risk premiums we are seeing from resource adequacy issues we are seeing. Although, in the long run there is significant downward risk with more renewables- The future will depend on how far policy makers will take goals and ambitions to actual operations and construction.
There will also likely be a feedback loop as well- such as changes in loads (both industrial losses and electrification opportunities and political changes due to ramifications of policy changes) and storage opportunities. Its possible storage could be key in keeping prices from getting too low- but that will depend on future costs of that technology. In the end there is a number of paths the future may take us and its really an issue of how much time should we
make to look at the region versus our portfolio. The way things are trending there should be more focus toward our portfolio then market prices. In this case the real risk of having too low of forecast for prices could have an effect of less acquisition of EE, but in the end with our requirements of having clean energy and capacity- the price forecast really only impacts a solar vs wind decision- but so far
wind is winning that decision due to capacity requirements and over reliance of solar elsewhere; then they question of should we build natural gas or storage- that decision is likely a matter of carbon pricing at this point. So where I’m going is and have been pondering for some time do price forecasts really matter for resource planning- given we have fewer resources to choose from and specific requirements to meet. For example, the energy price used to be a major component of our EE avoided cost- now the
highest component is social cost of carbon and non-energy benefits- its seems the world has shifted from energy price
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Conservation Council Electric IRP_councilstaff.pdf” Most comments were regarding providing additional context for statements
Rye Seek further information regarding modeling and
assumptions for pumped storage
o “State of Charge” assumed (table 9.12)?
 Table 9.12 indicates an 8-hour pumped storage project would only contribute 30% to Avista’s
peak capacity need and a 12-hur project would contribute 58%. These are much lower than Swan Lake and Goldendale would expect and
drastically lower than those used by other NW utilities
 Swan Lake and Goldendale believe Avista is
using a very low state of charge possibly 20%
pond fill). This doesn’t align with the
operational realities associated with operating
hydro or pumped storage facilities.
 Import assumptions during off-peak hours in
the winter should be re-visted, given that these
would be key hours when long-duration storage would charge for the winter on-peak reliability
 Swan Lake and Goldendale recommend that
Avista consider optimizing the dispatch of their resource over a wide time window (1-2 weeks) allowing for greater flexibility and minimizing
the need for daily charging/recharging o What duration of useful life? o
2021 to discuss their comments
• Avista modelled several northwest pumped hydro projects
in the 2021 IRP; including Swan Lake and Goldendale, based on publicly available data. Avista believes some of these comments could be derived from the 2020 IRP. • Avista acknowledges Rye’s comment regarding re-charging capacity during off-peak hours. Avista disagrees with Rye that it can fully recharge a storage devise during off-peak hours of a northwest system peak event beyond the limits already included.
• Pumped hydro is optimized on a 1 year basis and not 1 to
2 weeks. • Avista uses a 50-year life to amortize capital costs.

• Given the state of Washington policy, Swan Lake and Goldendale request that Avista provide a detailed explanation for why a new gas resource would meet one of the few and limited CETA provisions allowing
construction of such resources, particularly including violation of reliability standards and, if violations are possible, whether pumped storage could help alleviate
Goldendale in its PRiSM model. Given information available, these projects were not cost effective compared to natural gas. Avista’s IRP is an indication of cost-effective resources, but a future request for proposals (RFP) will determine the most cost-effective resource acquisition.
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Rye Advocate that Avista issue a capacity RFP (strongly support)
• Swan Lake is expected to achieve commercial operation in late-2026
• Only accurate way for Avista to fully evaluate potential
pumped storage projects including various pricing
information, timing for construction and whether the
need.
Northwest levelized cost ($/kW) for the preferred 4-hour lithium-ion battery, as there appears to be a gradual price increase
after 2033 rather than a steady decline, which would be expected.
renewable RFP. Further, Avista also used publicly available studies for its future cost curves. One difference between our
forecasted cost could be they are in nominal dollars rather than “real” dollars. Avista’s storage costs are expected to decline significantly in “real” terms. Avista also recommends any suggestions regarding costs of resources come earlier in the process. Avista included these costs in its TAC meetings and posted all its cost information on its website six months prior to the
Northwest generation on a sub-hourly timescale to calculate the
balancing reserve requirements and the associated system costs and benefits to meet those intra-hourly dispatch requirements, as legally enforced through NERC’s BAL
ancillary services costs using its ADSS system. This process will
begin in 2021 Q2. Also Avista is considering Plexos for potential reliability studies and other work, but has not acquired the model at this time.
Northwest operational configurations and characteristics of hybrid resources and standalone storage to correctly evaluate the resource ELCC value.

next. Avista disagrees with using alterative ELCC values for storage resources based on its analysis of its system. Specifically, Avista is concerned with relying on short duration storage in winter months because of its high winter energy needs, lack of reliable
market power in critical events for recharging the system, and high
Northwest why Avista’s capacity needs can only be met with new natural gas peaking capacity, we recommend that Avista provide at its upcoming TAC meeting or publish in its final IRP a projected loss-of-load event, displaying by hour where there is a deficiency in available capacity. This could
information required to develop the 12x24 matrix. Avista agrees this could be a useful exercise and will consider developing this report in the next IRP as it continues to review ELCC studies.
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hours with the highest loss of load probability which were used to calculate the ELCC values for all resources.
Renewable Northwest analysis to better understand how policy-driven changes in
Avista’s resource mix should impact the way the Company plans for meeting demand reliably
remove Colstrip in 2022 (just as with the PRS) and follow the other
logical requirements of the Portfolio 5. This portfolio is the 100% clean energy portfolio by 2045.
Coalition efficiency and begins to lay out a strategy for acquiring demand response resources, although we believe the targets can be increased and the pace can be accelerated. The treatment of new renewable resources is somewhat more mixed, as described below. Finally,
significant improvement is needed for both the cost and capacity value battery and pumped storage.
Avista future. Avista agrees some programs will take time to ramp up to large savings and some rate restructuring programs will take time to develop and get approval through multi-jurisdictions. Regarding battery & pumped hydro, Avista continues to use the
best information publicly available for these resources. Avista even specifically modeled many of the Northwest proposed projects. Avista also recommends any suggestions regarding costs of resources come earlier in the process. Avista included these costs in its TAC meetings and posted all its cost information on its
Coalition substantial available and cost-effective clean energy resources that can defer or eliminate this new emitting these emerging technologies decline.
Coalition greenhouse gas emissions are considered and priced using the SCC”, but that the SCGHG was not applied to market purchases and sales in the PRS as done previously. The reason for the change from previous practice is not clear.
document. In summary, after consultation with WUTC policy staff, Avista chose not to include the SCGHG/SCC as part of the market transactions specially because the CETA does not require these costs for short term transactions. Avista did conduct a study to see the implication of the change. Avista will discuss this option again
Coalition natural gas generation, we urge Avista to revisit
this issue and adjust the upstream methane emissions factor represented in the Social Cost of Greenhouse Gas analysis.
approximately 10% of the natural emissions directly burned. By
including these emissions as part of the social cost of carbon exceeds regulatory requirements in Washington. While upstream methane emissions will always have uncertainty due to life expectancy and the variety of sources, Avista will continue to make the best estimates for these emissions given its fuel
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portfolio that is better aligned with CETA policy guidance while meeting reliability needs cost-effectively. The first stage involves maximizing the availability of so-called
“energy limited” clean flexible resources, including demand response and storage. These are generally considered to provide capacity value of 4 hours duration and should suffice for meeting needs during typical peak periods. In the second stage, meeting rare long-duration peaks requires supplemental resources. The draft IRP suggests that new peakers can meet these supplemental needs. But once these very expensive and high-emitting new peakers
are put into the resource mix, the IRP models will dispatch them not only for very infrequent long duration high peaks, but much more often across the year because they are now “existing” resources. As a result, these new peakers will displace less expensive, non-emitting resources. This creates a lost opportunity for CETA compliant clean energy
Specifically the options to acquire resources for a5 to 10 year period will allow for a staged acquisition of cleaner resources that
may potentially become available in the 2030s. While the IRP does a great job at evaluating new resources this shortcoming means IRPs will always identify a resource mix that may differ from the actual resource acquisitions obtained through an RPF or another competitive bidding process. Avista anticipates significantly more cost effective cleaner resource options will be available as it acquires new resources.
Coalition for DR at 90 MW in 2025 (about 5.1% of peak load) and
170 MW in 2045 (almost 10% of peak). NWEC agrees that this is a reasonable magnitude for total potential, but we
demand response. Avista modeled these programs to be available
to begin in any year and optimized our system over the full 24 years. Beginning programs earlier will add cost to customers prior
Coalition simply don’t seem reasonable. The values in Figure 9.1 show slight declines in battery costs, and then flat or rising costs through the remainder of the planning horizon. Most other estimates show consistently declining costs through the coming decades, though at varying rates.
best information publicly available for these resources. Avista even specifically modeled many of the Northwest proposed projects. Avista also recommends any suggestions regarding costs of resources be submitted to the Company earlier in the process as they’re more likely to be able to be included. Avista included these
costs in its TAC meetings and posted all of its cost information on
Coalition reasonable chance of commercial operation by 2027, and found to be cost effective compared with a new natural gas
Coalition encourage revisiting this key issue. Hybrid resources could provide a significant capacity benefit and defer the need for new gas peakers, as well as make more effective use of limited available transmission capacity for renewables and
conduct further ELCC analysis to ensure proper peak credits of these resources so Avista customers have a reliable system.
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WUTC Staff Clean Energy Action Plan • Add a table to the CEAP that includes year-over-
year capacity of all planned resources, including
demand response. • Include planned Appendix G with details of about
planned transmission and distribution
year transmission plan and its 2019/2020 System Assessment
Climate change • Provide discussion regarding the implications of
possibly moving from a winter peaking utility to a
analysis in Chapter 3 and Appendix K. Further, Avista modeled a portfolio scenario in Chapter 12, outlining the changes in resource
Load Forecasting • Clarify the date in which its economic inputs were finalized. • Discuss any adjustments to the forecast made in
response to the ongoing pandemic. • Clarify the high and low load growth ranges used on page 3-14. For example, how did the company settle on the high and low assumptions for annual service area employment and population growth outlined in table 3.3? Please explain.
• Discuss the assumptions behind the EV and solar
PV forecasts that are inputs into the load forecast. • Clarify which of the two climate change forecasts

Upstream Emissions & SCGHG • Include in the narrative description required by
WAC 480-100-620(11) a clear articulation of how the company calculated the SCGHG. • Discuss assumptions about the SCGHG in market purchases and charging storage resources with market purchases. • Explain why 1.0 percent is an appropriate upstream
greenhouse gas analysis in chapters 9 & 11. Regarding the upstream emissions, this is in relation to the Natural Gas IRP.
Sub-hourly Modeling Capabilities • Clarify storage cost assumptions.

Chapter 9.
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WUTC Staff Customer Benefit Provisions in CETA • Provide a scenario or, at minimum, a narrative
regarding possible changes to resource decisions
that could increase customer benefit. • If available and time permits, incorporate the DOH
maximum customer benefits. Avista is also planning to engage a consultant to help estimate non-energy impacts for further analysis
regarding customer benefits. These changes may be available in the CEIP, but at minimum the 2023 IRP. Unfortunately, the DOH data was not available for the 2021 IRP.
Resource Adequacy and Uncertainty
• Clarify the company’s peak credit methodology,
including the definition of “peak” terms. • Explain how the company incorporates uncertainty
Chapter 9. Regarding the uncertainty of the RA assessment, Avista added information in Chapter 7 using the risk topic discussed in the “Implications of regional resource adequacy
Public Participation
• Provide an IRP update based on any recent
planned resource acquisition.
complete in time for the 2021 IRP. Avista plans to update the WUTC with a new Clean Energy Action Plan if any contracts are
Data Disclosure • Ensure appendices include a record of stakeholder feedback and the company’s response. • Provide context for the data files provided on the
comments from TAC members as well as Q&A and comments from the Company’s Public IRP meeting.
Natural Gas Design Day (Planning Standard) • Explain the new design day methodology.
• Explain why the new design day standard is now
Renewable Natural Gas
• Include details of RNG cost assumptions in the
scenario included in the 2021 draft IRP. Why the change
from last year?
Avista included the Lancaster PPA extension analysis in the 2020 IRP based on a request by the Idaho Commission staff. For the
2021 IRP, no such request was made until now, so it was not included as a scenario. Given we do not have a firm price for a PPA extension, or any other existing resource, we don’t think it would be appropriate to include it in the public IRP. One of my concerns with IRPs, is it is predominantly based on acquiring new resources and often does not or cannot do a good job of illustrating resource choices when existing resources are available. The IRP shows the resource options for new resource
choices and does a relatively poor job at studying existing
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the end, the IRP is a way to calculate the avoided cost of new generation or demand-side resources. The plan showing a need for new natural gas CTs does not preclude us from acquiring a
different resource that is a better solution for customers through an RFP or another acquisition strategy. We have recognized our IRP analysis needs to improve how we review existing resource options and that has been identified as an Action Item for the next IRP to determine the best way to include the potential to extend
Lancaster PPA extension scenario? It seems unlikely to us that choosing not to extend the Lancaster PPA and turning
around to immediately add 210+ MW of new peaking capacity in 2027 would be economically advantageous enough (compared to a Lancaster PPA extension scenario)
shows natural gas is a viable option. The decision for an existing plant vs a new facility or any other option is best decided in an
RFP rather than an IRP. In the future, if Lancaster should be considered in the IRP, Tyre should provide the IRP team with firm pricing for the resource option.
that would be used for a Lancaster PPA extension scenario? We’d like to understand what level of operational flexibility would be assumed in a Lancaster PPA extension
of the machine. As you know we are transitioning to more intermittent resources will require us to have more ramping and start/stop requirements.
Hersett alternatives evaluated to determine relative economics of the three approved new generation types, wind, solar and biomass here in the Inland Empire. We have the moral obligation to utilize the forests for the benefit of mankind not
resource option in the IRP. The KF upgrade was selected in the PRS, a new facility was not cost effective in the PRS but will be continued to be modelled as an option.

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Avista’s Integrate Resource Plan Public Meeting
February 24, 2021

These are results of the poll questions given to the audiences in both the webinar and breakout
rooms sessions.

Webinar Poll Questions
1. What would you prioritize among the choices below, acknowledging they are all important? • Environmental Issues: 32 • A Reliable System: 75 • Affordability: 33
2. Which Avista system provides more energy to its customers?
• Natural gas: 66 (this answer is most correct)
• Electric: 69

3. If Avista were to offer a voluntary program to charge higher prices during 4:00 pm to 8:00 pm in exchange for lower prices in other hours would you be interested?
• Yes: 77
• No: 59
Generation and Reliability Breakout Room
1. When Avista acquires new generation resources- where should they be located? • Indifferent to where resources are located: 6 • All of the above: 26 • Within our local communities: 9
• Within our service territory, but not in our local communities: 6 • Outside the service territory (i.e. another state or Canada): 1 2. To meet reliability needs in the next 5 years, how should Avista meet this requirement
• Acquire natural gas generation with a modest environmental footprint- medium cost alternative: 33
• Acquire storage resource with low operational environmental footprint- highest cost
alternative: 11
• Utilize customer outages to stabilize the grid- lowest cost alternative: 2

Affordability & Equity Breakout Room
1. How much of your electric bill should go towards assisting or improving the lives of individuals and communities who are economically disadvantaged?
• $0 per month: 6
• $5 per month: 9
• $10 per month: 6
• Other: 4
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2. What does an equitable transition to clean energy mean to you?
• Lowering their energy rates: 9
• Making their homes more energy efficient: 12
• Build clean generation resources within their community: 3
• Beautification of Avista assets: 1
• Other: 1
Natural Gas System Planning Breakout Room
1. If you could no longer use natural gas, which fuel would you likely use in its place?
• Electricity: 12
• Hydrogen: 2
• Propane: 8
• Renewable Natural Gas: 6
• Wood: 6
• Other: 3

Environmental Breakout Room
1. How should Avista best balance customer costs and environmental stewardship?
• Do the minimum to meet environmental requirements and keep energy rates as low as
possible: 1
• Be a partner and leader in environmental stewardship for a mod rate increase: 5
• Marginally exceed requirements for a small rate increase: 1
• Make environmental improvements and reduce impacts no matter the cost: 1

2. What is the most important environmental issue for you related to Avista?
• Reducing greenhouse gas emissions: 1
• Minimizing air pollutants such as particulate matter, volatile organics and nitrous/sulfur
dioxides: 3
• Being stewards of the water and natural resources of the Clark Fork and Spokane Rivers: 4

Energy Efficiency Breakout Room
1. In exchange for slightly lower energy costs, are you are interested in the utility controlling your thermostat?
• Never: 9
• No more than 20 hours per year: 1
• Yes, if I can override the request if I’m too cold or hot: 18

2. What is most important to you when you invest in energy efficiency for your home?
• Increase comfort: 4
• Reduce emissions: 4
• Savings on your bill: 20

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Questions from emails, breakout sessions, and chat box
For those of us who have solar panels on our roofs and are producing more
electricity than we use, what plans do you have to compensate us for our excess electricity?
kilowatt hour (kWh) compensation for their
generation. Generation produced by customers in excess of consumption is held in a ‘bank’, allowing kWh credit to be used in future months as needed. The intent of net metering is to offset your own usage, based on this intent any remaining kilowatt hour bank is reset annually in March, according to Schedule 095 in both Washington and Idaho. There are no current plans under the net metering program to provide compensation beyond the
banking provision. Please reference Schedule 095 in both Washington and Idaho for further details.
Electric Vehicle Questions Avista Response
plug-in vehicles (hybrid and pure electric)? publicly available at: www.myavista.com/transportation This plan includes Low, Baseline and High adoptions scenarios for light-duty vehicles considered in Appendix B. starting on p. 81. Given the current state of policy support,
industry investments, utility support, and local geographic and demographic considerations; we expect the trajectory of adoption to track between the medium and high scenarios in Washington, and between the baseline and low scenarios in
charging at preferred times of the day, when other demand is less? Plan, Avista has shown that utility programs leveraging EVSE
installations can accomplish this with participating customers. A new rate incenting off-peak charging may also be very effective, as demonstrated in other utility pilots and studies. Avista will continue to develop capabilities, with a goal to shift 50% or more of EV peak loads to off-peak in a cost-
more places to charge such vehicles, like
in high use areas (central parking lots, shopping malls, park-and-ride lots)?
charging infrastructure, up to 50% of the assessed market
need. A variety of other programs and incentives including
“make ready” investments, and a new commercial EV rate, will
help encourage additional private investment. See the TE
emissions, is there a plan to convert and cost effectively. See TE Plan pp. 72-73.
cars been added to the percent of
emissions as a long term cost? shown in the TE plan on pages 41-42, based on Avista’s
generation mix. Likely emissions in the future based on effects
from battery waste and other factors are very uncertain but
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discussion related to battery research and development, including second-use and recycling. The future state of battery technology and production will most likely differ greatly from
impact to be from the forthcoming increase in electric vehicles and how will you
prepare for that?
electric vehicles by 2045. The Company prepares for changed in forecasted load through this biennial resource
planning process and issue RFPs for various resources as
Policy Questions Avista Response
Washington State's population-reducing polices? What plans do you have if the population is killed by lack of heat?
explicitly intended to reduce population. Our engagement in
public policy is first and foremost focused on the cost-effective
operation of our energy system and the economic vitality of
the communities we serve.

Avista has an obligation to serve its customers electric and natural gas demands. When developing its resource plan, it
determines the expected customer demand and the amount of resources and types of resources that can actually meet this target using standard utility practices. Avista plans for resources to meet a 1-in-20 standard. This means it has enough resources to meet all customer load in 19 of 20 possible extreme weather events.
eliminate natural gas in new residential and commercial buildings by 2030 and to replace gas by heat pumps. At colder temps, heat pumps stop producing heat efficiently and can cause a spike in demand. Your presentation includes
customer choice for residential heating. Avista agrees that electric heat pumps lose their efficiency at lower temperatures and an “electrification” policy that requires customers to convert their natural gas heating systems to electric heat pumps will increase electric peak loads, among other impacts.
businesses, the main targets of efficiency efforts, will the harsh legislative regs. drive commercial and industrial businesses our of our region? Result, loss of jobs as well as revenue losses?
viability of businesses and shares the concern that such
policies will have dislocation impacts on business and workers. Avista’s energy efficiency analysis shows commercial and industrial businesses have opportunities to save energy economically while maintaining current requirements by installing more efficient technology. Avista’s energy efficiency programs will assist these customers with cost effective financial incentives. Lastly, the expected energy cost savings
Environmental Avista Response
natural gas companies that use fracking and other means to obtain natural gas? is delivered through the pipeline system. Natural gas from all sources is mixed together, and gas from wells that used fracking technology makes up the majority of natural gas currently. The environmental issues associated with drilling for
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focused on the fracking process.
Avista carefully manages natural gas once we receive it from pipelines. We were a founding member of the EPA’s methane challenge in demonstrating our leak detection and maintenance efforts. In addition, natural gas producers are increasing efforts to reduce emissions of natural gas production and make this energy source more sustainable. See https://www.aga.org/natural-gas/clean-
technology to create a carbon free source of power, electricity? What about Gen IV Nuclear? Is there any movement toward building these very
IRP analysis to determine if any specific offerings fit our resource needs. Currently Avista finds this technology not to be cost effective. Like others, we are watching to see how new emerging nuclear technology performs and how the cost changes as the technology develops.
align/don't align with Inslee? In particular, the use of natural gas, which I understand
Inslee wants to limit or get rid of entirely.
part of the Washington State legislative landscape. We continue to engage in legislative settings to promote clean
energy solutions that are affordable and which support reliability for our customers. Regarding natural gas, a specific bill was introduced during the 2021 legislative session. While this bill has not advanced, we will continue to work with our legislators and regulators on ways to address emissions
as machinery and maintenance cost) is there on the act of compressing natural
gas?
compressor to less than 1% of the original volume. While energy is needed for such compression and there are
emissions associated with the compression process, the net effect of using CNG as a transportation fuel is reduced emissions. All fuel delivery systems, including CNG, include ongoing maintenance costs for machinery.
that it is my understanding, backs up the intermittent power from wind farms like the one in Pullman? Is it really that "dirty"? If
the tribes don't want to run it, can't Avista lease it? Can you build a new state of the art coal plant? Coal presently provides over 60% of all electricity in the U.S. Our plans are super scrubbing in the U.S.!!
Washington State law prohibits the delivery of coal-fired energy to customers after 2025. Colstrip is also subject to other state and federal environmental regulations, which
continue to evolve. As one of six owners of the plant, Avista cannot independently determine Colstrip’s future. We will continue to evaluate the role that Colstrip plays in meeting our customers’ energy needs, and also how Colstrip’s future impacts communities, including Tribes, in Montana. We rely on thermal generation from Colstrip, natural gas-fired plants, and our biomass plant in Kettle Falls, along with our significant hydro resources, to back up intermittent
renewables. Consideration of this need is one of the key
consider methane emissions? are working to reduce emissions associated with natural gas and developing additional strategies with that in mind. Our natural gas IRP discusses the current state of these efforts, which we expect to build on and communicate further. Also
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with relicensing the existing dams in the network? 1999, receiving a license from FERC for 45 years. We relicensed the Spokane River hydro project in 2009, receiving a 50-year license. While we don’t have “relicensing” issues, we are implementing agreements with numerous local, state, federal and tribal partners on both river systems. These collaborative efforts imbed flexibility in what specific projects we undertake, for the benefit of our customers and the natural resources associated with these rivers. Please see
https://www.myavista.com/about-us/celebrate-our-rivers for
Methane, the primary component of natural gas, for the first 5-10 years is 100 times the greenhouse gas potential of CO2.
Gas Emissions is mostly from changes away from coal?
Yes, Avista’s forecasted reduction in greenhouse gas will be primarily from exiting the Colstrip Coal plant. The second largest reduction could be utilizing other resources rather the buying power from the Lancaster Generation Station that uses

for solar or geothermal heat pumps. Plans to send out pamphlets, for swamp coolers, on demand water heaters, or ways to transition to higher demand.
energy use. We work with developers regarding solar for residential and industrial plans in various ways. The IRP includes some of those plans. In the IRP, we look to fill resource needs by reviewing available options for new energy efficiency and demand response programs. Our energy efficiency team looks at developing programs based on the
results of those plans. We are also adding another advisory group in Washington to reach out to communities for input about ways we can be most helpful to them within the next year. Some incentive programs are prescriptive, like lighting, while others are customer specific and require working with engineers to implement (usually for commercial and industrial customers). We have information on our website for programs for energy efficiency as well as placing solar on homes.
There’s a solar evaluation estimator tool that will provide solar potential for specific addresses in our service territory.
the low Snake River have on electric resources?
Avista does not purchase power from the Snake River Dams. The impact of the current proposal on Avista seems at this time to be indirect. However, its effect on communities served by the company could be significant. It could also have regional ramifications of clear interest to Avista. Gauging the precise extent and nature of the proposal’s potential
implications is difficult without more specific information about replacement generation and other measures (conservation, demand response, transmission upgrades) that the proposal
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be required to discontinue ownership of Colstrip based on the new laws that are
under discussion (should those new laws
customers in 2025 per the Clean Energy Transformation Act in 2019. The law does not require us to discontinue ownership of
the plant and Avista must make future decisions about the
technology for variable renewables. resource planning as options to meet customer demand. These options include lithium-ion, pumped hydro, liquid air, hydrogen, and flow batteries. These technologies may be pursued in the future if they are an economic method of
impacts to fisheries due to the construction
and operation of the hydroelectric facilities? The dams on the Spokane River are initially responsible for the complete extirpation of salmon in that basin. Avista should have some responsibility for recovering those runs and the communities
Fork and 6 on the Spokane River. Went through an extensive
licensing process working with local tribes, state and federal agencies, and hundreds of stakeholders ranging from 5 to 7 years to work out the issues involved with the dams. Every week we work with the numerous tribes regarding the fisheries and bringing the steelhead back up to the upper regions. We do a lot of work together over those issues.
do not know the environmental cost of
solar waste from worn out panels long
this issue in upcoming plans regarding total life-cycle costs
and the wastes associated with worn out solar panels.
the deployment of EVs on a large scale, not only Avista's service fleet but also to private citizens but most of the Northwest doesn't have the EV charging infrastructure to support this market
change. Is Avista working to address this because that is a massive increase electric
area and its own fleet. The IRP includes this additional expected demand as part of our plans, but actual EV adoptions will depend on customer demand. Avista is committed to breaking down barriers to increase its adoption. Please see the EV section of these questions and answers for
more details about Avista’s EV plans.
energy consumption? These 5-year implementation programs started in Washington
stricter laws in Oregon and Washington do not equate to my power needs being met by a higher percentage of coal-based
power. As new laws are passed, and since Avista has a plan to phase out from Colstrip, is it possible to assume that this coal-based power supplier will be closed?
percentage of Idaho’s energy portfolio at this time. Avista does need to acquire new resources to replace capacity beginning in 2026; it is possible, but highly unlikely coal will be chosen to
meet this need for Idaho customers. This issue will be brought up with the Idaho Public Utility Commission and they will review and approve any plans for phasing out coal power being used to serve Idaho customers with input from customers.
salmon” and an acknowledgement of the successes in increasing salmon runs after
hugely costly efforts.
a state of the salmon, refer to this federal site https://www.nwcouncil.org/reports/columbia-river-
history/planningfishandwildlife.
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for wind farms and solar, be built at a 2025 and new coal is more expensive than other technologies

Equity & Affordability Avista Response
Equity of what? to ensure “that all customers are benefitting from the transition to clean energy: Through the equitable distribution of energy and noneenergy benefits.” RCW 19.405.040(8) “Equitable distribution” means a fair and just, but not necessarily equal, allocation intended to mitigate disparities in benefits and burdens, and based on current conditions, including existing legacy and cumulative impacts, which are
informed by the assessment described in RCW 19.280.030(1)(k) from the most recent integrated resource plan. In accordance with the rules, Avista staff is currently forming an Equity Advisory Group that will advise the utility on equity issues including, but not limited to, vulnerable population designation, equity indicator development, data support and
development and recommended approached for the utility’s compliance with WAC 480-100-610 (4)(c)(i). This advisory group will help determine the answer to the equity question
using your profits to pay for these upgrades? and to maintain a safe and reliable system. When the company invests capital in these assets, the State Commissions determine if these expenses are prudent. If they find them prudent, Avista will get recovery of these expenses,
if the expense is a capital investment, the company may earn a return on these investments. The Commissions also set the
how will the rate payers be charged for the increased cost on new "green" energy infrastructure? Will Idaho have to pay for the "green" energy that WA and OR want? Or can you make them pay more for the
increase in green that they crave and cost
be reviewed by each state’s regulatory commission. It is expected the costs for state compliance will be borne by the customers within the state where additional costs are required. Both commissions specifically review rate requests to ensure that customers from their respective state are paying only their
fair share.
Equity of what? vulnerable customers are protected and benefit from the ongoing development of our electric system. This advisory group will also help shape how equity will be incorporated into
Transmission/Distribution Avista Response
distribution/transmission planned for the near future? following website: https://www.oasis.oati.com/avat/index.html. Major Transmission projects planned for 2021 include:
• Rebuild approximately 13-miles of 115kV Transmission
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•between our Saddle Mountain and Othello Substations.
• Rebuild approximately 7-miles of 115kV Transmission
between Addy (BPA) and our Gifford Substation (1st Phase of 3-year project in Colville area).
• Rebuild approximately 10-miles of 230kV Transmission
between Oxbow (IPC) and our Lolo Substation (1st
Phase of multi-phase project).
• Integrate new 115kV Irvin Switching Station in the
Spokane Valley.
• Complete replacement of underground 115kV cables in downtown Spokane.
• Replace approximately 3-miles of 115kV Transmission south of Springdale, WA.
• Many smaller projects across the service territory for both
Transmission and Distribution projects are included in the
power lines? Will it be part of this 20-year plan? tree-related distribution outages, burying distribution lines is not a component of the Resource Plan. For new construction, Avista undergrounds facilities when appropriate. Avista has no systemic plans to underground existing facilities at this
Resource Selection Avista Response
providers and universities to get large federal grants to develop and field test new
energy storage systems?
research in storage. Avista has also been a recipient of Washington State grant funding and field tested a vanadium
flow battery in Pullman and is currently developing a project in the U-district of Spokane to integrate smart building designs
production builds/upgrades planned for the near future? baseload or 24/7 facilities. Current plans include new peaking resources, renewable resources, energy storage, energy efficiency and demand response in addition to our current
needs (Rathdrum prairie), and how will it
affect the reliability and price of our utilities? How are you dealing with the increase of population (and its need for
requiring service in our service territory, so the electrical and
natural gas infrastructure will be built to meet the demand as it develops.
increase in population? Avista’s economist conducts a forecast of future population and energy growth within Avista’s service territory as part of the load forecast. This forecast is updated each year and all electric and natural resource plans developed meet this
forecast’s estimate for energy needs. Higher and lower load
2030-early 2040s timeframe? storage compared to other alternatives, including renewable alternatives without storage, is higher priced until that time based on our current cost assumptions. In the next 10 to 15
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should be assessed. Especially Montana.
Are outside area resources being assessed? (asked multiple times)
be a viable and cost effective resource alternative to meet
customer needs. When Avista issues request for proposals by energy suppliers in the future, this will determine if this
using their full capacity, it is clean energy, and cheap. Is it being utilized? power is controlled by the Bonneville Power Administration (BPA) and is sold to other utilities. Avista does buy power from BPA on a day-to-day basis and may buy power from BPA on a longer-term basis in the future if it is a less costly option than
this a storage resource? looking to upgrade our Kettle Falls biomass facility in 2026
utilized? Also consider Rathdrum Prairie as a wind resource help meet resource needs. Although, actual wind acquisition from Montana will depend on a completive bidding process. The Rathdrum Prairie’s wind resource is not economically
solar? a solar farm. The reason for colocation is due to tax credits
capacity specifically Canada or Montana? location. Avista studies potential transmission interconnection points to test if the resource can connect or what will be required to facilitate the interconnection. More renewables will require more transmission or upgrades to existing to existing
scrapped- please clarify if this is accurate given you have natural gas plans in your resource plan.
Avista does have plans to retire or end contracts with some of these resources it currently uses. Given current economics, we expect some construction of new and more efficient natural
so late in comparison to building natural gas peak planning requirements depends on several factors including costs and the duration of the storage device. We mainly need energy production and storage in winter peak months and could be more reliant on storage earlier, but it will need to be either lower cost or a modestly higher cost compared to longer duration capability resources such as new
times- Do you need back up these resources- are we doubling the energy production?
from intermittent resources. These reserves are not necessarily doubling the generation required. For peak demand times we estimate a “peak credit’ for the intermittent resource types which is a measurement of how well we can expect the resource to help us meet peak needs when they occur. Typically this is a relatively low percentage for
seem to reflect this increase and expected. Each EV could add 5 to 10 kW of load to the
system. This is similar amount of power to an electric water
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EV scenarios to better understand how our plans could meet
free. Nuclear is large piece of the US energy supply and the INL has DOE contract for modular nuclear. What is Avista’s thought on nuclear.
in this plan due to high expected cost. Nuclear power also has additional risks from construction and waste disposal is an ongoing concern. Avista will continue to study nuclear in future IRPs and will update assumptions as more information about
Vancouver, Canada- what is the source of this Gas The Vancouver location referred to is likely the Sumas trading hub, where natural gas is traded between British Columbia and the I-5 corridor. Natural Gas may come from British
during peak load events. Its typically lower cost to construct but is often more expense to operate. More efficient natural gas-fired generation is available, but it is more expensive to build and would need to run a higher percentage of the time to
Is the carbon footprint of nuclear construction to great? this time. Avista studied hydrogen resources in is IRP, but not hydrogen fusion. Avista also evaluates the carbon footprint of
all resources when it looks to add to the system for both
resources? Southern Oregon, southern Idaho and Nevada have good options for geothermal. So far, the costs of these projects have been higher than other alternatives in our competitive bidding processes when the transmission costs to get
of rate scheme then a resource due to
pumping and generating at different times of the day? What about losses of pumping- you’re not creating energy- correct
throughout the day or week. It could also be used for meeting
peak load events and provide reserves for intermittent generation. Yes, pumped hydro does not create energy. It loses approximately 20% of its energy when operating, but it provides a large amount of capacity and energy over a much
adequacy? adequacy but planning for outages does not make for a reliable system. There are costs involved with making a system more reliable, and we are always trying to weigh the
higher then its demand- is that the case for Avista help with this issue, Avista is joining the energy imbalance market to pool resources with other utilities to handle this variation across a larger number of utilities and reduce the
Microgrids Avista Response
large scale but continue to test and monitor trends and changes in microgrid technology. This summer we will
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use in the future.

Security Avista Response
electrical system against terrorists or other people capable of damaging the key very large transformer's cooling systems with high powered rifles or explosive drones or malware?
nationally recognized security frameworks and standards to manage cyber and physical security related risks. These standards address protecting, detecting, responding and recovering from physical and cybersecurity threats. In addition, we work with industry and government partners to ensure we are aware of emerging security risks and how best
hacking which COULD shut down energy
supply (such as elec.)
nationally recognized security frameworks and standards to
manage cyber and physical security related risks. These standards address protecting, detecting, responding and recovering from physical and cybersecurity threats. In addition, we work with industry and government partners to ensure we are aware of emerging security risks and how best
Natural Gas (or Renewable NG) Avista Response
scheduling? scheduling as linepack provides the ability to flow the gas for the necessary demand. As more linepack is needed, more
supply will be brought on to the system to meet the demand
project changes (on linepack/scheduling)? the supply is available to our firm customers when they need
hydrogen technology for longer terms storage? of pure hydrogen is being blended directly with the natural gas. These systems are being studied for wider application. In other systems, hydrogen is first combined with waste CO2 to make methane before being blended. In this
application, the limits are much less restrictive and much more
Hydrogen gas you want to attain in your natural gas supply and what is the soon.
affect, reduce the btu’s? somewhat less than natural gas that does not have a hydrogen blend. Regardless, the customer is charged on the
Energy Efficiency & Demand Response
Questions
Avista Response
to be more efficient so they don’t lose or gain heat all the time? programs. Many of these options include improving cost effective weatherization of homes. Please visit Avista’s website for information on current energy efficiency rebates and programs. In addition to prescriptive offerings, commercial
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option to reduce energy demands, but
learned natural gas was the main usage we have and the ROI was negative. What offsets would be helpful on the Natural Gas side to replace our demand.
Energy Star appliances, space and water heating. In addition,
there are rebates for LED lighting and smart power strips to reduce phantom loads. More information can be found on Avista’s website at https://myavista.com/energy-savings/energy-savings-advice. From a resource planning perspective, in addition to energy efficiency on the natural gas side of the business, options include hydrogen and renewable natural gas. On the electric
side of the business, reducing dependence on natural gas will require long term storage solutions to store renewable energy
incentives where the owner of a building passes heating and cooling bills to the tenants, but the tenants don’t have long term incentives to benefit from capital investments in energy efficiency of the
continue to grapple with how to touch this hard-to-reach market. Utilities, regulators and legislators have been working on this issue, but there is no clear consensus yet on how to handle the split incentive problem.
years. Why will it take until 2024 to launch these in Avista's territories? Response but has not pursued these programs due to their higher cost then alternative resource acquisitions. The latest analysis shows these programs may be cost effective as an option to meet Avista’s capacity needs in 2026. We reevaluate the costs and benefits of Demand Response programs for
homeowner's HVAC system, does that
apply to given hours during a peak event? i.e., noon to 5 p.m.? Also, how would-this work? For example, if the peak event as heat related, would this be a device placed on the HVAC that would allow Avista to alternate AC to a fan-mode in 15-minute intervals?
modeled to be used during peak heating and cooling times
depending on the season for a two to four-hour time frame per
participant. This can be done with either a temperature set
back or by cycling the HVAC system. The customer impact is
a two-degree offset during the requested/event period.
Heating or cooling above/below the thermostat set point, ahead of the event period, (often called pre-heating or pre-cooling) was not included in the program design we evaluated We modeled this program in two ways, one with temperature control and one with cycle control. Either program would be time based and would include specific parameters around when those programs would operate and how customers could opt out for a specific event.
evaluate the energy usage of my home, such as efficiency of heating system ducts/furnace (gas), hot water (gas), and
way to understand ways you may be able to reduce energy consumption in your home. This is a free program, however, it is currently suspended due to the pandemic.
is, how does Avista deal with the natural
conflict between selling energy and conserving it?
through a bill adjustment called the “EE Tariff Rider”. All
customers contribute to these expenses based on the amount of energy they use that in turn will lower the cost for all
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relate to the amount of customer sales, but rather the investments it makes to its system that are prudent
investments as determined by the state regulatory
energy efficiency for middle income and low income customers? will there be rebates for homes converting to ductless heat pump systems from natural gas? or rebates for insulating window inserts?
programs such as weatherization and appliance upgrades. Community Action Agencies, such as SNAP for Spokane County, income-qualifies customers and administers the programs. For other customers, information on current energy efficiency
programs can be found on Avista’s website at
only through rebates or is on-bill financing also an option? If so, would that be applicable to residential customers and business customers?
implementing with a third-party lender. Avista will invoice and
collect the monthly payment and remit to the lender for qualifying energy efficiency projects. This program will initially only be available to Avista’s residential and small business
customers in Washington State and is expected to be
launched by the end of 2021. Avista is also looking at offering
reimbursement is? their Avista incentive payment for their qualifying energy
and just keeping up with regulation. Are we actually being proactive to lobby for EE improvement statewide, etc. in each jurisdiction or are you just reacting to state
of energy efficiency programs and offerings in the northwest. These include the Northwest Power and Conservation Council and the Northwest Energy Efficiency Alliance.
effective “deemed and calculated” DR
programs, such as more efficient charging of forklift batteries or switching to efficient lighting, so why can’t Avista adopt some of those sooner than 2024?
unique system. Costs and customer needs are often different
for each utility. Demand Response programs are different than Energy Efficiency Programs. Demand Response stops energy use for a period of time or shifts it, versus energy efficiency programs using less energy to get the same amount of work or process completed. Avista’s first DR programs will be rate related programs to incent use in non-peak hours. Over time as more controllable load is added to the system, it is likely
feed-in tariffs? Is Avista advocating for
those?
the utility. Currently the only program similar to this option is
generation provided under PURPA (Public Utility Regulatory Policies Act). No other state regulation requires a feed in tariff
neighborhood-scale geothermal, e.g. small thermal differential circulation pumps for heating or cooling costs. Avista welcomes developers to pursue this option and it may qualify for energy rebates.
neighborhood-scale renewable energy, such as solar gardens, Swedish-style local governments that allows property owners to finance
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property-assessed clean energy financing (PACE). have passed legislation allowing these programs, however, no counties in Avista’s service area have an active PACE program. Avista is currently developing an On-Bill Repayment (OBR) program that will be available to owner occupied buildings for both residential and small business customers in Washington State by the end of 2021. Avista is also looking at possibilities to offer OBR for our Oregon and Idaho customers
timers on hot water heaters? I have one on mine and it’s amazing how it keeps my found it to be non-economic compared to other options. Although Avista continues to evaluate this option and other
reducing their usage from having access to near real time
information and conservation voltage reduction on Avista’s
distribution system. The customer program for AMI energy
efficiency has partially been implemented with the availability of near real time usage on-line. Usage alerts and notifications, as well as data analytics for “always on” usage is under development and will be made available soon. Conservation voltage reduction is currently in use in Avista’s day-to-day operations. Additional AMI benefits, including energy efficiency, can be found on Avista’s website at https://www.myavista.com/about-us/smart-meters.
solar project as they once had in the past? that will provide more renewable options to our customers. At
but Avista intends to continue the energy fairs in the future
Reliability Avista Response
winter event when it is cold and dark with
no wind or solar production?
hydro resources to maintain system reliability for extreme
winter events until long-duration storage resources become
power grid from reliable power sources like hydro, gas, coal and nuc, to unreliable portfolio but will ensure reliable service by continuing to invest in capacity capable resources such as hydro and energy
will be based on these unreliables in the next 10, 15, 20 years? sales will be served by clean energy resources., A portion of this generation will be from wind and solar, as well as hydro
avoid the types of problems Texas just encountered? Are different plans needed to prepare for damage from wildfires?
supply are designed to withstand cold temperatures. Because of our climate, this has already been done. The second protection is to ensure Avista plans to add or maintain enough generation to serve customers during high load hours like
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Comments provided in breakout sessions, email, or chat feature
Inverted energy rates.
to determine the mix of resources needed to serve loads in these types of events. Avista is currently working with outside agencies and regulators to develop a wildfire plan but is well
positioned to repair and replace damage to infrastructure from
energy potential here to increase substantially? If so, how do you estimate the storage needed, for times when wind or solar or hydro. is supplying less than usual?
including wind and solar, as other regional utilities are also planning to do. The plan calls for at least 400 MW of additional wind and nearly 500 MW of solar over the next 24 years. The amount of storage will depend on the actual acquisition of specific resources and whether Washington will require real-time delivery of clean energy to its customer. For now, Avista’s
resource plan only plans to add 266 MW of storage, but if costs decline additional amounts could be added. The resource plan uses several modeling tools to determine how much energy can be relied upon for wind, solar and hydro
and solar are not available resources to meet this demand from intermittent resources. In the future energy may be stored in batteries, pumped hydro or
that resources are limited? particular price or cost or during periods of extreme weather
OR, and ID as what Texas is experiencing--why not? How will AVISTA and these states avoid the same fate? How do you expect to do the same program and expect different results?
Avista plans to meet extreme cold and hot events, second Avista plans for resource adequacy. Texas does not have a regulatory requirement to ensure capacity during cold or hot weather events. Another major issue in Texas was fuel suppliers, specifically for natural gas, were not prepared and their equipment was not designed for cold weather events. In
Avista’s case, its natural gas supply comes from Canada
energy, the problem with disposing of them when they are obsolete, and seeing the fiasco in Texas, should wind even be a
resources, the technology can still be economic to replace energy needs in other time periods.
warm and safe in the winters beyond 2025? 2026, the Company intends to address this in many ways including the issuance of a capacity RFP, possibly as early as
2021. In addition, the current IRP does not include any resource acquisition that may result from the 2020 Renewable
General Avista Response
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people fortunate enough to be home during times of lower use & lower costs could get the bonus of a
Policy
not comply with a bureaucratic environmental agency or with elected representatives who are in office based on computerized counting procedures that do not mirror the interest of the public which was
Reliability
come out and say this will happen, it seems we should expect mid-winter rolling blackouts after 2025 when Avista's predicted demand will exceed electrical supply. Think of California with its utility-
induced blackouts last summer, and the human tragedy and equipment destruction this winter caused by inadequate power planning in Texas. We don't want to fall into that kind of third-world situation here. I know we have a PUC and an Office of Energy and Mineral Resources but neither seems to be focused on this looming issue. I have attached some poignant excerpts from the IRP for your consideration. The full IRP can be found here: https://www.myavista.com/about-us/integrated-resource-planning
It's not very comforting to learn that Avista is "concerned" about not having adequate power generation after 2025, and that they are "hopeful" that something will be done on the regional level, but sadly they have no concrete solution. This does not sound like a very good contingency plan to me. If the Region needs new generating capacity and novel utility coordination to meet peak winter demand, and considering how long it takes to plan, finance and build large projects, it sure seems the energy outlook is not looking good for our area. It's rather troubling that Avista has put its customers in this predicament after their failed attempt to merge with Canada-owned Hydro-One in 2018. I think Avista is putting our state at risk by relying so heavily
on unrealized Regional solutions that are out of Avista's control. Avista hopes somehow the Regional players will create sufficient new generation and squeeze higher efficiencies out of a stressed and vulnerable network within the next 5 years. That seems far fetched; but if not, Avista should let us know the positive news before we all go out and buy whole house generators. It seems part of the diminishing supply problem stems from green initiatives of neighboring states and Federal mandates forcing the elimination of reliable "thermal" generation in favor of unreliable, and thinly available "renewable" energy sources.
I see you are Chair of the Resources and Environment Committee, so hopefully you will have some ideas on how to pursue this issue. Idaho might already be behind the 8-ball because 2025 is looming mighty fast and there is hardly any clear answer to the coming power shortage, other than the obviously un-said "rolling black outs". According to Cliff Harris, our local weather guy, we are due for a really big winter, bigger than 2007-2008, due to the solar minimum, etc. So all I can suggest is maybe get the appropriate committees to ask Avista and the Governors Energy office the tough questions: how will they keep north Idaho people warm and safe in the winters beyond 2025?
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Affordability & Equity
wage that has driven the cost of goods and services up to match. but wait grasshopper, no one raised the checks of the retired and disabled. only the prices went up which lowered the living standard of the
Environmental
are expensive too. They harm birds. They harm people. They require bare land. They are unsightly.
need to maintain our life. This is getting to be a matter of survival. All electricity is electricity; it would
be a fool's game to tell customers they are getting their electricity from wind or sun and not from hydroelectric dams. That is all bogus marketing. Telling customers they can pay for "green" energy is a credit that is all on the books and this is not tied to reality. Any way that financiers can play with money and that customers can be billed more or less for fees or peak loads or anything else is all "make-work" schemes for billing departments, computer programs, marketing webinars like these public forum meetings, which are a ploy to lead us to think we can stop what you are already planning to implement because you are "committed." Your company has co-opted the best, most noble vocabulary and is using it to name your plans which will actually destroy the lives of people and the
economy of America. A sample of your vocabulary includes "power production," "load growth," "lens,"
consistent coal still accounts for over 60% of all the power generated in the U.S., and to pretend that intermittent wind and solar can in the near term (let alone ever??) replace coal without natural gas, nuclear and hydro expansions, is irritating to many of us. The tribal influence of less than 10,000 members in our region, over the welfare of millions of U.S. citizens, is of great concern to us. I had put in some questions about Colstrip that I hope get publicly answered. Is the power generated by U.S. plants like Colstrip really that "dirty"? (U.S. companies are leaders in scrubbing pollutants out of
exhausts.) Is the public being sold a false narrative in that regard, due to political pressures? Could that plant be leased by Avista and run by the utility if the tribes don't want to do it? Could a new state of the
Resource Selection
Boyle Dam, Copco Dams 1 & 2, and Irongate Dam, I also support solar power, but within limits. I
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in legal jeopardy for future failures in WA, ID, and OR? Wind is a joke. There can be no wind. The turbines can freeze. The blades are made of fiberglass. They are so big, they must be brought in one
per truck. Fossil fuels are needed to transport them. They are not biodegradable. Just like China, we need to forestall any changes from our present energy forms until we have more technologically advanced forms of energy. Wind and sun are NOT advanced forms. Our present federal-level
We need to think other than wind and solar. It is primitive. Your questions are lose-lose. The multiple
General
powers of the mind to make new discoveries of the physical world around us, why don't we get out of this doomsday outlook which says we are limited to the energy platform we are already on? We ought to be spending our time and strength building on the steps we have already taken to be able to land on the Moon and voyage to Mars, in order to get new forms of energy available to us. Specifically, environmentalists have blocked nuclear power energy. However, NuScale's Small Modular Reactors are as clean as wind, solar, and are cleaner than any fossil fuel. I think AVISTA ought to push back against Washington State's population-reducing polices. Our country was founded to promote the General Welfare of all the people, but Washington State, Oregon, and California's governors and
focus on scientific discovery of new ideas, like Benjamin Franklin and Thomas Edison did. We will not be able to maintain what we have because the production of these "green" "clean" energies are
reliability, clean, attentive to, responsible to the environment, generation, strategy, scalable, ensure, pre-credit, production history, resources, renewable, reduce carbon foot-print, need energy, build our needs, deliver, service territories, demand response, retiring existing resources, social cost of carbon, voluntary offering, energy efficiency, advancing technologies, lowering costs, hydrogen blending, opportunity matures, forecasted. All of this vocabulary puts a great-sounding face on plans for your reduction of perfectly good forms of energy in present use and divvying it out piece-meal to the result that the people will be diminished and in grave danger of dying off from supposedly new ideas, which are actually nothing at all beyond just sitting outside in the cold. I think "carbon-footprint" is a false
boogey man that AVISTA is foolishly bowing down to and carrying the rest of the people to do the same. I think your assumptions and definitions need to be re-visited and reviewed. You are limiting
assumptions. Basically, they believe what Malthus said, namely, that the earth is not able to support a growing population. Actually, God said to be fruitful and multiply. He has made man with the ability (of his mind and powers of observation) to DISCOVER new ways to harness the natural laws and physical
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community. I was interrupted in my second breakout meeting but I still have a question; “What does your company anticipate the impact to be from the forthcoming increase in electric vehicles and how
will you prepare for that?” This is probably an industry wide question with a complex answer. You don’t

Avista Corp.2021 Electric IRP Appendices 722
1

Sent Via email to: [e-mail]
July 31, 2020
Mr. Lyons and the Avista IRP Team,
Thank you for the opportunity to request additional studies as part of the 2021 IRP
process. Our requests below include some process improvements to the existing studies in the IRP as well as some new considerations. In each instance, our goal is to ensure the IRP leads to the least cost and least risk portfolio of supply side and demand side
resources. As the complexity of the electric system increases, as the economics of resources change rapidly, and as new issues become even more acute, we encourage the Avista IRP team to lean into this process and set an example for the region for a best
in class IRP process. We look forward to working with you and the rest of the Technical Advisory Committee to achieve these goals. Contact us anytime using the information below
Stay safe, stay healthy,
Ben Otto Idaho Conservation League 208-345-6933 ext 12 [e-mail]
Dainee Gibson Idaho Conservation League [e-mail]

Study and Process Improvement Requests
Systemwide v state specific resource additions
At the first Technical Advisory Committee meeting, Avista indicated the PRiSM model could add resources to Washington and Idaho separately or to the combined, interconnected system. We request a study of the costs and timeline necessary to replace the fossil-fueled component of the 35% of existing resources allocated to Idaho with an optimized portfolio of non-fossil resources including supply-side, demand-side,
and storage resources. We request Avista compare the results of this Idaho-specific study to the results of the same analysis at the system-wide level. We also request a study that documents the costs to implement, monitor and document the state-specific addition of resources to an interconnected system dispatched to meet combined customer loads.
Avista Corp.2021 Electric IRP Appendices 723
2
Existing resource costs
We request Avista study a scenario that applies the Social Cost of Carbon to all
resources, including those that serve Idaho, as offered in the first TAC meeting.
We request Avista study scenarios for Colstrip costs that reflect the changing ownership shares currently being considered by co-owners Puget Sound Energy, Northwestern Energy, and Talen. Further, we request a study of likelihood and scale of increases to Avista’s share of common plant costs, remediation costs, and fuel supply costs, including minimum fuel supply and generation off-take, attributable to both the closure of Units 1 and 2 and the changing ownership share of Units 3 and 4.
We request a study of the accuracy of Avista wholesale natural gas price forecasting methodology by comparing forecasted prices in prior IRPs to prices Avista actually paid. We request this study include a comparison of the accuracy of consultant-supplied forecast to publicly-available forecasts covering the same time periods.
Storage
Storage resources provide unique attributes that are not captured in traditional IRP modeling techniques that focus on energy and capacity needs in the hourly time
scale. Storage technologies like Li-Ion batteries with fast reaction times, but only a few hours of capacity can address power quality and reliability needs within the hour. Medium term storage resources, such as Li-Ion batteries with 6 - 12 hour capacity,
and pumped storage projects, can help integrate variable energy resources and address reliability needs. Longer term storage resources like hydrogen electrolysis paired with storage and repowered turbines, can address integration, reliability, and resiliency needs. By combining these storage resources with specific clean generation options, Avista can develop clean resources that meet the reliability metrics for flexibility, peaking, and renewable integration necessary to meet Avista’s clean energy goals as well as CETA requirements.
To ensure a full and fair treatment of storage values we request the following:
• We request Avista model loads and generation at the sub-hourly level. We recognize Avista began pursuing sub-hourly modeling in the 2017 IRP and further refined the ADSS system in the 2019 IRP. We request Avista fully implement sub-hourly modeling for all IRP studies and processes.
• We request Avista study the optimal pairing of generation resources with storage of different technologies and lengths of supplying services. For example: pairing local solar or wind with Li-Ion 4hr, 6hr, and 12hr batteries; pairing pump hydro resources with regional solar, wind, and wholesale markets; pairing long term storage like hydrogen electrolysis and associated hydrogen storage with Avista’s own resources and wholesale market generation.
• We request Avista study the emission reductions possible from pairing storage with specific clean generation options along with the Proposal presented to the TAC to apply the average emissions rate of the region for storage paired to generic wholesale market resources.

Avista Corp.2021 Electric IRP Appendices 724
3
Distribution level modeling
Distributed energy resources are increasing as products diversify and the economic
proposition improves. To help encourage the optimal growth of DERs on the Avista system, we request a Hosting Capacity Analysis. This analysis could support a distributed energy resource interconnection map that identifies where distributed energy resources exist on the system or where the distribution system is constrained and could benefit from energy storage or specific demand responses. This Hosting Capacity Analysis would benefit the IRP’s load forecasting and overall integration of distributed energy within the IRP. We recommend Avista define DERs broadly for this study to include: customer-sited generation and storage, utility-sited generation and storage at substations or other locations on the distribution grid, as well as public and private electric vehicle charging stations. We request Avista incorporate different load shapes that are indicative of customer generated power as well as the charging of electric
vehicles to ensure accuracy in the load shapes for supply-side resource planning. The Smart Electric Power Alliance has an informative set of resources to help with this effort: https://sepapower.org/knowledge/proposing-a-new-distribution-system-planning-model/.
Flexibility Issues
With the technological changes of a modern grid system, including flexibility in both supply and demand studies is essential as we look to the future of electric service areas. As shown in the pilot program with the Catalyst Building, the savings from energy efficiency and flexible building loads can be extremely beneficial for the electric grid as a whole. Similarly, the micro-transaction grid project in the Spokane University District is demonstrating the value of flexible loads and new market opportunities for customers to manage their power bills. To fully explore the value that flexibility brings to Idaho customers, we request Avista study the potential to expand similar projects in the Idaho service territory. At minimum, a study to see the perspective of customers’ willingness to
participate in such a pilot program could have lasting results.
Climate Change Impacts to Avista’s System and Costs
In the 2020 IRP, Avista describes how climate change is causing a rise in temperatures today in the service territory and, therefore, is influencing the load forecast. To further examine how the currently changing climate can impact the system and costs, we
request Avista build upon this by studying the following:
• Loads - study changes to both long-term load forecast and the peak load forecast attributable to climate change. The 2020 IRP mentions a 1-degree increase in temperatures, but does not appear to describe how climate change is factored into the peak load forecast. The 2020 IRP also cites a temperature data set from 2013, which we recommend Avista update to the most currently available set.
• Hydro - study the potential changes to hydroelectric power generation that could result from climate-caused changes to precipitation type and timing. This study
should document the range of impacts to power costs that result from the changes in hydroelectric power generation.
• Thermal plants - study potential changes to expected generation and production costs due to temperature changes. This study should include changes to expected generation and fuel costs as output varies with ambient temperatures
Avista Corp.2021 Electric IRP Appendices 725
4
and the impacts to cooling water needs due to changes in precipitation and water temperatures. The study should document the range of impacts to power costs
due to the change in expected generation output, fuel needs, and cooling water needs.
Beneficial electrification
One of the most interesting long-term planning issues to address in the 2021 IRP is how increasing electrification of transportation can benefit the system and customers. Idaho
currently imports 100% of our transportation fuels. Electrifying transportation can make Idahoans more energy secure and reduce costs since we pay above average fuel prices and below average electricity prices. And optimizing charging practices can deliver further benefits to all electric customers. The 2020 Transportation Electrification Plan (TEP) states that “In 2025, over 6,800 EVs are expected to provide Avista with gross revenue of $2.1 million from EV charging. Subtracting an estimated $0.5 million in marginal utility costs to generate and deliver this energy results in $1.6 million in net revenue – savings which may be passed along to all utility customers in the form of decreased rate pressure.” To ensure Avista is prepared to serve Idaho’s clean transportation needs, we request:
• The load forecast includes the baseline projection of electric charging services,
as forecasted in the 2020 TEP. We also request scenarios that consider higher penetration of EV, especially for commercial fleets, delivery vehicles, and public transportation.
• A study of how to optimize charging behaviors, including customer load management, and how to optimize the location of public and workplace charging
stations to avoid distribution grid overload while maximizing grid flexibility and benefits to the system. For example, the TEP identified that the $1,206 in electric system benefits per EV could “be increased by another $463 per EV when load management shifts peak loads to off-peak.”
Avista Corp.2021 Electric IRP Appendices 726
Hello Ben and Dainee,
Thank you for your continued participation and involvement in Avista’s IRP. Here are
the replies to your 2021 IRP study requests and suggestions for process improvements
to ongoing studies.
System wide versus state specific resource additions
• “We request a study of the costs and timeline necessary to replace the fossil-
fueled component of the 35% of existing resources allocated to Idaho with an optimized portfolio of non-fossil resources including supply-side, demand-side,
and storage resources.
Avista is developing a portfolio with all renewable/GHG emissions free
resources as it did in its 2020 IRP.

• We request Avista compare the results of this Idaho-specific study to the results
of the same analysis at the system-wide level.
Yes, we will highlight the comparisons of the system-wide versus the
Idaho-specific study in the IRP.

• We also request a study that documents the costs to implement, monitor and
document the state-specific addition of resources to an interconnected system
dispatched to meet combined customer loads. The cost allocation for new assets constructed to meet the Washington
CETA law has not been decided by either Commission yet. An IRP does
not answer this question. The 2021 IRP will attempt to evaluate the cost
deltas between portfolios absent CETA mandated acquisition targets.
Avista looks forward to working with both commissions and interested parties on this issue as new analyses become available.

Existing resource costs
• “We request Avista study a scenario that applies the Social Cost of Carbon to all
resources, including those that serve Idaho, as offered in the first TAC meeting.”
Avista will conduct this study in the 2021 IRP.

• “We request Avista study scenarios for Colstrip costs that reflect the changing
ownership shares currently being considered by co-owners Puget Sound Energy,
Northwestern Energy, and Talen. Further, we request a study of likelihood and
scale of increases to Avista’s share of common plant costs, remediation costs, and fuel supply costs, including minimum fuel supply and generation off-take, attributable to both the closure of Units 1 and 2 and the changing ownership
share of Units 3 and 4.”
Regarding the change in ownership percentages for Units 3 and 4, there
are no changes to Avista’s responsibilities or modeling inputs to alter because Avista’s 15 percent share of both units remains static under the
Colstrip ownership agreement. Avista’s financial responsibility for the plant
Avista Corp.2021 Electric IRP Appendices 727
remains the same regardless of the non-Avista ownership or ownership percentages for Units 3 and 4. As in the last IRP, Avista is accounting for
the shift (increase) in previously shared costs that are a result of the
closure of units 1 and 2. Those costs increased, but Avista’s share of
those costs did not change. Avista has zero responsibility for the remediation costs associated with Units 1 and 2. The closure of those
units did not end the financial responsibility of those remediation costs for
the owners of those units (Puget Sound Energy and Talen). Avista’s fuel
contract is separate from the contracts that supplied Units 1 and 2.
Avista’s fuel contract and any subsequent mine remediation costs with our
share of coal are already included in the prices being modeled in the 2021 IRP, consistent with past IRPs.

• “We request a study of the accuracy of Avista wholesale natural gas price forecasting methodology by comparing forecasted prices in prior IRPs to prices
Avista actually paid. We request this study include a comparison of the accuracy
of consultant-supplied forecast to publicly-available forecasts covering the same
time periods.
The natural gas price forecast beyond the shorter term forward markets is
always an area of concern because of the potential for volatility, timing and magnitude of outside events, much like the current pandemic we are
now experiencing. It is in our own best interests to use good forecasts.
Avista publishes its natural gas price forecasts in each IRP; including both
consultant forecasts on an annual average basis. Actual natural gas prices are also publicly available. The consultants that we use work on a national
as well as an international basis. They already perform their own internal
analyses to make their forecasts as accurate as possible to maintain and
grow their business. We are paying for their expertise and research into
the natural gas market. Avista has not seen any evidence indicating that
there are better forecasts available and we do not possess the resources to develop a comprehensive fundamentals based natural gas forecast on
our own. Some forecasts, like those provided by the Energy Information
Administration, supply some more details about the fundamentals they are
using, but they are also more dated and do not provide the level of granularity into specific trading hubs. The consultants would not be able to
remain in business if they had to give away all of their research for free.
Please let us know if you have found other evidence or research indicating
better forecasts. Storage
• “We request Avista model loads and generation at the sub-hourly level. We
recognize Avista began pursuing sub-hourly modeling in the 2017 IRP and
further refined the ADSS system in the 2019 IRP. We request Avista fully implement sub-hourly modeling for all IRP studies and processes.”
Sub-hourly modeling is challenging due to model solution complexity and
data availability. Further, modeling all sub-hourly periods is not
Avista Corp.2021 Electric IRP Appendices 728
technologically possible. Presently, modeling at one-hour granularity requires thousands of hours of computer processing time. Moving to intra-
hour modeling would cause an exponential increase in solution time even
if the data was available. ADSS and other modeling techniques are used
to evaluate intra-hour values, and generally rely on sampling of relevant time periods. This is specifically the case with the complexity of modeling
storage resources. Avista is working on this issue and is hopeful it will be
available in future IRPs and will be added as an Action Item in the 2021
IRP if not completed for this plan.

• “We request Avista study the optimal pairing of generation resources with
storage of different technologies and lengths of supplying services. For example:
pairing local solar or wind with Li-Ion 4hr, 6hr, and 12hr batteries; pairing pump
hydro resources with regional solar, wind, and wholesale markets; pairing long term storage like hydrogen electrolysis and associated hydrogen storage with
Avista’s own resources and wholesale market generation.”
As described in the first TAC meeting and distributed to the TAC
afterwards, this IRP is already including a wide variety of stand-alone
storage and combined renewables plus storage options. The options
being modeled include distribution scale 6-hour Lithium-ion; 4, 8 and 16-hour Lithium-ion; 4-hour Vanadium flow, 4-hour Zinc Bromide flow
batteries; 16-hour 100 MW share pumped storage; and 100 MW solar
photovoltaic with 200-MWh Lithium-Ion batteries. Avista is also modeling
hydrogen using fuel cells or converted combustion turbines. Each of the hydrogen options will include long duration storage facilities as a backup
to real-time deliveries. Avista’s IRP modeling includes the benefits from a
portfolio optimization in its current process between storage and
renewable resources.

Avista acknowledges there could be a benefit to pairing storage with renewables from a transmission perspective. Although the locational
benefits of storage paired with resources may not be optimal when
considering other “better” locations to locate the storage. Avista agrees
with this concept and is trying to determine the best methodology to model these potential benefits, but the modeling of this concept may not be
available in time for this IRP. It will be added as an Action Item if we are
not able to develop the concept and include it in the 2021 IRP.

• “We request Avista study the emission reductions possible from pairing storage
with specific clean generation options along with the Proposal presented to the
TAC to apply the average emissions rate of the region for storage paired to
generic wholesale market resources.”
Avista includes regional emissions for storage not connected to a facility;
for paired resources, Avista does not include the emissions when using
the paired resources. Although, over time as paired solar/storage
resources are no longer obligated to use the paired resources storage
Avista Corp.2021 Electric IRP Appendices 729
technology to satisfy tax credit requirements will likely use a combined grid/local power for optimization of the system.

Distribution level modeling
• “To help encourage the optimal growth of DERs on the Avista system, we request a Hosting Capacity Analysis. This analysis could support a distributed
energy resource interconnection map that identifies where distributed energy
resources exist on the system or where the distribution system is constrained
and could benefit from energy storage or specific demand responses. This
Hosting Capacity Analysis would benefit the IRP’s load forecasting and overall integration of distributed energy within the IRP. We recommend Avista define
DERs broadly for this study to include: customer-sited generation and storage,
utility-sited generation and storage at substations or other locations on the
distribution grid, as well as public and private electric vehicle charging stations.”
Avista’s transmission and distribution departments are working on a public
process for this type of planning. This process will likely be separate from
the IRP process, but will provide information for the IRP. More details of
this process and its findings will be shared with the TAC as they are
developed.

• “We request Avista incorporate different load shapes that are indicative of
customer generated power as well as the charging of electric vehicles to ensure
accuracy in the load shapes for supply-side resource planning. The Smart
Electric Power Alliance has an informative set of resources to help with this effort: https://sepapower.org/knowledge/proposing-a-new-distribution-system-planning-model/.”
Avista welcomes the information, but at this time is using data collected
from its local system for both solar and electric vehicles. Flexibility Issues
• “With the technological changes of a modern grid system, including flexibility in
both supply and demand studies is essential as we look to the future of electric service areas. As shown in the pilot program with the Catalyst Building, the
savings from energy efficiency and flexible building loads can be extremely
beneficial for the electric grid as a whole. Similarly, the micro-transaction grid
project in the Spokane University District is demonstrating the value of flexible
loads and new market opportunities for customers to manage their power bills.
To fully explore the value that flexibility brings to Idaho customers, we request Avista study the potential to expand similar projects in the Idaho service territory.
At minimum, a study to see the perspective of customers’ willingness to
participate in such a pilot program could have lasting results.”
Avista appreciates the comment to also consider Idaho as a test bed for future projects and will take this under advisement. Avista utilizes the
University of Idaho for several R&D efforts through a grant process for a
total of $270,000 to study efforts related to energy efficiency and flexible
building loads. Example projects from the 2019/20 academic year include:
Avista Corp.2021 Electric IRP Appendices 730
a program design for energy trading system for consumers, using infrared cameras for building controls, and gamification of energy use.

Climate Change Impacts to Avista’s System and Costs
• “Loads - study changes to both long-term load forecast and the peak load
forecast attributable to climate change. The 2020 IRP mentions a 1-degree
increase in temperatures, but does not appear to describe how climate change is
factored into the peak load forecast. The 2020 IRP also cites a temperature data
set from 2013, which we recommend Avista update to the most currently
available set.” Climate change is being included in the load forecast as a scenario, which
was covered in the special TAC meeting on August 8, 2020 after we
received this letter. Further, all load forecast scenario data is available on
the IRP website. Please let us know if you have any additional questions or concerns that may have arisen since that presentation.

• “Hydro - study the potential changes to hydroelectric power generation that could
result from climate-caused changes to precipitation type and timing. This study
should document the range of impacts to power costs that result from the changes in hydroelectric power generation.”
We have obtained the climate adjustments developed by the Power
Council and are reviewing them to determine how they might be
incorporated into the 2021 IRP. More details will be presented at a future
TAC meeting.

• “Thermal plants - study potential changes to expected generation and production
costs due to temperature changes. This study should include changes to
expected generation and fuel costs as output varies with ambient temperatures
and the impacts to cooling water needs due to changes in precipitation and water temperatures. The study should document the range of impacts to power costs
due to the change in expected generation output, fuel needs, and cooling water
needs.”
Avista agrees temperature changes will impact the amount of production
from its natural gas-fired facilities. This impact will be included in the
climate change scenario.

Beneficial electrification
• “The load forecast includes the baseline projection of electric charging services,
as forecasted in the 2020 TEP. We also request scenarios that consider higher
penetration of EV, especially for commercial fleets, delivery vehicles, and public
transportation.”
Avista studied increasing EV penetration in the 2020 IRP. At this time, Avista will need to focus on other scenarios for this IRP because of the
limited amount of time available for modeling.

Avista Corp.2021 Electric IRP Appendices 731
• “A study of how to optimize charging behaviors, including customer load
management, and how to optimize the location of public and workplace charging
stations to avoid distribution grid overload while maximizing grid flexibility and
benefits to the system. For example, the TEP identified that the $1,206 in electric system benefits per EV could “be increased by another $463 per EV when load
management shifts peak loads to off-peak.”
Avista is updating its EV demand response program assumptions and this
will be discussed at the September TAC meeting. Avista welcomes this
discussion at the upcoming meeting to ensure it has robust assumptions
for this IRP.
Avista Corp.2021 Electric IRP Appendices 732

August 18, 2020
RE: Electrification Assumptions in August 6 Avista IRP Presentation
Dear Mr. Gall, Mr. Pardee, Mr Lyons, and the Avista IRP team,
We appreciate the opportunity to provide comments on Avista’s IRP. This comment letter focuses on
considerations regarding the electrification of end uses scenario that the company is considering.
Washington state adopted greenhouse gas limits during the 2020 legislative session that direct the state to
reduce total emissions by 95% compared to 1990 levels, or approximately 5 million tons of CO2e by 2050; for
comparison, residential and commercial use of natural gas was responsible for approximately 7.3 million tons of
CO2e emissions in 2015. In order for the state to achieve its overall limit, it is clear that this total must decline
precipitously and studies indicate that electrification is likely the least cost pathway for doing so. Washington
State’s Deep Decarbonization Pathway Study, which was aimed at a less ambitious reduction target of 80%
compared to 1990 levels, called for 85% reductions in residential gas use and 43% in commercial gas use
reductions.
Evaluating electric sector impacts of this scale of reductions is important, and doing so must be informed by
current and reasonable assumptions about appliance performance. Below we provide recommendations to
update Avista’s assumptions regarding representative heat pumps and water heaters, as well as additional
considerations to properly model their impact on the company’s system. In particular, we think it is reasonable
to assume that over the period considered in the IRP, electric space and water heating choices will become
dominated by heat pumps, especially with the salutary involvement of the company.
Washington’s residential energy code already preferences heat pumps given their high efficiency, a preference
that will only be strengthened as the code goes through subsequent updates along the path to 70% less energy
consumption by new buildings by 20311 and as carbon is accounted for in code as it now is under WSEC 2018.
Likewise, for customers that are converting from gas or another fuel source, they are likely to opt for the most
cost-effective long-term option. This is already heat pumps rather than electric resistance units, and the
economics of this choice will continue to improve.
Electric Heat Pumps
Avista suggests that end use efficiency of electric space heating at 35 degrees would be 150% (COP=1.5) and
100% at 5 degrees (COP=1). This does not accurately reflect the current state of the market. Climate Solutions
reviewed the Northeast Energy Efficiency Partnership’s (NEEP) Cold Climate Air Source Heat Pump List. NEEP’s
definition of “cold climate” is any IECC climate zone of 4 or higher. Avista’s service territory meets this definition,
containing zones 5 and 6. NEEP’s list contains nearly 8,000 air source heat pumps available on the market today
from 89 manufacturers.
The average COP for the listed heaters operating at their maximum capacity at 5 degrees Fahrenheit is 2.09, and
the lowest COP for the models they catalogue is 1.75 at that temperature. A number of models do indicate they
would switch to backup heat at lower temperatures, but 4 out of 5 do not include a condition for switching and

1 RCW 19.27A.160
Avista Corp.2021 Electric IRP Appendices 733

would continue operating at the rated COP. Below is a histogram showing the distribution of various COPs
within this product list.
Below we also provide the
the average COP at a variety
of other temperatures
included in NEEP’s list.
Because customers living in
cold weather are most likely
to acquire a heat pump
calibrated to their needs, and
because this technology
invariably will continue to
improve, we recommend that
Avista change its end use
efficiency assumption for
space heating to at least
200% efficiency at 5 degrees,
and adjust the end use efficiency statistic at 35 degrees consistent with the data provided in NEEP’s database.
Ambient Temperature
(degrees Fahrenheit) Average COP at Rated Capacity Average COP at Max Capacity
17 2.75 2.45
47 3.81 3.58

Water Heaters
While there are heat pump water heaters (HPWH) available that perform at the low level Avista selected for 5
degrees, we do not think selecting the bottom of the market is a prudent choice. In 2018, Energy 350 completed
field tests in a variety of conditions of HPWHs in British Columbia, including at locations that lie just outside of
Avista’s service territory. A summary of their results are available here.
Energy 350 chose two HPWHs, one from Sanden and another from Rheem and evaluated their operation over
the course of a year. The Sanden model was a split system, with a unit located outside, while the Rheem model
was designed to directly replace a traditional water heater located in conditioned and semi-conditioned spaces.
Their COP results bear out these differing designs. On the next page are scatter plots showing the observed
performance of these systems at various temperatures, along with their lines of best fit.
From these results, and from a review of other comparable products on the market, we are concerned that the
current choices Avista has made for water heater end use efficiency don’t accurately reflect operational
conditions. While there are indeed HPWH that would be rated at a COP of 0.9 at 5 degrees, these are not
designed to be placed outside and instead reside indoors—in basements, garages, or even utility closets that
stay at room temperature—preventing them from needing to operate in such ambient temperature conditions.
If a customer opts instead to place their water heater outside, they would select a model designed for such
Avista Corp.2021 Electric IRP Appendices 734

conditions, along the lines of the Sanden model tested by Energy 350 whose observed COP at that temperature
is 1.76. Outdoor placement of water heaters is unusual, and the Sanden split model is more expensive than the
Rheem indoor option, so we would consider the proposed representative water heater the company is
suggesting to be an exceedingly rare configuration on Avista’s system.

For this reason, we request that Avista explain the assumptions the company is making about water heater
locations, the ambient temperatures the model anticipates the water heaters will be exposed to over the course
of a year, and make adjustments to more accurately reflect the product and appliance location choices
customers are likely to make. At a minimum, we consider the current efficiency selected in the August 6th
presentation to represent a circumstance that wouldn’t occur—an indoor model placed outdoors.
Thank you for the opportunity to participate in Avista’s electric Integrated Resource Plan, and for running an
open and inclusive process to date. We look forward to continuing to engage with your IRP team on the
resource plan and this scenario.
Sincerely,

Vlad Gutman-Britten
Washington Director, Climate Solutions
Avista Corp.2021 Electric IRP Appendices 735
1
Gall, James
From:Gall, James
Sent:Monday, September 14, 2020 10:45 AM
To:Vlad Gutman
Cc:Lyons, John; Pardee, Tom
Subject:RE: [External] RE: Avista Draft TAC 2 Presentations for 8/6/20
Dear Mr. Gutman,

heat pumps
expectations.

After discussion with Avista’s chief energy efficiency engineer, a few modifications to the efficiency calculation are in ord
These modifi
for this calculation on the IRP website. The modifications are as follows:
1) Removed the space heat effect to the efficiency of heat pump water
100%.
2)
customers shut off heat pumps to avoid the defrost cycle.
3) The hybrid scenario begins the load
behavior given economic inputs for fuel.
heaters to clarify the whol
temperatures are high, looking at this v
during periods of cold temperatures at a great ec
such as defrosting, the possibility of a reduction in effi
the regional residential building survey assessment (RBSA) which detail observed performance.

Space Heating Conversion
Fuel conversion from natural gas to electric heating will likely be to a central heat pump instead of a ductless heat pump
system because current natural gas customers already have ducted systems in their
The central system heat pumps are not as efficient as ductless heat pumps because the system must wor
return air, or return air only coming from one floor, can reduce the rated efficiency of the heat pump. With a ductle
all of the airflow characteristics are controlled by the heat pump manufacturer resulting in a more efficient unit.
consumer d
effectively model cold te
of inclement weather and further reduces efficiency.
to the current limitations in these systems described above heat pumps will not achieve similar efficiencies now.
The Regional Technical Forum table shown below identifies residential single-
which given the
Avista Corp.2021 Electric IRP Appendices 736
2
in heating zone 1 makes it dif
climates like ours.

New homes that would previously include natural gas ducted systems could be ductless heat pumps in the future
discussion continues below.

Ductless Heat Pumps
If a natural gas home converts to a ductless heat pump system (DHP), the whole house would not see a COP in the 3 to 5
range for homes with cold temperatures as commonly advertised by the vendors. Fir
or be supplemented with additional resistance heat to maintain house temperature. Further, most
use this system for the entire house and typically only heat one or two rooms while putting very low cost resistive heating i
smaller rooms and areas of the house not frequently used.
Practically, in colder temperatures, it is possi
heat pumps with slightly better than 1 COP values. The f
consumption is over 5,000 kWhrs. The best study here also shows other fuel influe
efficiency is less than a COP of 1.25.

Water Heating
The data included on heat pump water heating is consistent with Avista’s assumptions. This data does not include the
impact of the heat pump system consuming space heat from the house, when adjusting for this consumption, cold weather
efficiency values are
revised them to not be below 100% as they will be in resistance mode for space heating.

Avista Corp.2021 Electric IRP Appendices 737
3

Thanks again for the questions regarding this scenario it has improved the assumptions and our understanding of the
complexities of electrification,

James Gall
IRP Manager, Avista
509-495-2189

From: Vlad Gutman <[e-mail]>
Sent: Tuesday, August 18, 2020 10:23 AM
To: Gall, James <[e-mail]>
Cc: Lyons, John <[e-mail]>; Pardee, Tom <[e-mail]>
Subject: RE: [External] RE: Avista Draft TAC 2 Presentations for 8/6/20

Attached please find some
though I think they’re checking about whether or not I can provide it to you all. In either case, you can receive the list
from them directly if you become a member.

Thanks again for all your work to date, and I look forward to hearing more this afternoon.

--Vlad

---
Vlad Gutman-Britten
Washington Director
Climate Solutions
206-886-4616

From: Gall, James <[e-mail]>
Sent: Wednesday, August 12, 2020 5:19 PM
To: Vlad Gutman <[e-mail]>
Cc: Lyons, John <[e-mail]>; Pardee, Tom <[e-mail]>
Subject: RE: [External] RE: Avista Draft TAC 2 Presentations for 8/6/20

Please send it when you can. I plan to make any modifications to the assumptions in the next two weeks prior to posting
the data file. After you see the new data file we can discuss more then. This is a more straight forward scenario so it can
be refined later in the process compared to other scenarios.

From: Vlad Gutman <[e-mail]>
Sent: Wednesday, August 12, 2020 4:42 PM
To: Gall, James <[e-mail]>
Cc: Lyons, John <[e-mail]>; Pardee, Tom <[e-mail]>
Subject: RE: [External] RE: Avista Draft TAC 2 Presentations for 8/6/20

We’ve collected some data on what’s available on the market now, vs bleeding edge, that we intend to share with you
for your consideration. I’m going to work up a letter—remind me when would be timely to have it to you by?

---
Vlad Gutman-Britten
Avista Corp.2021 Electric IRP Appendices 738
4
Washington Director
Climate Solutions
206-886-4616

From: Gall, James <[e-mail]>
Sent: Wednesday, August 12, 2020 4:37 PM
To: Vlad Gutman <[e-mail]>
Cc: Lyons, John <[e-mail]>; Pardee, Tom <[e-mail]>
Subject: RE: [External] RE: Avista Draft TAC 2 Presentations for 8/6/20

Hi Vlad,

COP for heating is probably the closest definition, but not for other appliances which is why we labeled it differently.
Also there are lots of options out there and we attempted to make an estimate of the average customer- not the
bleeding edge of available technology. Given technology change potential, we decided to conduct a scenario with much
higher efficiency ratings in the event. My hope is in the next week or two we will post the spreadsheet of our
assumptions and methodology for this scenario and you can take a look.

From: Vlad Gutman <[e-mail]>
Sent: Wednesday, August 12, 2020 4:14 PM
To: Lyons, John <[e-mail]>; Gall, James <[e-mail]>; Pardee, Tom
<[e-mail]>
Subject: [External] RE: Avista Draft TAC 2 Presentations for 8/6/20

Hi all--

On the electrification scenario assumptions, I just want to ensure I properly understand the inputs you’re using—when
you say “end use efficiency”, you’re referring to the COP of the appliance at that temperature. Is that correct? Not some
other rating I’m not thinking of? Just want to make sure I’m properly understanding the metric.

Thanks,

Vlad

---
Vlad Gutman-Britten
Washington Director
Climate Solutions
206-886-4616

From: Lyons, John <[e-mail]>
Sent: Tuesday, August 4, 2020 1:53 PM
To: '[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; Kalich, Clint <[e-mail]>; Vermillion, Dennis
<[e-mail]>; Rahn, Greg <[e-mail]>; Gall, James
<[e-mail]>; Wenke, Steve <[e-mail]>; Lyons, John
<[e-mail]>; 'Gervais Falkner, Linda' <IMCEAEX-
_O=CORP_OU=Site1_cn=Recipients_cn=[e-mail]>; Ehrbar, Pat <[e-mail]>;
McGregor, Ron <[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>;
Avista Corp.2021 Electric IRP Appendices 739
5
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; Coelho, Renee <[e-mail]>; Dempsey, Tom C
<[e-mail]>; Bryan, Todd <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; Ash Awad <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; Shane, Xin <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; Soyars, Darrell <[e-mail]>;
'[e-mail]' <[e-mail]>; Miller, Joe <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; Kimmell, Paul <[e-mail]>; Lee, Lisa <[e-mail]>;
Tatko, Mike <[e-mail]>; Trabun, Steve <[e-mail]>; Vincent, Steve
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; Forsyth, Grant <[e-mail]>;
Bonfield, Shawn <[e-mail]>; '[e-mail]' <[e-mail]>;
Steiner, Nolan <[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>; Maher,
Patrick <[e-mail]>; Kinney, Scott <[e-mail]>; Thackston, Jason
<[e-mail]>; Holland, Kevin <[e-mail]>; Rothlin, John
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; McClatchey, Erin <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; Fielder, Casey <[e-mail]>;
Kacalek, Sean <[e-mail]>; Browne, Terrence <[e-mail]>;
'[e-mail]' <[e-mail]>; Sprague, Collins
<[e-mail]>; '[e-mail]' <[e-mail]>; Schlect, Jeff
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; Smith, Jennifer <[e-mail]>; Howard, Bruce
<[e-mail]>; Magalsky, Kelly <[e-mail]>; 'nathan.weller@Pullman-
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; Andrea, Michael <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; Dillon, Mike
<[e-mail]>; '[e-mail]' <[e-mail]>; Pardee, Tom
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; Finesilver, Ryan <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; Matt
Nykiel <[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
Avista Corp.2021 Electric IRP Appendices 740
6
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; Phil Jones <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; Kyle Murphy <[e-mail]>;
'[e-mail]' <[e-mail]>; Schuh, Karen <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; Kelly Hall <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; Schultz, Kaylene
<[e-mail]>; '[e-mail]' <[e-mail]>; Tyrie, Mary
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; Rose, Melanie <[e-mail]>; '[e-mail]'
<[e-mail]>; Kara Odegard 2 <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; Brown, Garrett <[e-mail]>; Ericksen, Ryan
<[e-mail]>; '[e-mail]' <[e-mail]
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; Kimball, Paul <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>;
Hermanson, Lori <[e-mail]>; Ghering, Amanda <[e-mail]>;
'[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; McDougall, James
<[e-mail]>; '[e-mail]' <[e-mail]>; Gross, John
<[e-mail]>; Fisher, Damon <[e-mail]>; Spratt, Dean
<[e-mail]>; Vlad Gutman <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>
Subject: Avista Draft TAC 2 Presentations for 8/6/20

Hello TAC members,

Here are the draft presentations for Thursday’s joint meeting with the Natural Gas TAC and the call in information for
the meeting.

Thank you,

John Lyons
Avista Corp.
Avista Corp.2021 Electric IRP Appendices 741
7
509-495-8515

.........................................................................................................................................
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of the intended recipient, or if this message has been addressed to you in error, please immediately alert the sender by reply email and then delete this
message and any attachments.
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Do not click on links or open attachments that are not familiar.
For questions or concerns, please e-mail [e-mail]
Avista Corp.2021 Electric IRP Appendices 742
1
Gall, James
From:Tina Jayaweera <[e-mail]>
Sent:Friday, February 26, 2021 4:41 PM
To:Lyons, John; Gall, James; Finesilver, Ryan
Cc:Daniel Hua
Subject:[External] RE: Avista's Draft 2021 Electric IRP
Attachments:Avista 2021 Draft Electric IRP_councilstaff.pdf
Hi Avista team,
Thanks for the opportunity to review the draft 2021 Electric IRP. Council staff appreciate the level of engagement from
are asking for clarification or additional detail. However, one more substantial comment from staff is on the market
price forecast:

Preliminary market price forecasts for the 2021 Power Plan diverge from the pricing regime shown in this draft
IRP. While understanding the underlying cause of that divergence would take a deep dive into our respective AURORA
runs, given our work thus far we would expect that it’s related to allowing AURORA to construct new natural gas
generation outside the Northwest to replace expected retirements in the WECC thermal generation fleet (and the
associated volume of those retirements).

We were given guidance from the Council and from our advisory committees to limit the potential for new natural gas
generation both inside and outside the region. In doing so, we see a wave of solar and wind generation construction
that depresses future market prices substantially lowering them from prices seen today. While this is largely outside of
the control of the region, it presents substantial risk to regional utilities making decisions consistent with market prices
that assume natural gas resources will set the marginal price.

We’d encourage all the utilities in the Northwest, including Avista, to test any IRP-based decisions against an
aggressively low market price forecast. Many things are uncertain about the future of the power system in the
WECC. We would not want to represent any forecast, including our own, as certain. But we do think it’s a risk to
consider and one that will be developing rapidly over the next few years.

While we’re still working on the 2021 Power Plan, we’d be happy to share an AURORA archive file of the work done to
date.

Tina Jayaweera (she/her)
Northwest Power & Conservation Council
503-222-5161

From: Lyons, John <[e-mail]>
Sent: Monday, January 4, 2021 3:20 PM
To: '[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; Kalich, Clint <[e-mail]>; Vermillion, Dennis
<[e-mail]>; Rahn, Greg <[e-mail]>; Gall, James
<[e-mail]>; Wenke, Steve <[e-mail]>; Lyons, John
<[e-mail]>; Ehrbar, Pat <[e-mail]>; McGregor, Ron
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
Avista Corp.2021 Electric IRP Appendices 743
2
<[e-mail]>; Coelho, Renee <[e-mail]>; Dempsey, Tom
<[e-mail]>; Bryan, Todd <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; Shane, Xin <[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; Soyars, Darrell <[e-mail]
<[e-mail]>; Miller, Joe <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; Kimmell, Paul
<[e-mail]>; Lee, Lisa <[e-mail]>; Tatko, Mike <[e-mail]>;
Trabun, Steve <[e-mail]>; Vincent, Steve <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; Forsyth, Grant <[e-mail]>; Bonfield, Shawn
<[e-mail]>; Steven Simmons <[e-mail]>; Steiner, Nolan
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; Maher, Patrick
<[e-mail]>; Kinney, Scott <[e-mail]>; Thackston, Jason
<[e-mail]>; Holland, Kevin <[e-mail]>; Rothlin, John
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; McClatchey, Erin <[e-mail]>;
Elizabeth Osborne <[e-mail]>; Gillian Charles <[e-mail]>;
'[e-mail]' <[e-mail]>; Fielder, Casey <[e-mail]>;
Kacalek, Sean <[e-mail]>; Browne, Terrence <[e-mail]>;
'[e-mail]' <[e-mail]>; Sprague, Collins
<[e-mail]>; '[e-mail]' <[e-mail]>; Schlect, Jeff
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; Howard, Bruce <[e-mail]>; Magalsky, Kelly
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>; Andrea, Michael
<[e-mail]>; '[e-mail]' <[e-mail]>; Tina Jayaweera
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>; Dillon,
Mike <[e-mail]>; '[e-mail]' <[e-mail]>; Pardee, Tom
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; Finesilver, Ryan
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; Schuh, Karen
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]'
Avista Corp.2021 Electric IRP Appendices 744
3
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; Schultz, Kaylene
<[e-mail]>; '[e-mail]' <[e-mail]>; Tyrie, Mary
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; Rose, Melanie <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; Brown, Garrett
<[e-mail]>; Ericksen, Ryan <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; Kimball, Paul
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; Hermanson, Lori <[e-mail]>; Ghering, Amanda
<[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>;
McDougall, James <[e-mail]>; '[e-mail]' <[e-mail]>; Gross, John
<[e-mail]>; Fisher, Damon <[e-mail]>; Spratt, Dean
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; Daniel Hua <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>;
Brandon, Annette <[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; Majure, Jaime <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>
Subject: Avista's Draft 2021 Electric IRP

Hello TAC Members,

Attached is a copy of the draft 2021 Electric IRP for your review. Please provide any comments or edits back to us by
Monday, March 1, 2021 to me at [e-mail]. The final IRP and completed appendices will be filed on
April 1, 2021 with the Idaho and Washington Commissions.

Our fifth and final TAC meeting will be held on Thursday, January 21, 2021. The meeting invitation and agenda will be
available by the end of this week. There will also be an opportunity to provide written comments about the draft IRP to
Avista Corp.2021 Electric IRP Appendices 745
4
the Washington Commission and a public meeting on February 23, 2020. We will provide more details at the fifth TAC
meeting.

Thank you for all of your participation in the 2021 IRP,

John Lyons
Avista Corp.
509-495-8515

CONFIDENTIALITY NOTICE: The contents of this email message and any attachments are intended solely for the addressee(s) and may contain
confidential and/or privileged information and may be legally protected from disclosure. If you are not the intended recipient of this message or an agent of the intended recipient, or if this message has been addressed to you in error, please immediately alert the sender by reply email and then delete this
message and any attachments.
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Do not click on links or open attachments that are not familiar.
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Avista Corp.2021 Electric IRP Appendices 746
Northwest Power and Conservation Council
In line comments on draft Electric IRP

Page 13: See comment in email re: suggestion to do sensitivity study with significantly
lower market prices
Page 16: DR capability is for summer or winter or either?
Page 16: In section 5, the target EE is 113 aMW
Page 57: Be more clear which climate trend you are using from the Council, as we have
several projected futures
Page 66: Is there any analysis of how climate change will affect hydro availability on a
monthly basis?
Page 87: Also, the achievable technical potential includes a max achievability. Did the
CPA use the 7P or the 2021P assumptions?
Page 88: I read this that AEG didn't use the RBSA, which is fine if Avista has sufficient
res data, but it would be good to explain this. Also, since CBSA is regional, how was it
downscaled to Avista. Perhaps this is in the CPA report?
Page 89: I don't understand this sentence
Page 90: How are these adjusted? Since the 2021P starts in 2022, what recent
accomplishments would be incorporated?
Page 90: I think this is a bit confusing - i would recommend breaking out the "ramp rate"
from the "achievability factor", since the 85- 100% is not really the ramp rate
Page 91: Incorrect units
Page 91: Typo in figure "cumulative". Also, the terminology is getting confusing here,
you mean achievable *economic* potential, right?
Page 92: It's a little confusing that this chart goes to 2045, while the above table is
through 2041. Add a sentence in paragraph above about that?
Page 93: 2022-2023, right?
Page 94: If this is utility cost, not total cost, then what assumption was made for portion
of total cost made for by the utility?
Page 97: I'm not sure what this is referencing. The methodology we recommend uses 5-
10 years historic and/or forward-looking, data available. What is this referencing?
Page 97: Non-energy impacts could be benefits or costs
Avista Corp.2021 Electric IRP Appendices 747
Page 97: There is also language in the report about how these values should not be
used past 2022.
Page 98: Given how Avista's generation supply is getting cleaner over the IRP time
horizon, is that incorporated into this analysis?
Page 98: Has applying the 10% credit for Idaho been discussed?
Page 107: I'm confused about the numbers in this bullet compared to the bullet above
that indicates the TOU opt-in has a 4.3 MW potential
Page 109: Are these costs net of anything? e.g. T&D deferrals? How are incentives
treated? It would be helpful to have a brief discussion of what is included in the levelized
cost calcs.
Page 109: It might be nice to have these presented in order of increasing cost?
Page 111: 8 continuous hours? That is quite long for a DR program
Page 120: How is this price determined?
Page 172: How are you incorporating other states (mostly CA) clean energy policies?
Page 179: It's not clear if/how REC prices are being incorporated
Page 193: Since renewables have zero emissions, it seems that they would be more
often built in a SCC world, and thus there would be less interaction between the thermal
plant and the market price.
Page 194: It is not intuitive why there would be less wind in the SCC scenario
Page 229: I think this is an overly pessimistic view of HPs. Newer units that are installed
well with good controls can certainly provide a capacity benefit. I see later you explore
the impact of higher efficiency units which is good. This leads me to think the Avista EE
program should be focused more on ensuring installed ASHP are operating optimally

Avista Corp.2021 Electric IRP Appendices 748
1
Gall, James
From:Gall, James
Sent:Monday, March 1, 2021 12:01 PM
To:Tina Jayaweera; Lyons, John; Finesilver, Ryan
Cc:Daniel Hua; Kalich, Clint
Subject:RE: [External] RE: Avista's Draft 2021 Electric IRP
Hi Tina and Dan,

Thank you for the review of our document. I’ve conducted a quick look at your comments and it appears you spend
regarding the price forecast. I have concerns that prices going forward will be extremely volatile, more than Aurora can
quantify, much of this volatility will depend on how much and if capacity resources will be developed or not- I also think
its appropriate to understand the risk of higher and lower prices. From my work in the short term, Avista’s price
forecasts are too low- specifically not including risk premiums we are seeing from resource adequacy issues we are
seeing. Although, in the long run there is significant downward risk with more renewables- I guess this future will
depend on how far policy makers will take goals and ambitions to actual operations and construction.

There will also likely be a feedback loop as well- such as changes in loads (both industrial losses and electrification
opportunities and political changes due to ramifications of policy changes) and storage opportunities. I think storage
could be key in keeping prices from getting too low- but that will depend on future costs of that technology. I guess
where I’m going is there is a number of paths the future may take us and its really an issue of how much time should we
make to look at the region versus our portfolio.

The way things are trending I would say more focus is going toward our portfolio. In this case the real risk of having too
low of forecast for prices could have an effect of less acquisition of EE, but in the end with our requirements of having
clean energy and capacity- the price forecast really only impacts a solar vs wind decision- but so far wind is winning that
decision due to capacity requirements and over reliance of solar elsewhere; then they question of should we build
natural gas or storage-
pondering for some time do price forecasts really matter for resource planning- given we have fewer resources to
choose from and specific requirements to meet. For example, the energy price used to be a major component of our EE
avoided cost- now the highest component is social cost of carbon and non-energy benefits- its seems the world has
shifted from energy price forecasts.

Thanks for raising this important issue.

James

From: Tina Jayaweera <[e-mail]>
Sent: Friday, February 26, 2021 4:41 PM
To: Lyons, John <[e-mail]>; Gall, James <[e-mail]>; Finesilver, Ryan
<[e-mail]>
Cc: Daniel Hua <[e-mail]>
Subject: [External] RE: Avista's Draft 2021 Electric IRP

Hi Avista team,
Avista Corp.2021 Electric IRP Appendices 749
2
Thanks for the opportunity to review the draft 2021 Electric IRP. Council staff appreciate the level of engagement from
are asking for clarification or additional detail. However, one more substantial comment from staff is on the market
price forecast:

Preliminary market price forecasts for the 2021 Power Plan diverge from the pricing regime shown in this draft
IRP. While understanding the underlying cause of that divergence would take a deep dive into our respective AURORA
runs, given our work thus far we would expect that it’s related to allowing AURORA to construct new natural gas
generation outside the Northwest to replace expected retirements in the WECC thermal generation fleet (and the
associated volume of those retirements).

We were given guidance from the Council and from our advisory committees to limit the potential for new natural gas
generation both inside and outside the region. In doing so, we see a wave of solar and wind generation construction
that depresses future market prices substantially lowering them from prices seen today. While this is largely outside of
the control of the region, it presents substantial risk to regional utilities making decisions consistent with market prices
that assume natural gas resources will set the marginal price.

We’d encourage all the utilities in the Northwest, including Avista, to test any IRP-based decisions against an
aggressively low market price forecast. Many things are uncertain about the future of the power system in the
WECC. We would not want to represent any forecast, including our own, as certain. But we do think it’s a risk to
consider and one that will be developing rapidly over the next few years.

While we’re still working on the 2021 Power Plan, we’d be happy to share an AURORA archive file of the work done to
date.

Tina Jayaweera (she/her)
Northwest Power & Conservation Council
503-222-5161

From: Lyons, John <[e-mail]>
Sent: Monday, January 4, 2021 3:20 PM
To: '[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; Kalich, Clint <[e-mail]>; Vermillion, Dennis
<[e-mail]>; Rahn, Greg <[e-mail]>; Gall, James
<[e-mail]>; Wenke, Steve <[e-mail]>; Lyons, John
<[e-mail]>; Ehrbar, Pat <[e-mail]>; McGregor, Ron
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; Coelho, Renee <[e-mail]>; Dempsey, Tom
<[e-mail]>; Bryan, Todd <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; Shane, Xin <[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; Soyars, Darrell <[e-mail]
<[e-mail]>; Miller, Joe <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; Kimmell, Paul
<[e-mail]>; Lee, Lisa <[e-mail]>; Tatko, Mike <[e-mail]>;
Trabun, Steve <[e-mail]>; Vincent, Steve <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>;
Avista Corp.2021 Electric IRP Appendices 750
3
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; Forsyth, Grant <[e-mail]>; Bonfield, Shawn
<[e-mail]>; Steven Simmons <[e-mail]>; Steiner, Nolan
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; Maher, Patrick
<[e-mail]>; Kinney, Scott <[e-mail]>; Thackston, Jason
<[e-mail]>; Holland, Kevin <[e-mail]>; Rothlin, John
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; McClatchey, Erin <[e-mail]>;
Elizabeth Osborne <[e-mail]>; Gillian Charles <[e-mail]>;
'[e-mail]' <[e-mail]>; Fielder, Casey <[e-mail]>;
Kacalek, Sean <[e-mail]>; Browne, Terrence <[e-mail]>;
'[e-mail]' <[e-mail]>; Sprague, Collins
<[e-mail]>; '[e-mail]' <[e-mail]>; Schlect, Jeff
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; Howard, Bruce <[e-mail]>; Magalsky, Kelly
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>; Andrea, Michael
<[e-mail]>; '[e-mail]' <[e-mail]>; Tina Jayaweera
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>; Dillon,
Mike <[e-mail]>; '[e-mail]' <[e-mail]>; Pardee, Tom
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; Finesilver, Ryan
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; Schuh, Karen
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; Schultz, Kaylene
<[e-mail]>; '[e-mail]' <[e-mail]>; Tyrie, Mary
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; Rose, Melanie <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>;
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<[e-mail]>; '[e-mail]' <[e-mail]>; Brown, Garrett
<[e-mail]>; Ericksen, Ryan <[e-mail]>; '[e-mail]'
Avista Corp.2021 Electric IRP Appendices 751
4
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
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<[e-mail]>; '[e-mail]' <[e-mail]>; Kimball, Paul
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; Hermanson, Lori <[e-mail]>; Ghering, Amanda
<[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>;
McDougall, James <[e-mail]>; '[e-mail]' <[e-mail]>; Gross, John
<[e-mail]>; Fisher, Damon <[e-mail]>; Spratt, Dean
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; Daniel Hua <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>;
Brandon, Annette <[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; Majure, Jaime <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>; '[e-mail]'
<[e-mail]>; '[e-mail]' <[e-mail]>;
'[e-mail]' <[e-mail]>
Subject: Avista's Draft 2021 Electric IRP

Hello TAC Members,

Attached is a copy of the draft 2021 Electric IRP for your review. Please provide any comments or edits back to us by
Monday, March 1, 2021 to me at [e-mail]. The final IRP and completed appendices will be filed on
April 1, 2021 with the Idaho and Washington Commissions.

Our fifth and final TAC meeting will be held on Thursday, January 21, 2021. The meeting invitation and agenda will be
available by the end of this week. There will also be an opportunity to provide written comments about the draft IRP to
the Washington Commission and a public meeting on February 23, 2020. We will provide more details at the fifth TAC
meeting.

Thank you for all of your participation in the 2021 IRP,

John Lyons
Avista Corp.
509-495-8515

CONFIDENTIALITY NOTICE: The contents of this email message and any attachments are intended solely for the addressee(s) and may contain
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of the intended recipient, or if this message has been addressed to you in error, please immediately alert the sender by reply email and then delete this
message and any attachments.
Avista Corp.2021 Electric IRP Appendices 752
5
USE CAUTION - EXTERNAL SENDER
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For questions or concerns, please e-mail [e-mail]
Avista Corp.2021 Electric IRP Appendices 753
February 5, 2021
Mark Johnson
Executive Director and Secretary
Washington Utilities and Transportation Commission
621 Woodland Square Loop SE
Lacey, WA 98504-7250
RE: Comments of Renewable Northwest, Docket UE-200301
Utilities and Transportation Commission’s January 5, 2021, Notice of Opportunity to File
Written Comments Relating to Avista’s 2021 Draft Integrated Resource Plan for
Electricity, Docket UE-200301.
I. INTRODUCTION
Renewable Northwest thanks the Washington Utilities and Transportation Commission (“the
Commission”) for this opportunity to comment in response to the Commission’s January 5,
2021, Notice of Opportunity (“Notice”) to File Written Comments relating to Avista Corporation
d/b/a Avista Utilities’ (“Avista” or “the Company”) 2021 Draft Integrated Resource Plan (“Draft
IRP”) for Electricity, published January 4, 2021.
Renewable Northwest participated in Avista’s Technical Advisory Committee (“TAC”) meetings
during development of the Draft IRP, and we were generally pleased with the Company’s
consideration of stakeholder input during its public participation phase. Still, we have noted in
these comments various areas for improvement in the Draft IRP for Avista and the Commission
to consider, bearing in mind the important role of this IRP to plan for compliance with the clean
energy standards of Washington’s Clean Energy Transformation Act (“CETA”), and as such, to
inform Avista’s first Clean Energy Implementation Plan (“CEIP”), set to be published later this
year. 1
In these comments, we identify areas where Avista’s Draft IRP does not align with the most
current resource costs and characteristics. We offer recommendations for revising Avista’s
flexibility analysis, resource adequacy considerations, and sensitivity analyses with the goal of
nudging the Company toward a least-cost portfolio with the best likelihood of meeting CETA’s
clean energy standards.
1 WAC 480-100-640
Feb. 5, 2021 Comments of Renewable Northwest, Docket UE-200301 Page 1 of 8
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Avista Corp.2021 Electric IRP Appendices 754
Finally, we appreciate Avista’s commitment to achieving carbon neutrality in its electric
operations by 2027 and to provide customers with one hundred percent carbon-free electricity by
2045. We think the Company is making strides in creating a path toward meeting those goals, 2
but we urge Avista and the Commission to consider where the Draft IRP may be hindered by
traditional resource planning assumptions not relevant to an energy transformation toward a
dynamic mix of non-emitting resources. We look forward to continued participation in the
development of Avista’s 2021 IRP.
II. COMMENTS

A.Regulatory Context

CETA broadly requires Washington utilities to achieve greenhouse gas neutrality by 2030 and to
serve Washington customers with one hundred percent non-emitting and renewable electricity by
2045. Utilities must identify steps to achieve these standards using the new tool of Clean Energy 3
Implementation Plans, and those CEIPs must in turn “identify specific actions to be taken by the
investor-owned utility over the next four years, ​consistent with the utility's long-range integrated
resource plan​ and resource adequacy requirements, that demonstrate progress toward meeting
the standards under RCW 19.405.040(1) and 19.405.050(1)” as well as interim targets to ensure
incremental progress. 4

The Commission worked for months with many stakeholders, including Renewable Northwest,
to craft new rules aligning utility IRPs with CEIPs and CETA’s substantive requirements. These
new rules point to some key downstream effects of IRPs: first, “[t]he commission will consider
the information reported in the integrated resource plan when it evaluates the performance of the
utility in rate and other proceedings” ; and second, a utility’s “CEIP must describe how [its] 5
specific actions ... [a]re consistent with the utility's integrated resource plan.” The main 6
takeaway of this structure is that it is important to get as much correct as possible in the IRP, as
analytical missteps could have repercussions both for utility cost recovery and for achieving
CETA’s critically important substantive standards.

With that backdrop in mind, we offer the following comments on Avista’s Draft IRP, assessing
elements of the Draft IRP not only against specific provisions of the Commission’s rules as
2 Avista Connections, ​available at
https://www.myavista.com/connect/articles/2019/08/this-is-clean-energy-for-the-future​.
3 RCW 19.405.040(1) & 19.405.050(1) (emphasis added).
4 RCW 19.405.060(1)(b)(iii).
5 WAC 480-100-238(6).
6 WAC 480-100-640(6)(d).
Feb. 5, 2021 Comments of Renewable Northwest, Docket UE-200301 Page 2 of 8
Avista Corp.2021 Electric IRP Appendices 755
appropriate, but also against the broader context of how the information in this IRP will be used
in future planning, procurement, and ultimately cost recovery efforts.

B.Supply Side Resource Options

Assumptions

Avista may have rounded up its solar capital costs, judging by current estimates, but the
Company should consider revising its solar capital costs to reflect the slightly lower values
estimated at this time. For example, Lazard’s Levelized Cost of Energy Analysis for 2020
estimates solar capital costs to lie in the range of $825 to $975. 7

Considering Avista’s assumptions for lithium-ion battery storage, we recommend the Company
review the data informing the levelized cost ($/kW) for the preferred 4-hour lithium-ion battery,
as there appears to be a gradual price increase after 2033 rather than a steady decline, which
would be expected. For example, the National Renewable Energy Laboratory’s (“NREL”) 2020 8
Annual Technology Baseline (“ATB”) reports a trend of cost reductions (illustrated as $/kW in
Figure 1​) through to 2050.

Figure 1.​ Li-ion battery storage projection (in $/kW) from NREL’s Annual Technology Baseline 2020. 9

7 ​See, e.g.​, Lazard’s Levelized Cost of Energy Analysis (Oct. 2020), at 11, ​available at
https://www.lazard.com/media/451419/lazards-levelized-cost-of-energy-version-140.pdf​.
8 Table 9.7. Lithium-ion Levelized Cost $/kW, p. 9-14
9 Battery Storage cost values from W. Cole and A. W. Frazier, “Cost Projections for Utility-scale Battery Storage:
2020 Update,” NREL/TP-6A20-75385. Golden, CO: National Renewable Energy Laboratory, ​available at
https://www.nrel.gov/docs/fy20osti/75385.pdf​.
Feb. 5, 2021 Comments of Renewable Northwest, Docket UE-200301 Page 3 of 8
Avista Corp.2021 Electric IRP Appendices 756

Ancillary Services Value
We appreciate Avista’s proactive approach in valuing ancillary services of emerging resources
using sub-hourly modeling. Because there are a number of impending questions that the
Company is working through, the comments provided below will shed some light on the broader
concept of system flexibility and how emerging resources are able to provide the flexibility
needs arising from an increasing share of renewable resources in a reliable manner.

Flexibility has always been part of power system operation because the normal demand for
electricity varies significantly on a daily and seasonal basis. Traditional approaches to planning
have supported flexibility that is sufficient to meet load reliably. However, increasing renewable
generation sources may make traditional approaches to planning inadequate to ensure sufficient
flexibility. System flexibility can be characterized along four dimensions: first, the ​absolute
power output capacity​ range (in “MW”); second, the​ ​speed of power output change​, or ramp
rate (in “MW/min”); third, the ​duration of energy levels​ ​(in “MWh”); and finally the ​carbon
intensity​ ​(in “CO​2​e/MWh”). Resources which have a larger range between their minimum and
maximum “MW” output, such as pumped-hydro storage systems, can provide the flexibility to
adjust to a wider range of power system conditions. Resources that can change their output
quickly or can be easily turned on or off, including 2-, 4- & 6-hour lithium-ion, flow battery
storage systems and demand response (“DR”), have a higher ramp rate and are more flexible
because they adjust faster to changes in power system conditions. Resources which can deliver
energy for longer durations increase flexibility because they can address prolonged disturbances
or outages. Resources such as conventional combustion turbines and combined cycle can provide
dispatchable power but have low capacity utilization and are emission-intensive when ramped up
or down rapidly. These different dimensions are important to consider in any holistic flexibility
analysis and, thus, in calculating benefits, considering not just the frequency of flex violations
but their magnitude, speed, duration, and carbon intensity.

In addition to the ADSS system, we recommend the use of the PLEXOS model to simulate
generation on a sub-hourly timescale to calculate the balancing reserve requirements and the
associated system costs and benefits to meet those intra-hourly dispatch requirements, as legally
enforced through NERC’s BAL series standards. As defined in BAL-005.5, each Balancing
Authority Area is required to have Automatic Generation Control (“AGC”), calculate Area
Control Error (“ACE”), and deploy balancing reserves to balance resources and demand. It is
important to recognize that with the changing supply-and-demand paradigm, flexibility needs are
changing as system variability migrates from load to generation. With Avista’s participation in
the Energy Imbalance Market (“EIM”), it has the ability to tap into the diversity benefits of
multiple resources to balance their demand and supply.

Feb. 5, 2021 Comments of Renewable Northwest, Docket UE-200301 Page 4 of 8
Avista Corp.2021 Electric IRP Appendices 757
At the same time, new technologies (such as controllable solar and wind power plants, battery
storage systems, pumped-hydro systems, and demand response resources) and operational
practices provide new options for flexibility. These emerging needs and solutions increase the
benefit of a transparent flexibility value, which can help system operators efficiently maintain
reliability and enable market participants to make informed investments. Controllable solar and
wind power plants have the ability to respond to dispatch instructions much more quickly than
conventional generators, in addition to having a zero variable cost. “Flexible solar” not only
contributes to solving operating challenges related to solar variability but can also provide grid
services, essentially creating dispatchable renewable power plants. A similar study was 10
conducted by Avangrid, NREL, and GE showing that a utility-scale wind power plant can
provide regulation-up, regulation-down, and other grid services. Since the flexibility benefit is 11
calculated based on the difference between “day-ahead” and “intra-hour” dispatch, resources
with zero variable cost and fast response times, like controllable renewable, battery storage,
demand response and pumped-hydro, would generate much higher values than conventional
thermal resources. In addition, it has also been proven through many studies that geographical 12
resource diversity and aggregation reduce the need for reserve requirements by reducing
short-term variability. 13

In conclusion, we appreciate the effort Avista has put into modeling ancillary services and
providing draft results to stakeholders, but we recommend additional considerations to (i)
operational flexibility (both up & down) offered by controllable solar and wind power plants, (ii)
detailed analysis of multiple lithium-ion battery durations to the flexibility resource options, (iii)
the modeling of sensitivities around the nameplate capacity of flexible resources, and (iv) the
draft value of “diversity savings” from participation in the EIM. In addition, it would be useful to
see different dimensions of the flex violations and how they are being addressed using the fleet
of resources modeled in the flex analysis conducted using PLEXOS. We are also interested to
view the flex benefit results coming out of the modeling for pumped-hydro and DR resources,
which we believe would be higher than conventional solutions to provide the necessary
intra-hourly supply and load flexibility.

Resource ELCC Analysis
10 Investigating the Economic Value of Flexible Solar Power Plant Operation First Solar & E# Study. October 2018.
https://www.ethree.com/wp-content/uploads/2018/10/Investigating-the-Economic-Value-of-Flexible-Solar-Power-Pl
ant-Operation.pdf
11 Avangrid Renewables: Demonstration of Capability to Provide Essential Grid Services..
http://www.caiso.com/Documents/WindPowerPlantTestResults.pdf
12 Determining Utility System Value of Demand Flexibility From Grid-interactive Efficient Buildings.
https://pubs.naruc.org/pub/2E1DDEEC-155D-0A36-3137-0FC3D941B1A4
13 Ancillary Service and Balancing Authority Area Solutions to Integrate Variable Generation. Available at:
https://www.nerc.com/files/ivgtf2-3.pdf

Feb. 5, 2021 Comments of Renewable Northwest, Docket UE-200301 Page 5 of 8
Avista Corp.2021 Electric IRP Appendices 758
While we appreciate the detailed analysis that Avista has conducted and the provision of peak
capacity credit values for different supply side resource options, we are concerned that these
values significantly under value storage and hybrid resources.

To start, the Draft IRP references an E3 report in stating that, “4-hour duration storage can
provide high levels of resource adequacy in small quantities because it has other resources to
assist in its re-charging; but as its proportion gets larger, there is not enough energy to refill the
storage device for later dispatch.” This statement is confusing and misrepresents operating 14
characteristics and values of energy storage systems. As we know, reliability should be valued
during the times when the system is in stress (i.e. hours with the highest probability of loss of
load). As Avista mentions, 4-hour duration storage can provide high levels of resource adequacy.
The quantity of adequacy depends on the operating characteristics of the power plant and how it
is being operated to meet the reliability risks. In addition, storage capacity can be easily refilled
during off-peak hours when solar and wind are usually curtailed (mid-morning for solar and late
night for wind), either directly or indirectly, from the grid. It is also worth noting that hybrid
resources are not physically restricted to charge from the renewable component since the Federal
Investment Tax Credit (ITC) is a financial not a physical restriction. Thus, a power plant
operator may choose to charge the storage partially from the grid to ensure that it meets the
capacity requirement during critical periods.

The Draft IRP also mentions that “[h]igher levels of penetrations for renewables may lower their
effect on resource adequacy.” While this statement is true due to diminishing marginal ELCC
from increasing penetration of renewables, it is also true that the capacity credit of storage
increases with increasing penetration of renewables since they are complementary resources, by
changing the shape of net demand patterns and effectively shifting delivery of energy to meet the
reliability needs. An analysis conducted by Astrape Consulting commission by joint IOUs in 15
California showed that solar paired with 4-hour storage provides greater than 95% ELCC on
average including analysis and values pertaining to the BPA region. Avista’s value provided in 16
Table 9.12 shows a 17% value which is extremely low based on recent IRP filings and technical
reports in the region. Therefore, we recommend Avista study for its final IRP the different
operational configurations and characteristics of hybrid resources and standalone storage to
correctly evaluate the resource ELCC value.

14 P. 9-27
15 The Potential for Battery Energy Storage to Provide Peaking Capacity in the United States. Denholm et al, 2019.
Available at:
https://www.osti.gov/biblio/1530173-potential-battery-energy-storage-provide-peaking-capacity-united-states
16 2020 Joint CA IOU ELCC Study Report 1. Astrape Consulting. August 2020. Available at:
https://www.astrape.com/2020-joint-ca-iou-elcc-study-report-1/
Feb. 5, 2021 Comments of Renewable Northwest, Docket UE-200301 Page 6 of 8
Avista Corp.2021 Electric IRP Appendices 759
C.Preferred Resource Strategy

To begin, we request that Avista incorporate the results of its 2020 Renewable RFP in the
preferred resource strategy (“PRS”) for its final IRP, including how Avista’s improved
knowledge of current market prices may adjust resource assumptions informing the 2021 IRP
model.

We appreciate Avista’s transparency in revealing that the early economic contractual exit from
Colstrip Units 3 & 4 would benefit its Washington and Idaho customers. If the joint owners of
this resource were to agree on the terms of early exit from or retirement of these units, it would
in part be because of this modeling effort by Avista. However, we recognize the complexity of
exiting a jointly-owned resource, and we understand Avista’s decision to maintain the 2025
Colstrip exit date in its PRS.

As indicated above, Avista may be undervaluing storage and hybrid resources, especially
considering Washington’s and the entire region’s transition away from fossil resources, thus
increasing the penetration of renewables on the grid and the capacity credit of storage. Avista
does note their intention to study additional benefits of storage by modeling additional scenarios
including price and renewable penetration. We hope Avista will conduct these analyses to 17
inform the PRS of the final IRP, as we urge the Company and the Commission to acknowledge
that traditional methods of resource planning -- especially those driving standards for
determining resource adequacy -- will likely continue to favor new natural gas builds and delay
the clean energy transition.

Avista mentions throughout the Draft IRP that upon exit from coal contracts by 2025, limited
capacity options are available as replacement. For example, Avista notes, “With the exit of
Colstrip and the expiration of the Lancaster PPA in the fall of 2026, the PRS adds 211 MW of
natural gas-fired CTs. The 2020 IRP assumed the capacity lost from Colstrip and Lancaster
could be met with long duration pumped hydro, but the updated cost and construction schedule
information for pumped hydro caused this resource to not be selected in this IRP.” For the 18
Commission and stakeholders to better understand why Avista’s capacity needs can only be met
with new natural gas peaking capacity, we recommend that Avista provide at its upcoming TAC
meeting or publish in its final IRP a projected loss-of-load event, displaying by hour where there
is a deficiency in available capacity. This could be in the form of a 12x24 matrix of the peak
demand or hours with the highest loss of load probability which were used to calculate the ELCC
values for all resources. 19
17 P. 9-26
18 P. 11-5
19 ​See, e.g.,​ Energy+Environmental Economics (E3), “Capacity Value Framework & Allocation Options,” Oregon
Feb. 5, 2021 Comments of Renewable Northwest, Docket UE-200301 Page 7 of 8
Avista Corp.2021 Electric IRP Appendices 760

D.Portfolio Scenario Analysis

While there is certainly value in many of Avista’s twenty modeled sensitivities, we recommend
the Company conduct one additional analysis to better understand how policy-driven changes in
Avista’s resource mix should impact the way the Company plans for meeting demand reliably
and at least cost. For example, especially considering our previous comments regarding pricing
and ELCC values for storage resources, a sensitivity analysis of must-take storage (not limited
by resource type or duration characteristics) combinations in place of new natural gas peaking
plants would inform Avista how much current storage technologies would change levelized
portfolio costs. Avista’s Portfolio #5 -- “Clean Resource Plan (2027)” -- does not prohibit new
gas procurements, and Portfolio #6 -- “Clean Resource Plan (2045)” -- does prohibit new gas
procurements but curiously allows Colstrip to exit at any time. 20
III. CONCLUSION

Renewable Northwest thanks Avista and the Commission for its consideration of this feedback.
We are optimistic that the changes and additional analysis we have recommended above will
help Avista to identify a least-cost portfolio that also puts the Company on a path to achieving
CETA’s clean energy standards and the company’s own emission reduction goals. We look
forward to continued engagement as a stakeholder in this 2021 IRP process.

Sincerely,

Public Utilities Commission (UM 2011) at slide 39 (Jul. 9, 2020), ​available at
https://edocs.puc.state.or.us/efdocs/HAH/um2011hah17397.pdf​.
20 P. 12-6
Feb. 5, 2021 Comments of Renewable Northwest, Docket UE-200301 Page 8 of 8
/s/ Katie Ware
Katie Ware
Washington Policy Manager
Renewable Northwest
[e-mail]
/s/ Sashwat Roy
Sashwat Roy
Technology & Policy Analyst
Renewable Northwest
[e-mail]
/s/ Max Greene
Max Greene
Regulatory & Policy Director
Renewable Northwest
max​@renewablenw.org
Avista Corp.2021 Electric IRP Appendices 761
220 NW 8th Ave. Portland, OR 97209

1
February 5, 2021
Puget Sound Energy
355 110th Ave NE Bellevue, WA 98004
RE: Comments of Swan Lake and Goldendale Avista Corporation – Draft Integrated Resource Plan UTC Docket UE-200301 The companies working to develop the Swan Lake and Goldendale pumped hydro storage
projects (“Swan Lake and Goldendale”) appreciate Avista Corporation’s (“Avista”) work that
went into preparing its draft Integrated Resource Plan (“Draft IRP”), which was filed in the above-referenced proceeding on January 4, 2021. The Washington Utilities and Transportation Commission (“Commission”) subsequently issued a notice, on January 5, 2021, indicating it would accept comments on Avista’s Draft IRP until February 5, 2021.1 In response to that
notice, Swan Lake and Goldendale are filing these comments.
These comments advocate for Avista to further consider pumped storage resources instead of new natural gas facilities, which are politically infeasible to build and do not align with Washington State’s Clean Energy Transformation Act (“CETA” requirements. Specifically, these comments:
(1) seek further information regarding Avista’s modeling and assumptions for pumped storage;
(2) argue that Avista should not seek to construct new gas facilities, given the current political realities associated with new gas facilities and CETA’s requirements; and (3) advocate for Avista to issue a capacity request for proposals (“RFP”) as soon as possible, as an RFP is the only mechanism through which Avista will receive accurate pricing and capacity proposals, particularly
for large resources like pumped storage.
I. Overview of Pumped Storage in the Draft IRP According to Avista’s Draft IRP, long duration pumped hydro storage was identified as the
capacity resource to meet future long duration deficits; however, it appears the Draft IRP did not
include them in the Preferred Resource Strategy because “long duration pumped hydro is likely available later than the timelines used in the 2020 IRP and at higher costs.”2 As a result, the Draft IRP states, “The resource analysis identifies a natural gas CT to replace resource deficits if pumped hydro is not a feasible resource to meet the 2026 shortfall.”3 These statements suggest that pumped
storage was Avista’s preferred resource, if not for a mismatch in timing and updated cost figures.

1 Notice of Opportunity to File Written Comments, Docket UE-200301, Jan. 5, 2021, available at:
https://www.utc.wa.gov/_layouts/15/CasesPublicWebsite/GetDocument.ashx?docID=11&year=2020&docketNumber=200301.
2 Draft IRP at 14-5. 3 Id.
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Avista Corp.2021 Electric IRP Appendices 762
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Through these comments, Swan Lake and Goldendale suggest that Avista reconsider including pumped storage in its Preferred Resource Strategy. Specifically, as further explained below, Swan Lake and Goldendale are two of the most mature projects in the region, one of which (Swan Lake)
is likely to be available in 2026, which matches Avista timeline of capacity need. Furthermore,
Swan Lake and Goldendale are in the process of refining their cost assumptions and, should Avista issue an RFP, would likely be able to provide update cost figures that may make pumped storage a more attractive option, particularly considering the infeasibility of constructing a new natural gas plant, as explained below.
II. Swan Lake and Goldendale Request Further Information on Avista’s Modeling Assumptions for Pumped Storage Swan Lake and Goldendale appreciate that Avista has been forthcoming with a significant amount
of data that was used to develop the Draft IRP. That said, Swan Lake and Goldendale request
Avista provide some additional information and data on the modeling assumptions used for the various pumped storage resources considered in the Draft IRP. Specifically, Swan Lake and Goldendale request further information regarding: (1) the “state of charge” assumed by Avista in order to develop its capacity values for pumped storage, as seen in Table 9.12; (2) what duration
Avista assumed for the useful life of a pumped storage project; and (3) whether Avista’s analysis
of pumped storage considered the Swan Lake project specifically, which is expected to be available in 2026 and, therefore, aligns with Avista’s capacity need.
a. Swan Lake and Goldendale Request Further Information on Avista’s Modeling
Assumptions Regarding a Pumped Storage Project’s State of Charge

Swan Lake and Goldendale believe one of the impediments to long-duration pumped storage performing even better in Avista’s Draft IRP is the very low capacity values being assigned to pumped storage resources. For example, Table 9.12 indicates an 8-hour pumped storage project would only contribute 30% to Avista’s peak capacity need, and even a 12-hour project would
contribute only 58%.4 Considering these figures are much lower than Swan Lake and Goldendale
would expect, and drastically lower than those used by other utilities in the Pacific Northwest,5 Swan Lake and Goldendale request that Avista provide further information regarding the assumed “state of charge” for these resources. Swan Lake and Goldendale assume the “state of charge”
assumptions are the genesis for these low figures.
If the highest priority for pumped storage is reliability, then Avista would always have the ability to charge it for its longest available durations, eight hours or more. Understanding that Avista will always prioritize reliability over economic optimization, adjustments to the state of charge
modeling may be appropriate. Swan Lake and Goldendale believe that Avista’s model may be
using a very low state of charge entering into the next operating day for pumped storage (possibly as low as 20% pond fill); however, this planning assumption does not align with the operational

4 Id. at 9-28, Table 9.12. 5 Swan Lake and Goldendale would also note for the Commission’s benefit that both PacifiCorp and Portland General Electric use capacity contribution figures in the range of 80-95% for pumped storage in their respective IRPs.
Avista Corp.2021 Electric IRP Appendices 763
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3
realities associated with operating hydro or pumped storage facilities. Operationally, peak load days are fairly predictable, meaning that Avista’s operations folks would set up for those days in advance to ensure its hydro (or pumped storage) facilities have sufficient pond fills to cover the
expected peak load hours. Furthermore, the pumped hydro facility would not necessarily need to
deplete its full reservoir daily to address capacity needs (low frequency of 8-hour reliability events), reducing the total amount of charging required to address all potential loss of load events. A low capacity contribution value (ELCC) for pumped hydro implies that the facility is energy
limited and does not have access to the market or other on-system resources to charge for peak
load events. Swan Lake and Goldendale understand that Avista may be concerned about the evolving market for peak import assumptions during the winter, given the emerging regional capacity shortage documented in several NWPCC studies. However, import assumptions during off-peak hours in the winter should be re-visited, given that these would be key hours when long-
duration storage would charge for the winter on-peak reliability. Additionally, if not already doing
so, Swan Lake and Goldendale recommend that Avista consider optimizing the dispatch of their resources over a wider time window (1-2 weeks). A wider optimization time window in resource adequacy models allow for greater operational flexibility of long duration storage and minimize the need for daily charging and discharging. For the foregoing reasons, at minimum, pumped
storage should be treated like a traditional hydro facility with storage capability, which the Draft
IRP assigns a 60-100% peak capacity credit.6
b. Swan Lake and Goldendale Request Further Information on Avista’s Assumed Useful Life for a Pumped Storage Project

Similarly, Swan Lake and Goldendale request that Avista provide further information on the assumptions they used for the expected useful life of a pumped storage project. Swan Lake and Goldendale’s experience—which is informed by discussions with pumped storage turbine manufacturers and industry examples throughout the U.S. and abroad—suggests that a pumped
storage resource’s useful life is, at minimum, 40 years, and more likely will last 50 years or more.
Using an appropriate useful life will ensure pumped storage’s costs are properly considered over the long time horizon in which a pumped storage resource will continue to reliably operate.
c. Swan Lake and Goldendale Request Further Information on Whether Avista’s
Pumped Storage Analysis Specifically Considered the Swan Lake Project
Given the statements in the Draft IRP noted above regarding a potential mismatch of timing, Swan Lake and Goldendale request further information from Avista on whether it specifically considered the Swan Lake project. While both Swan Lake and Goldendale are among the most mature and
viable pumped storage projects in the region, it appears Avista’s analysis assumes Swan Lake will
not be available to meet its small 2026 capacity need of 12 MW, nor would Swan Lake be available to meet the much larger need of 301 MW in 2027.7 However, Swan Lake is expected to achieve commercial operation in late-2026, so Swan Lake and Goldendale are concerned that Avista’s

6 Draft IRP at 9-28, Table 9.12. 7 See id. at 7-3.
Avista Corp.2021 Electric IRP Appendices 764
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4
analysis is not considering the Swan Lake project, despite it being a viable option that aligns with Avista’s capacity needs.
Furthermore, Avista’s capacity figures assume Colstrip remains part of its portfolio through 2025;
however, this assumption may not be prudent, considering the faster-than-expect push to retire coal plants throughout the region. In a scenario where Colstrip retires earlier than expected—which Swan Lake and Goldendale believe is more likely than not—Avista’s capacity need would significantly increase, thereby further supporting Avista’s early action on a potential capacity RFP,
as further explained in Section IV below.
III. The Draft IRP Should Remove New Natural Gas as a Viable Resource Option In addition to the CETA requirements that mandate the removal of emitting generation sources
from Avista’s generation portfolio, Governor Inslee also recently announced legislation that would
phase out all natural gas in homes and businesses by 2050.8 Furthermore, Avista has a stated goal of having a carbon neutral electricity supply by 2027 and having 100 percent clean electricity by 2045.9
Given these recent developments, which highlight the unfriendly political environment for natural
gas, instead of proposing to construct new natural gas facilities, Avista should focus its efforts on a Preferred Resource Strategy that aligns with both CETA and this evolving political landscape. To the extent Avista believes new natural gas resources are allowable under CETA, Swan Lake and Goldendale request that Avista provide a detailed explanation for why a new gas resource
would meet one of the few and limited CETA provisions allowing construction of such resources,
particularly including violation of reliability standards and, if violations are possible, whether pumped storage could help alleviate or solve those potential violations. Furthermore, considering the unfriendly political climate for new gas resources and Avista’s own commitments to transitioning to a carbon-free future, Swan Lake and Goldendale request that Avista re-run its IRP
analysis with a constraint of no new natural gas resources. Doing so would likely result in pumped
storage being in the Preferred Resource Strategy, considering the statements noted above. Swan Lake and Goldendale would also remind Avista and the Commission that, Avista need only look to Portland General’s IRP process for evidence of the political realities associated with
permitting new gas resources. Specifically, a few years ago, Portland General attempted to expand
its Carty Generating Station (referred to as “Carty 2”). When Portland General proposed expanding the capacity of Carty in its IRP process, significant stakeholder opposition immediately arose and effectively killed the gas-fired plant as a potential solution to meet Portland General’s future capacity needs. Therefore, Avista should be aware that environmental groups, renewable
resource developers, and many stakeholders will likely align to uniformly oppose any new gas
facility. As a result, Avista should instead remove new gas as an option from its Draft IRP and re-

8 See Washington State Proposes Legislation to Phase Out Natural Gas Utility Service, S&P Global, Jan. 6, 2021,
available at: https://www.spglobal.com/marketintelligence/en/news-insights/latest-news-headlines/washington-state-proposes-legislation-to-phase-out-natural-gas-utility-service-61819435.
9 Avista Declares Clean Electricity Goal, April 18, 2019, available at: https://www.myavista.com/-/media/myavista/content-documents/our-environment/cleanelectricitygoalnewsrelease-pdf.pdf.
Avista Corp.2021 Electric IRP Appendices 765
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5
run the analysis to determine a Preferred Resource Strategy that aligns with both CETA and Avista’s own climate goals.
IV. Swan Lake and Goldendale Strongly Support Avista Issuing a Capacity RFP As Soon As Possible In the Draft IRP, Avista indicates may release a capacity RFP as early as 2021. Specifically, the Draft IRP states, “To meet the January 1, 2026 capacity shortfall and to validate Avista’s preferred
choice of long duration pumped hydro to meet this deficit, Avista may release a capacity RFP as
early as 2021. . . Avista is still committed to releasing a capacity RFP subject to the needs of the final 2021 IRP.”10 Swan Lake and Goldendale strongly support Avista’s plan to release a capacity RFP as soon as possible.
While Swan Lake and Goldendale have highlighted some of their concerns regarding the modeling
and assumptions used for pumped storage in these comments, the only accurate way for Avista to fully evaluate potential pumped storage projects—including the various projects’ pricing information, timing for construction, and whether the operating characteristics align with Avista’s needs—is through actual proposals received through an RFP. Without an actual offer submitted
through an RFP, Avista will be relying on its own assumptions and expectations regarding the
price, timing, and operating characteristics of pumped storage. Furthermore, because pumped storage resources are relatively unfamiliar to many utilities in the Pacific Northwest, these resources are at a disadvantage in the IRP modeling and evaluation process, particularly when compared to other resources with which utilities are more familiar and have better data.

Therefore, Swan Lake and Goldendale overwhelmingly support Avista issuing a capacity RFP as soon as possible to evaluate potential clean-capacity resources to meet its identified capacity needs. Swan Lake and Goldendale request that Avista confirm its intention to do so and, if necessary, the Commission and Commission Staff specifically direct Avista to prepare and issue such an RFP as
promptly as possible.

10 Draft IRP at 14-5.
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V. Conclusion Swan Lake and Goldendale appreciate the opportunity to provide these comments on the Draft
IRP. While Swan Lake and Goldendale are encouraged by some of the statements in the Draft
IRP that suggest pumped storage is the preferred resource, Swan Lake and Goldendale believe further work needs to be done on the pumped storage modeling and analysis, as well as to remove natural gas as a viable option for fulfilling Avista’s future capacity needs.
If you have any questions, please contact the undersigned.

Sincerely,
/s/ Nathan Sandvig
Nathan Sandvig [e-mail]

Avista Corp.2021 Electric IRP Appendices 767

February 5, 2021

Mark Johnson, Executive Director/Secretary
Washington Utilities and Transportation Commission
1300 S. Evergreen Park Dr. S.W., P.O. Box 47250
Olympia, Washington 98504-7250

Re: Avista 2021 Draft Integrated Resource Plans for Electricity and Natural Gas
Dockets UE-200301 (electricity) and UG-190724 (natural gas)

Mr. Johnson;

The NW Energy Coalition (“NWEC” or “Coalition”) appreciates the opportunity to comment on
the draft Integrated Resource Plan (“IRP”) submitted by Avista Utilties on January 4th, 2021, per
the Notice of Opportunity to File Written Comments issued by the Commission on January 5th,
2021.

The Coalition is an alliance of more than 100 organizations united around energy efficiency,
renewable energy, fish and wildlife preservation and restoration in the Columbia basin, low-
income and consumer protections, and informed public involvement in building a clean and
affordable energy future.

The Coalition notes Avista’s timely submission of a draft integrated resource plan (IRP) in
compliance with the schedule established by the Commission. We hope our comments will
be useful in revising the IRP for its final submission. The utilities must soon prepare their first
CEIPs under CETA. It is extremely important that the IRP/CEAP be technically correct and
thorough, since it “informs” the CEIP. The specific actions the utility plans to undertake as
described in the CEIP per 19.405.060(1)(b)(i) and (iii) are intended to be informed and
consistent with the IRP. Shortcomings in an IRP/CEAP must not be used as a means to limit the
utilities’ attainment of CETA standards in their CEIP. A CEIP based on an insufficient IRP/CEPA
analysis that fails to create a path towards meeting the 2030 standards will not be acceptable.

Our comments address both the overall context for planning and specifics issues in the IRP.

The standard for integrated resource planning has changed

Unlike previous planning cycles, CETA unequivocally established standards for 2030 and 2045.
The approach to integrated resource planning and resource acquisition planning should have
changed accordingly. IRPs are no longer simply analyzing lowest reasonable cost alternatives,
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Avista Corp.2021 Electric IRP Appendices 768

but lowest reasonable cost alternative pathways that lead to achieving the 2030 and 2045
standards. That is the analysis needed to provide the data and context for specific targets and
actions in the CEIP.

CETA’s intent is to transform the electric system - it requires a utility to: (1) eliminate coal fired
resources from a utility’s allocation of electricity by the end of 2025; (2) achieve cost-effective
conservation and efficiency to reduce load; (3) reduce demand as much as possible with
demand response actions; and (4) use electricity from renewables and non-emitting generation
1 to serve 80% of the remaining retail load by 2030, and 100% by 2045.
This first round of IRPs under CETA should be clearly focused on how to reach the goals, not
how to approximate the standards or to reach a utility’s own vision of “carbon neutrality”,
while ignoring the statutory requirements.
Avista’s explanation for the Clean Energy Targets table (CEAP p. 15-4, table 15-2) indicates that
may be the case in the CEAP. Avista raises the strawman that “use” of electricity from
renewable and non-emitting sources means “minute-by-minute tracking” of electrons. That is
not the case. While the rules regarding “use” are still being developed, the language of the
statute is clear. As Avista states in the introduction to the CEAP “this Action Plan is subject to
change prior to the April 1, 2021 IRP filing date to account for potential renewable resource
acquisitions from the 2020 Renewable FRP and as final CETA rules by the Washington Utility
and Transportation Commission (WUTC) are issued”. An IRP should analyze the various
pathways to meet the standards as set out in statute.

For example, using the data from that chart for a quick “back of the envelope” calculation, it
appears likely that Avista could meet the 2030 compliance standards for using electricity from
renewables and non-emitting to meet the 80% standard. Using the data in WA Clean Energy
Targets table 15.2, adjusting the net retail load of 641 aMW in 2030 to 80% amounts to 512.8
aMW. Most of that can be met with the 436 aMW from the renewable resources Avista
already owns. The shortfall of 76.8 aMW can be met with a little more than half of the planned
144 aMW from Montana wind. The 20% portion of retail sales, or 128.2 aMW, could be met
with various other resources listed on that chart.

Key Outcomes for the 2021 Avista IRP

The Avista 2021 IRP has two high priority tasks:
• First, to set a new direction in electric system planning in accordance with the policy
direction and compliance requirements of CETA. Both the policy and compliance
aspects are important.

• Second, to address system needs after the conclusion of 222 MW of coal plant service to
Avista customers by the end of 2025, as required by CETA, and other system changes,
especially the termination of the Lancaster 257 MW natural gas contract in 2026.
Avista Corp.2021 Electric IRP Appendices 769

Recognizing that the draft IRP takes significant steps in the right direction, NWEC believes
additional improvements can be made for both tasks. We address these questions below in
two sections focusing on the overall IRP and the 2027 preferred resource portfolio.

While the draft IRP is not fully complete, Avista has presented a clear and detailed analysis,
provided work products and responded to stakeholder questions. The preferred portfolio
continues to develop energy efficiency and begins to lay out a strategy for acquiring demand
response resources, although we believe the targets can be increased and the pace can be
accelerated. The treatment of new renewable resources is somewhat more mixed, as
described below. Finally, significant improvement is needed for both the cost and capacity
value battery and pumped storage.

We also give special commendation to Avista’s Energy Equity analysis in chapter 13. This is a
strong first step in assessing energy burden and service quality across Avista’s Washington
service territory, especially for vulnerable populations and highly impacted communities.
Avista’s work is already setting a standard for utilities across the Northwest. We look forward
to further enhancements, including assessment of whether services and programs for customer
side resources like energy efficiency, demand response, distributed generation and electric
vehicle support are equitably available.

All that said, a significant question still should be addressed. While the draft IRP anticipates
retirement of Colstrip coal as early as 2021 and Lancaster gas in 2026, we are concerned about
the addition of 211 MW of new gas peaking capacity in 2027 to help address the gap. A new
peaker unit of that size would have a capital cost above $200 million, with additional fixed and
variable O&M including fuel cost, and would continue in operation for many years. We believe
further analysis will show that there are substantial available and cost-effective clean energy
resources that can defer or eliminate this new emitting resource.

Cross-Cutting Issues for CETA Policy and Compliance

A. Natural Gas Resource Risk

Even if the Avista gas fleet as a whole operates at a lower annual capacity factor over time,
continued additions of new gas capacity resources could pose both reliability and cost
concerns. Recent episodes including the BC pipeline explosion in October 2018, ongoing
restrictions in pipeline delivery and Jackson Prairie storage through the spring of 2019, and
more recently maintenance problems on the Williams pipeline through the Columbia Gorge in
the fall of 2020, highlight the tenuous situation for gas deliverability.

B. Market Reliance

Avista Corp.2021 Electric IRP Appendices 770

We commend Avista for a thorough market analysis (chapter 10) and provide the following
observations.

The price and availability risk in the short-term market (primarily the Mid-C trading hub) has
been growing in recent years. Underlying recent price disturbance episodes, including very high
prices in February-early March 2019 due to exceptionally cold weather and gas delivery
constraints, there is an underlying structural change in the Northwest bilateral market with two
key drivers.

First, a recent PacifiCorp presentation in an IRP workshop shows that the transaction volume
for the Mid-C trading hub has basically fallen in half over the last five years. There is some
evidence that much of the decline is the result of transactions moving to the Energy Imbalance
Market which is more liquid and has a favorable real-time pricing regime compared to the
outmoded high load hour/low load hour Mid-C construct. While EIM energy flows to load in an
economically beneficial manner, the EIM cannot assist with day-ahead and operational unit
commitment and dispatch.

Second, the retirement of Northwest coal resources and other changes is continuing to
diminish market supply relative to demand. This poses increasing price and availability risk
going forward.

Two other developments may counter the trend somewhat. For short term capacity, the
proposed Northwest Power Pool resource adequacy program could alleviate peak risk both
through advance commitments and an operational program. On the energy side, the Enhanced
Day Ahead Market expansion of the EIM could move forward, providing much deeper and more
liquid market access.

All that said, we conclude that the short-term market is increasingly risky, but we are also
confident that enhanced development of clean energy resources can help reduce market
exposure.

C. Social Cost of Greenhouse Gases (SCGHG)

The IRP analysis states “construction and operational greenhouse gas emissions are considered
and priced using the SCC”, but that the SCGHG was not applied to market purchases and sales
in the PRS as done previously. The reason for the change from previous practice is not clear.
The statute at 19.280.030(3)(a) states a utility must incorporate the SCGHG when evaluating
and selecting conservation policies, programs and targets; when developing integrated
resource plans and clean energy action plans; and when evaluating and selecting intermediate
term and long-term resources. The SCGHG is a variable cost used in planning to internalize the
costs of emitting CO2e. The SCGHG does not function as a tax that is passed through to
customers. In the modeling process, for both the IRP and CEAP, the SCGHG should be applied
to variable costs, dispatch modeling and unspecified or fossil fueled market purchases.
Avista Corp.2021 Electric IRP Appendices 771

The impact of adding the SCGHG to market purchases is tested in portfolio #19 – SCC on
Purchases/Sales Resource Selection (IRP p. 12-29). This results in relatively little impact relative
to the PRS portfolio, except to select less solar. That result might well change if hybrid
resources, such as solar+battery were assessed, instead of charging storage with market
purchases.

Further, the Optimized SCGHG Carbon Future Portfolio shown in Table 12.24 not only improved
costs over the PRS, reduced natural gas by 88MW and increased energy efficiency and wind.
This option also reduced solar, but probably for the same storage charging reasons as in
portfolio #19.

In the final IRP/CEAP Avista should model a portfolio in which the SCGHG is optimized as a
variable cost and applied to unspecified and fossil fueled electricity brought in state for
customer use. This portfolio should also include hybrid resources, as discussed later.

D. Upstream Methane Emissions

An issue linked to the application of SCGHG is the life cycle emissions for gas power plants. As
we explained in a submission to the Northwest Power and Conservation Council,1 recent peer-
reviewed research has revised upstream methane emissions factors sharply upward. Because
of the current and proposed new addition of natural gas generation, we urge Avista to revisit
this issue and adjust the upstream methane emissions factor represented in the Social Cost of
Greenhouse Gas analysis.

2027 Preferred Resource Portfolio

With the cessation of coal power supply after 2025 and the expiration of the Lancaster gas
contract in 2026, the year 2027 is a useful point for evaluating system need and proposed new
resources.

In 2027, the draft IRP indicates a need for 301 MW of capacity. The draft proposes to fill the
gap with ongoing energy efficiency, the beginning of a demand response program, 200 MW of
Montana wind, a 12 MW upgrade at Kettle Falls, and 211 MW of peaker resources (85 MW for
Idaho and 126 MW for Washington/Idaho).

NWEC believes further review is needed on several categories of clean energy resources to see
if they can provide additional capacity value and defer or eliminate the need for new peaker
resources.

1 NWEC letter to Northwest Power and Conservation Council, June 15, 2020,
https://www.nwcouncil.org/sites/default/files/2020_0616_2.pdf
Avista Corp.2021 Electric IRP Appendices 772

A. Two Types of Capacity Need

The pivotal point to understand about the period after 2026 is that there are basically two
types of capacity need. We refer to these as typical and long-duration peak periods.

A typical peak period is that observed in most years, where demand peaks within a range
described by the median or “1-in-2” demand forecast.

Once or more per decade, a long-duration peak condition may occur, with extended high daily
peaks that may recur for two or more consecutive days, as reflected in a “1-in-10” forecast. In
the winter, these conditions may occur during very cold “Arctic express” periods where demand
is very high on a sustained level and renewable energy production is low. In such conditions,
the entire Northwest will be energy limited, market supply will be very expensive and perhaps
restricted, and gas supply from Canadian sources and storage withdrawals may also be
constrained.

In the late summer, similar heat wave conditions may occur. The reduced availability of hydro
peaking compared to winter stress conditions is an additional factor.

The question we pose is whether a staged approach to capacity need could provide a balanced
2027 resource portfolio that is better aligned with CETA policy guidance while meeting
reliability needs cost-effectively.

The first stage involves maximizing the availability of so-called “energy limited” clean flexible
resources, including demand response and storage. These are generally considered to provide
capacity value of 4 hours duration and should suffice for meeting needs during typical peak
periods.

In the second stage, meeting rare long-duration peaks requires supplemental resources. The
draft IRP suggests that new peakers can meet these supplemental needs. But once these very
expensive and high-emitting new peakers are put into the resource mix, the IRP models will
dispatch them not only for very infrequent long duration high peaks, but much more often
across the year because they are now “existing” resources. As a result, these new peakers will
displace less expensive, non-emitting resources. This creates a lost opportunity for CETA
compliant clean energy resources.

Avista should investigate the availability of firm capacity or other term resources to meet
infrequent long-duration event needs, for example from regional imports or merchant gas
plants. As time goes on, those resources could be replaced with new long-duration storage
from sources such as renewable hydrogen, renewable natural gas and pumped storage.

Below, we suggest the additional potential for clean flexible resources including demand
response, storage and hybrids to meet typical peaks.
Avista Corp.2021 Electric IRP Appendices 773

B. Demand Response

The Conservation Potential Assessment (CPA) includes estimates for the technically available
potential of demand response, and the preferred portfolio includes initial steps toward
achieving that potential.

The CPA summarizes the technically achievable potential for DR at 90 MW in 2025 (about 5.1%
of peak load) and 170 MW in 2045 (almost 10% of peak). NWEC agrees that this is a reasonable
magnitude for total potential, but we believe it can be achieved considerably faster.

The preferred portfolio indicates 53 MW of DR in 2027 (3% of peak) in 2027. We believe
further assessment will show this amount can be increased.

For example, we estimate about 7 MW per year of technically achievable potential is available
from one specific resource – stock turnover and conversion to grid enabled residential electric
water heaters, or about 35 MW between now and 2027. In addition, new construction and gas-
to-electric conversions could increase the potential. This resource is facilitated by
Washington’s incoming requirement for all new electric water heaters to have a CTA-2045
communications interface, providing a common access standard.

It remains to be seen what level of customer participation can be achieved for a grid enabled
water heater program, but we anticipate that with effective customer engagement strategies it
can be higher than the 50% saturation assumed by Avista and the savings potential of 48.9 MW
by 2045 can be increased and significantly accelerated.

For demand response and load management as a whole, it is apparent that program launches
can be moved forward considerably. In the Clean Energy Action Plan, Table 15.1 indicates that
the first programs will appear in 2024, and the last in 2031. It would make more sense to
launch a coordinated set of DR programs earlier so they can scale up rapidly to meet capacity
need in 2027 and beyond. Portland General Electric has already succeeded in taking that path,
including both coordinated pilot programs and the Smart Grid Testbed. Their new Flexible Load
Plan lays out a strategy for moving DR to full maturity in the next 5 years.

C. Storage Cost
Avista Corp.2021 Electric IRP Appendices 774

NWEC believes that most of the reference resource costs in the draft RFP are in the reasonable
range, though we may have different views on specific resources and future cost trajectories.

However, the future costs for batteries and pumped storage simply don’t seem reasonable.
The values in Figure 9.1 show slight declines in battery costs, and then flat or rising costs
through the remainder of the planning horizon. Most other estimates show consistently
declining costs through the coming decades, though at varying rates.

Avista Corp.2021 Electric IRP Appendices 775

Cost Projections for Utility-Scale Battery Storage, National Renewable Energy Laboratory
(2019). NREL/TP-6A20-73222, https://www.nrel.gov/docs/fy19osti/73222.pdf

Turning to pumped storage, the draft IRP states:

With the exit of Colstrip and the expiration of the Lancaster PPA in the fall of 2026, the
PRS adds 211 MW of natural gas-fired CTs. The 2020 IRP assumed the capacity lost from
Colstrip and Lancaster could be met with long duration pumped hydro, but the updated
cost and construction schedule information for pumped hydro caused this resource to
not be selected in this IRP. This modeling result is consistent with a scenario analysis
performed in the 2020 IRP showing natural gas CTs would be required if low cost long-
duration pumped hydro was not available by 2026. Avista will continue to follow
pumped hydro developments for future consideration.
Draft IRP at 11-5.

Table 9.6, Pumped Hydro Company-Owned Options, provides a summary of costs, but NWEC
does not fully understand the presentation and has not been able to pinpoint the underlying
data for this conclusion. There are at least two pumped hydro projects with a reasonable
chance of commercial operation by 2027, and further specific project assessment would be
useful.

D. Storage and Hybrid Capacity Value

Avista Corp.2021 Electric IRP Appendices 776

A notable aspect of the preferred portfolio is the lack of composite (hybrid) resources before
2038, when the first solar+battery resource appears.

The rapid emergence of hybrid resources around the nation and in the Northwest indicates the
importance of composite resources to meet both energy and capacity needs. A leading
example is PGE’s acquisition of a large portion of the NextEra Wheatridge project, an innovative
three-way hybrid of wind, solar and storage.

With regard to PacifiCorp’s current all-source RFP, it is widely expected that solar+battery
hybrids will be selected for half or more of the total acquisition, potentially amounting to more
than 2000 MW of solar capacity and over 1000 MW of battery storage.

A recent study by Astrape Consulting for Pacific Gas & Electric, Southern California Edison and
San Diego Gas & Electric found a substantial increase in ELCC value for Northwest (BPA
Balancing Area) wind hybrid resources. No value for solar hybrids was provided for the
Northwest because of insufficient data, but the effect is expected to be similar.

The values in the Astrape analysis are not directly comparable because they are with reference
to California ISO summer peak conditions. That said, the dramatic effect of battery availability
to shift energy to peak periods is clear. Yet the draft IRP indicates only a 17% peak credit value
for solar plus 4-hour battery resources and 15% for standalone 4-hour storage.

Avista Corp.2021 Electric IRP Appendices 777

Whether the renewable resource is Montana wind with batteries or pumped storage shifting
energy into the morning and evening peaks, or eastern Washington solar plus batteries shifting
mid-day peak solar into late afternoon demand, NWEC views Table 9.12 as likely
underestimating peak value. In addition, there is no value listed for wind + storage (either
battery or pumped hydro), which is a clearly relevant use case.

As Avista proceeds towards the 2021 capacity RFP, we encourage revisiting this key issue.
Hybrid resources could provide a significant capacity benefit and defer the need for new gas
peakers, as well as make more effective use of limited available transmission capacity for
renewables and provide more operating flexibility.

Conclusion

The Coalition appreciates the work that has gone into the preparation of this draft IRP. We look
forward to collaborating on analyzing the changes we have suggested.

Respectfully,

Joni Bosh Fred Heutte
Senior Policy Associate Senior Policy Associate
NWEC NWEC
[e-mail] [e-mail]

Avista Corp.2021 Electric IRP Appendices 778

BEFORE THE WASHINGTON UTILITIES AND TRANSPORTATION COMMISSION

1 Electric Integrated Resource
Avista 1 Natural Gas Integrated

DOCKET UG-190724

COMMISSION STAFF COMMENTS REGARDING
AVISTA CORPORATION d/b/a AVISTA UTILITIES DRAFT INTEGRATED RESOURCE PLANS SUBMITTED IN COMPLIANCE WITH RCWs 19.405, 19.280 and WACs 480-90-238, 480-100-600 through -630
AND UNDER CONSOLIDATED DOCKETS UE-191023 AND UE-190698,
Order R-601 February 5, 2021
Avista Corp.2021 Electric IRP Appendices 779
Contents
Introduction ................................................................................................................................... 2 Summary of Staff Assessment.................................................................................................. 2
Gas Transportation Customer Conservation ......................................................................... 3
Recommendations related to the 2021 Final IRP................................................................... 4
Recommendations for the CEIP and future IRP planning cycles ........................................ 5
Staff Assessment of 2021 Draft Integrated Resource Plan by Focus Area ................................... 7 Clean Energy Action Plan ........................................................................................................ 7
Climate change ........................................................................................................................ 10
Load Forecasting ..................................................................................................................... 12
Upstream Emissions & SCGHG ............................................................................................ 13
Sub-hourly Modeling Capabilities......................................................................................... 14
Demand-Side Resources and Distributed Energy Assessments.......................................... 15
Distribution Planning and Non-Wires Alternatives ............................................................ 18
Nonenergy Impacts ................................................................................................................. 19
Customer Benefit Provisions in CETA ................................................................................. 20
Resource Adequacy Assessment and Uncertainty Analysis ................................................ 21
State Allocation of Resource Need ......................................................................................... 23
Electrification Scenarios ......................................................................................................... 23
Public Participation ................................................................................................................ 24
Data Disclosure........................................................................................................................ 25
Natural Gas Design Day (Planning Standard) ..................................................................... 26
Natural Gas CPA and Conservation Targets ....................................................................... 26
Renewable Natural Gas (RNG) ............................................................................................. 27

Appendices
Appendix 1: Rules and statutes overview
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Introduction

On January 4, 2021, Avista Corporation d/b/a Avista Utilities (Avista or company) submitted its
draft Integrated Resource Plan (Draft IRP) in Dockets UE-200301 and UG-190724. The
Washington Utilities and Transportation Commission (UTC or commission) posted a Notice of Opportunity to File Written Comments and Notice of Recessed Open Meeting. Written
comments are due by February 5, 2021, and the recessed open meeting is scheduled for 9:30 a.m.
on Tuesday, February 23, 2021. The company will file its completed 2021 IRP (Final IRP) with
the Commission by April 1, 2021.1
Commission staff (Staff) prepared these comments to assess whether Avista’s Draft IRP satisfies
the rules and statutes governing the company’s IRP filings, highlight areas of strength in the
Draft IRP, suggest opportunities for improvement in the final IRP, and make recommendations
for the clean energy implementation plan and the next integrated resource planning cycle. In
developing these comments, Staff consulted with Jeremy Twitchell from Pacific Northwest National Laboratory.

Summary of Staff Assessment
Electric: Avista’s public process, data transparency, and analysis of results were executed well.
While the company’s handling of equity and the customer benefit mandate is understandably
underdeveloped, Staff is comfortable with the trajectory and looks forward to working closely with the company. However, the company’s Draft IRP can be improved in terms of clarity and
thoroughness in certain areas. Staff has concerns that the utility is undervaluing flexible resources such as storage, solar, and distributed energy resources (DERs), because of incomplete analysis
of the impact of climate change, lack of sub-hourly modeling, the lack of a comprehensive DER
resource assessment, and limited application of nonenergy impacts.
Avista plans to meet or exceed the clean energy standard by acquiring 375 MW of clean energy resources by 2031. As shown in Figure 1, the preferred portfolio (or preferred resource strategy
as labeled in the Draft IRP) has Avista economically exiting Colstrip in 2021 and over 300 MW
of natural gas plants by 2040. The preferred resource strategy includes the addition of new
natural gas peakers for system reliability in 2027 and 2036. Natural gas: Overall, Staff is satisfied with Avista’s analysis and resulting preferred portfolio
for natural gas with the data available to-date and through Advisory Group participation. Without
inclusion of the appendices with the Draft IRP, there are details missing Staff has not been able
to fully analyze. Given that no new, large resource acquisitions are anticipated for natural gas this document is heavily focused on the electric IRP. Recommendations for the IRP process for natural gas often overlap with electric; Staff provides targeted comments on separate areas
specific to natural gas.

1 See Docket UE-180738, Order 02 (Nov. 7, 2019) and Docket UG-190724, Order 01 (Feb. 6, 2020).
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Figure 1: 2021 Preferred Resource Strategy2

Gas Transportation Customer Conservation
One tangential issue Staff brings to the Commission’s attention is the requirement in RCW
80.28.380 for the utilities to identify and acquire all conservation measures that are available and
cost-effective. While it has been the practice of the utilities to exclude gas transportation customers from participating in their conservation programs, Staff struggles to find an exclusion for gas transportation customers in the statutory language of RCW 80.28.380. Staff notes that the
IRP does not address the provision of gas for these customers; they acquire their own gas. Thus,
the CPA typically included in a gas IRP has not historically included any assessment of
conservation for these customers. There is, however, a linkage between the conservation potential for these very large gas transportation customers and the expected distribution system improvements the company includes in the IRP. Acquiring that conservation should reduce the
need for distribution system improvements.

2 Avista Draft 2021 Electric Integrated Resource Plan, Docket UE-200301, pp. 1-5, Table 1.1 , (Avista Draft Electric IRP) (Jan. 4, 2020).
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Staff expects the issue of conservation from gas transportation customers and its inclusion or
exclusion from the target can be addressed on a case-by-case basis with each company during the
approval of each company’s CPA and target.
Recommendations related to the 2021 Final IRP
• Clean Energy Action Plan o Add a table to the CEAP that includes year-over-year capacity of all planned resources, including demand response.
o Include planned Appendix G with details of about planned transmission and
distribution improvements.
• Climate change o Provide discussion regarding the implications of possibly moving from a winter
peaking utility to a dual or summer peaking utility.
• Load Forecasting
o Clarify the date in which its economic inputs were finalized. o Discuss any adjustments to the forecast made in response to the ongoing
pandemic.
o Clarify the high and low load growth ranges used on page 3-14. For example,
how did the company settle on the high and low assumptions for annual service
area employment and population growth outlined in table 3.3? Please explain. o Discuss the assumptions behind the EV and solar PV forecasts that are inputs
into the load forecast.
o Clarify which of the two climate change forecasts the IRP uses.
• Upstream Emissions & SCGHG o Include in the narrative description required by WAC 480-100-620(11) a clear articulation of how the company calculated the SCGHG.
o Discuss assumptions about the SCGHG in market purchases and charging
storage resources with market purchases.
o Explain why 1.0 percent is an appropriate upstream emissions factor for U.S.
Rockies natural gas.
• Sub-hourly Modeling Capabilities
o Clarify storage cost assumptions.
• Customer Benefit Provisions in CETA o Provide a scenario or, at minimum, a narrative regarding possible changes to
resource decisions that could increase customer benefit.
o If available and time permits, incorporate the DOH data in the CIA.
• Resource Adequacy and Uncertainty o Clarify the company’s peak credit methodology, including the definition of “peak” terms.
o Explain how the company incorporates uncertainty in the RA assessment.
• Public Participation o Provide an IRP update based on any recent planned resource acquisition.
• Data Disclosure
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o Ensure appendices include a record of stakeholder feedback and the company’s
response. o Provide context for the data files provided on the company’s website and submit in the docket.
• Natural Gas Design Day (Planning Standard)
o Explain the new design day methodology.
o Explain why the new design day standard is now the most appropriate one.
• Renewable Natural Gas
o Include details of RNG cost assumptions in the appendices.
Recommendations for the CEIP and future IRP planning cycles
• Climate change
o Incorporate a suite of variables, including snowpack, streamflow, and rainfall
parameters; meteorological trends; and load risks into the analysis. Staff believes
further study is needed.
o Consider additional resources, such as a climatologist or climate change specialist, to analyze climate impacts over time on Avista’s system.
• Load Forecasting
o Conduct a back cast of the load forecasting model, using actual values for their
independent variable inputs to their load forecast to assess whether their models
have systematic bias. o Include a section in the load forecasting chapter that “assess[es] the effect of
distributed energy resources on the utility’s load,” as per WAC 480-100-620(3).
• Sub-hourly Modeling Capabilities o Develop a workplan to expand sub-hourly modeling and discuss with stakeholders.
o Expand sub-hourly modeling capability to appropriately evaluate DERs on equal
footing with utility-scale renewable and other supply-side resource options.
• Demand-Side Resources and Distributed Energy Assessment o Treat DERs as generation resource in modeling, not just net from load. o Optimize DERs with supply-side resources.
o Account for rate increases or pricing signals that can move peak demand and
change DER uptake. o Consider issuing a RFI for DR without prescriptive screens to better understand potential. o Take a proactive approach to DR program implementation in the CEIP,
accounting for longer lead time of customer sited programs.
o Ensure programs in the CEIP are scalable.
• Distribution Planning and Non-Wires Alternatives o Start a public distribution planning process in 2022.
• Nonenergy Impacts
o Identify which nonenergy impacts are required and allowed for resource selection. o Include NEIs for all resources, as appropriate.
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o Consider how NEIs do and do not overlap with equity requirements.
o Identify where real data collection makes sense and where continued use of proxy
is fine.
• Customer Benefit Provisions in CETA
o Incorporate the Department of Health Cumulative Impact Assessment (CIA) into
the IRP CIA.
o Utilize the customer benefit indicators developed through the equity advisory group to design and model a maximum customer benefit scenario.
• Resource Adequacy and Uncertainty
o Incorporate the results of the regional resource adequacy program, as
appropriate. o Discuss “peak” definitions within the advisory group.
• State Allocation of Resource Need
o Facilitate a discussion between Washington and Idaho stakeholders concerning
state allocation of resources.
• Electrification Scenarios o Consider effects of policy trends towards electrification on both the electric and
natural gas systems.
• Public Participation o Provide additional time to review presentations prior to meetings. o Post meeting minutes in a timely manner and allow opportunity for revision.
o Consider if additional staffing is required to adequately meet new IRP
requirements.
• Data Disclosure o Provide contextual aids alongside data input files.
• Natural Gas Design Day (Planning Standard)
o Explore the feasibility of using projected future weather conditions in its design
day methodology, rather than relying exclusively on historic data. The company is conducting a similar analysis for a climate change scenario in its electric IRP.
• Natural Gas CPA and Conservation Targets
• Renewable Natural Gas o Use any up-to-date cost and other data that is available to model potential RNG resources.

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Staff Assessment of 2021 Draft Integrated Resource Plan by Focus Area

Clean Energy Action Plan
To comply with statute and rules, Avista presented a ten-year clean energy action plan that works towards implementing the lowest reasonable cost solution, including incorporation of the social cost of greenhouse gas emissions as a cost adder in its analysis.3 Specifically, each CEAP
should:

• meet clean energy transformation standards, including customer benefit provisions4;
• be informed by the utility’s ten-year cost-effective conservation potential assessment;
• identify the potential cost-effective demand response and load management programs
that may be acquired;
• establish a resource adequacy requirement and demonstrate how each resource,
including renewable, nonemitting, and DERs, may reasonably be expected to contribute
to meeting the utility’s resource adequacy requirement;
• identify any need to develop new, or to expand or upgrade existing, bulk transmission and distribution facilities; and
• identify the nature and extent to which the utility intends to rely on an alternative
compliance option identified under RCW 19.405.040(1)(b), if appropriate.
Avista’s presents its draft CEAP as the lowest reasonable cost plan of acquisitions, given societal cost, clean energy, and reliability requirements.5 Table 15.2 outlines Avista’s CEAP energy-
related projected new resources, identifying the year-over-year, resource ramp needed in the next
ten years to meet energy needs of both Idaho and Washington6 customers, including initial
“targets” to acquire an additional 375 MW by 2031 of new clean energy resources:
• 180 aMW of clean energy by 2031
o 144 aMW (300 MW) of Montana Wind
o 31 aMW from renewing a (75 MW) long-term hydro purchase power agreement
in 2031 o 5 aMW from a 12 MW upgrade to the Kettle Falls Generating Station (existing)
• Along with, under median hydro conditions, 41 aMW of clean energy purchases from
Avista’s Idaho customers and 20 aMW of RECs.7

3 WAC 480-100-620(12).
4 WAC 480-100-610.
5 Avista’s plan exceeds goals of Washington’s Energy Independence Act (EIA), relying on the Palouse and Rattlesnake Flat Wind contracts, generation from the Kettle Falls biomass facility and upgrades to the Clark Fork
and Spokane River hydroelectric developments.
6 Avista notes its CEAP is specific to Washington’s portion of Avista’s system needs in compliance with CETA.
7 Avista notes, depending on the determination of the WUTC’s decision regarding compliance with the 100 percent goal, Avista may need additional clean energy and/or RECs if renewable and non-emitting energy must be delivered
to customers instantaneously. Chapter 12 of the 2021 Draft IRP outlines the cost and energy acquisition impacts of this scenario.
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Avista is planning to procure resources capable of meeting Washington load. Questions remain
regarding whether such resources could be dispatched in a manner to serve Washington demand:
Does this clean energy resource acquisition imply clean energy operations? Operationally, how this energy is getting used and whether such “use” meets the spirit and letter of CETA remains a topic of discussion during Washington clean energy legislation implementation.8

In the Draft CEAP, Avista signaled preference for renewable projects located in vulnerable
population areas to “further develop those economies,” indicating this does not include new generation facilities in Washington except for an upgrade to the Kettle Falls wood-fired facility, which Avista believes is not located in a vulnerable population area.9

Avista also provides a narrative and series of commitments related to the customer benefit
provisions of CETA. The company plans to form an Equity Advisory Group (EAG) that is responsible to review the indicators and vulnerable populations, asserting the EAG will also help guide the design of the vulnerable population outreach and engagement and be used to
distinguish and prioritize additional indicators and solutions needed to develop the upcoming
Clean Energy Implementation Plan. Avista’s CEAP also includes a discussion of its analytical
enhancements to include energy and non-energy benefits, and the company concludes these enhancements should benefit vulnerable communities. Staff agree that identifying non-energy benefits is a good first step towards identifying customer benefit indicators and implementing
programs in a manner that ensures equitable distribution of energy and non-energy benefits.

Staff notes Avista’s projections outlined in this CEAP may change. Avista flagged in its Draft IRP analysis that a future request for proposal (RFP) may identify a lower cost clean resource to meet the first significant reliability shortfall and could yield resources more beneficial than those
more broadly identified in the CEAP.

For the draft CEAP, Staff is unable to provide an overarching recommendation due to the extent of Avista’s draft submittal, including lack of complete appendices and modeling data for examination. However, Staff offers several observations and suggestions for the Final IRP:

CEAP Presentation. The draft CEAP includes Table 15.1 with an outlay of DR programs, from
2024 through 2031, and a narrative, which identifies potential to reduce load by 37.6 MW by 2031, noting a 25 MW large commercial customer program offering may come to fruition before the Lancaster PPA ends in 2026. Staff appreciates the company’s CEAP presentation in Table
15.2, representing the company’s year-over-year resource need in average capacity (aMW), or
the average power output of the facility over a given period, percent clean energy target and goal,
available resources, including owned and contracted, delineated by resource type and general location (as appropriate), and projected shortfall.

8 See “Use” discussion docket notice relating to Clean Energy Implementation Plans and Compliance with the Clean
Energy Transformation Act, Docket UE-191023 (June 12, 2020).
9 Avista Draft Electric IRP at 15-5. Note that Avista formats the pages of the IRP with dashes. To avoid confusion,
throughout these comments Staff cites a single page as “XX-XX”, and multiple pages in the draft IRP with a “XX-XX to XX-XX” format.
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For nameplate capacity presentation (MW), Avista provides Table 1.1 in the IRP, which provides
the company’s “preferred resource strategy” through the 2045 but lists Demand Response at the bottom of the table with no timing specified, other than “2045 capability.”10 Staff points to the new IRP rules, which define CETA-related resource need as:

any current or projected deficit to reliably meet electricity demands created by changes in demand, changes to system resources, or their operation to comply with state or federal requirements. Such demands or requirements may include, but are not limited to, capacity and associated energy, capacity needed to meet peak demand in any season,
fossil-fuel generation retirements, equitable distribution of benefits or reduction of
burdens, cost-effective conservation and efficiency resources, demand response, renewable and nonemitting resources.11 For the final CEAP, Staff suggest Avista also include incremental nameplate capacity (MW), or
maximum capacity, including in tabular form year-over-year, showing the timing of all planned
capacity resources: (1) existing and contracted resources (identified by resource type, location, or
potential location); (2) peak import projections; (3) peak capacity needs before demand-side resources (developed from forecast + planning margin); (4) demand-side resources; and (5) peak capacity resource need net demand-side resources.

CEAP resources. The evaluation of delivery systems, including transmission expansion is
becoming increasingly important because resources are becoming more geographically diverse and shared among utilities.12 The definition of lowest reasonable cost in the IRP rules includes planned resources and “related delivery system infrastructure,” which shows consistency with
chapters 19.280, 19.285, and 19.405 RCW. Staff notes Avista’s CEAP does not discuss
significant transmission or distribution improvements. Instead, the company briefly explains
these resources are “likely to be off system or utilize existing transmission assets, not requiring new investment in the next ten years,” as shown in Appendix G.13 Staff looks forward to reviewing Appendix G in the Final IRP, noting details were not provided for stakeholder review
as part of the Draft IRP.
Recommendations for the Final IRP:
• Add a table to the CEAP that includes year-over-year capacity of all planned
resources, including demand response.

10 Staff notes in Table 1, demand response and load management programs are essentially footnoted, not included in the resource year-over-year ramp in the table or represented side-by-side with other resource type, contracts, or other
plant acquisitions.
11 WAC 480-100-605.
12 Juan Pablo Carvallo et al., Implications of a regional resource adequacy program on utility integrated resource planning - Study for the Western United States, Energy Analysis and Environmental Impacts Division, Lawrence
Berkeley National Laboratory, p. 15, Table 3.5 (November 2020).
13 Avista Draft Electric IRP at 15-4.
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• Include planned Appendix G with details about planned transmission and
distribution improvements. Climate change
Staff is concerned Avista’s modeling of climate change in this IRP is not comprehensive. Avista
considered historical weather trends during load forecasting and ran a climate change scenario.
Still, the possible risks of climate change on resource adequacy and optimal resource portfolio deserve a more complete and nuanced approach in the future.
Avista’s expected case load forecast incorporated historical trends that show HDD gradually
declining and CDD gradually increasing. The company contemplated using two different data
sets of trending HDD and CDD forecasts, one using Avista-specific data and the other using Northwest Power and Conservation Council (NWPCC) state-level data. Both forecasts indicate that Avista’s summer peak will grow faster than the winter peak, with the average summer peak
eventually higher than the average winter peak.14 However, the NWPCC trended forecast shows
the summer peak increasing faster, where the winter peak is growing slower than Avista’s
trended forecast.
Recent regional climate change analysis in the Northwest shows, “anticipated increases in temperature will alter the pattern of electricity use, where higher temperatures and more precipitation tend to result in more rain and less snow during the winter months, thus reducing
the snow pack and subsequent summer flow.”15 Importantly, Avista’s forecast shows the high
end summer peak (95 percent confidence level) is never higher than the high end winter peak,
while the NWPCC forecast shows the high end summer peak is expected to be higher than the winter peak around 2040.16
This analysis demonstrates to Staff there is a strong potential that climate change will likely
move Avista from a winter peaking utility to a dual or summer peaking utility in the near future.
Avista is incrementally moving in the right direction in the 2021 IRP with respect to incorporating the effects of temperature changes over time; but overall, Avista’s climate change
analysis as fairly minimal. The company modeled only one climate shift scenario that
deterministically examined impacts to hydro production and reduced gas plant maximum
capabilities expected to result from climate change. Avista used NWPCC data that estimated additional hydro generation in the winter and less in the spring and summer. To simulate climate change impacts to load, Avista, with assistance from the Pacific Northwest Utility Conference
Committee, used NWPCC data to create linear trends in load by month. This scenario results in
marginally lower wholesale electricity prices and slightly lower emissions due to increased hydro
production.

14 Avista Draft Electric IRP at 3-23, Table 3.7
15 Northwest Power and Conservation Council, “Update on Climate Scenario Selection for the 2021 Power Plan”.
Available at https://www.nwcouncil.org/sites/default/files/2020_04_p2.pdf.
16 Avista Draft Electric IRP at 3-24 to 3-25, Figures 3.20 and 3.21.
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Avista refers to the NWPCC assessment of climate change impacts in its preliminary resource
adequacy assessment presented in December 2020. The company expresses concerns with the
limited inputs used to derive the potential climate adjusted load and hydro conditions but does agree that there are great regional resource adequacy risks in this area.17 Staff agrees and encourages Avista to use more rigor in its analysis exploring the effects of climate change on
their system.

Further, to adequately account for the effect of climate change, Avista could consider acquiring additional expertise regarding temperature impacts over time on Avista’s system, especially considering the company’s hydro-reliance position, as shown in Figure 2. Staff suggests the
company take a closer look at the methods peer utilities are taking. For example, Seattle City
Light included a study on “Climate Change Effects on Supply and Demand,” as an appendix to
its IRP, dedicating resources to assess the IRP climate sensitivity on the utility’s load-resource balance, including reduced snowpack, earlier melt, higher winter inflows, and lower summer inflows. This additional information provided insights into climate change scenarios’ effects to
potentially change the expected base portfolio for supply and demand.18

Figure 2: 2020 Avista Capability and Energy Fuel Mix19

17 Avista Draft 2021 Electric IRP at 7-12.
18 NWPCC presentation on Climate Change and the 2021 Power Plan Workshop; Seattle City Light (May 1, 2019).
Also see Seattle City Light 2016 IRP, Appendix 12.
19 Avista Draft 2021 Electric IRP at 4-1, Figure 4.1.
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Recommendation

For Final IRP:
• Provide discussion regarding the implications of possibly moving from a winter
peaking utility to a dual or summer peaking utility.

For next IRP:
• Incorporate a suite of variables, including snowpack, streamflow, and rainfall
parameters; meteorological trends; and load risks into the analysis. Staff believes
further study is needed.
• Consider additional resources, such as a climatologist or climate change specialist, to analyze climate impacts over time on Avista’s system.

Load Forecasting
In addition to the climate change-related recommendations above, Staff finds that the load forecast section could use some clarification in the Final IRP. Avista conducted base, high-, and
low-load growth forecasts, as did its peer utilities. Comparisons to the other two utilities are
difficult because the Draft IRP narrative lacks sufficient detail, including how Avista derived the
input assumptions for the high- and low-load growth scenarios.
One area where the Avista Draft IRP falls short of its peer utilities is discussing whether and how
the ongoing COVID-19 pandemic has impacted its load forecast. For example, the company does
not specify when its economic inputs into the forecast were finalized, or whether it has made any
adjustments to the forecast to account for observed load impacts from the state’s stay-at-home
orders. The state’s (and the nation’s) economy has been severely impacted since the pandemic’s onset in early 2020. For Staff to appropriately evaluate Avista’s forecast, especially considering
the new 10-year Clean Energy Action Plan requirements which create mid-term requirements
within the company’s 2045 planning horizon, more information is needed.
Recommendation
In the Final IRP:
• Clarify the date in which its economic inputs were finalized.
• Discuss any adjustments to the forecast made in response to the ongoing pandemic.
• Clarify the high and low load growth ranges used on page 3-14. For example, how did
the company settle on the high and low assumptions for annual service area employment
and population growth outlined in table 3.3? Please explain.
• Discuss the assumptions behind the EV and solar PV forecasts that are inputs into the load forecast.
• Clarify which of the two climate change forecasts the IRP uses.
In the next IRP:
• Conduct a back cast of its load forecasting model, using actual values for their
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independent variable inputs to their load forecast to assess whether their models have
systematic bias.
• Include a section in its load forecasting chapter that “assess[es] the effect of distributed energy resources on the utility’s load,” as per WAC 480-100-620(3).

Upstream Emissions & SCGHG
For both the electric and natural gas IRP, Avista includes the social cost of greenhouse gases (SCGHG) as a cost adder in its portfolio optimization of resource options, including upstream
emissions from natural gas. Avista describes the application of the SCGHG in several places in
the IRP. However, Staff finds the Draft IRP lacks a separate detailed methodology as to how the
company applies this cost adder in its electric portfolio optimization and preferred portfolio
selection. Staff expects Avista to provide a narrative illustrating step-by-step how the SCGHG cost adder is applied throughout its modeling logic, including associated cost calculations, with
the Final IRP.20

For upstream methane emissions, Avista uses a global warming potential (GWP) factor that was
calculated based on the International Panel on Climate Change’s Assessment Report 5 (IPCC AR5), which Staff prefers over older analyses. Avista uses the upstream methane leakage factor
of 0.77 percent for Canadian natural gas, and uses 1.0 percent for the U.S. Rockies natural gas
factor. Given that this U.S. Rockies natural gas emissions factor is significantly lower than any
of the factors analyzed by the NWPCC in its analysis of upstream natural gas emissions, Staff
recommends the Final IRP explain why the factor is appropriate.
In the expected case, Avista did not apply the SCGHG for market transactions but did include a scenario to test the effect of applying SCGHG to the annual average emissions rates of net
market purchases. Including this value on market emissions led to additional procurement of
wind and less storage and solar. This is likely due to the assumption that the energy used to
charge storage resources comes from market purchases. Staff recommends additional narrative
describing how Avista selected these assumptions regarding market purchases.
During the advisory group process, the company was responsive to Staff’s request to use the annual incremental emissions rate instead of the annual average emissions rate when assuming a
value for SCGHG reduction for energy efficiency. Avista performed a sensitivity to understand
how this assumption changed the selection of energy efficiency. The company found that using
the average rate savings are 12 percent lower by 2045 (10 aMW less) than when using the
incremental rate.
Due to the uncertainty during rule development, Avista developed and performed three different scenarios to help inform the cost of CETA mandates:
• Baseline 1 incorporates the SCGHG but does not include the clean energy standards,
• Baseline 2 achieves the clean energy standards in CETA without using the SCGHG,
• Baseline 3 excludes both the clean energy standards and the SCGHG.

20 WAC 480-100-620(11).
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By varying the baseline assumptions and modeling the SCGHG in several ways, Avista provided
useful insights into the effect of legislation. However, the Draft IRP provided insufficient narrative describing how the company included SCGHG in the scenarios and the preferred portfolio. Staff recommends a separate narrative that focuses on the different methods Avista
used to model the SCGHG in addition to the individual explanations throughout the document.
Recommendation: In its Final IRP, Avista should:

• Include in the narrative description required by WAC 480-100-620(11) with a clear articulation of how the company calculated the SCGHG.
• Discuss assumptions about the SCGHG in market purchases and charging
storage resources with market purchases.
• Explain why 1.0 percent is an appropriate upstream emissions factor for U.S. Rockies natural gas.

Sub-hourly Modeling Capabilities To fully capture the value of flexible resources such as storage or demand response, IRP models
need to have enough granularity to capture intra-hour variables. Modeling sub-hourly dispatch
can readily integrate resources offering more granular grid services into portfolio development.
For storage resources, it is unclear what is included in the company’s cost assumptions and Staff
expects these details to be included in the Final IRP.
Staff is concerned about Avista’s current ability to optimize all the resources needed for a
reliable one hundred percent clean system. With increasing renewable energy on the grid Avista
will be challenged to match generation and load. The current paradigm of planning to a peak in
winter when the wind isn’t blowing must be realigned to recognize that the utility must also plan to a summer peak with an intra-hour weather anomaly. Staff looks forward to updates from
Avista regarding its sub-hourly modeling functionality in its ADSS software for the next IRP.21

Avista must expand its sub-hourly modeling capability to appropriately evaluate DERs on equal footing with utility-scale renewable and more traditional fossil resource options. Avista could also transition to a LTCE optimization platform that endogenously considers the sub-hourly
benefits of DERs. Alternatively, the company can apply cost credits to better characterize the
sub-hourly grid services DERs provide, which in turn may increase the likelihood Avista’s
preferred resource portfolio solution would include these resource options. As discussed within the Demand-Side Resources and Distributed Energy Assessments section of these Staff comments, Avista should not assume future IRPs that handle distributed generation simply as a
load forecast decrement will be CETA compliant.

21 Avista Draft Electric IRP at 14-6.
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Recommendation
In the Final IRP:
• Clarify storage cost assumptions.
Prior to the next IRP:
• Develop a workplan to expand sub-hourly modeling and discuss with stakeholders.
• Expand sub-hourly modeling capability to appropriately evaluate DERs on equal
footing with utility-scale renewable and other supply-side resource options.
Demand-Side Resources and Distributed Energy Assessments
Energy efficiency, demand response (DR), and other distributed energy resources (DERs) are
essential to a clean energy system that adequately serves and benefits all customers. Avista has
made a reasonable attempt to value acquisition of energy efficiency and demand response in the Draft IRP but has not sufficiently analyzed other DERs. Avista, like PSE and Pacificorp,
performed potential assessments for EE and DR but only used a forecast of EV and PV adoption.

The modeling of DER is a major weakness in the Draft IRP. Electric vehicle charging and net-
metered generation are accounted for in the load forecast, but DERs, except for EE and DR, are not otherwise valued as potential resources. Avista signaled plans to further integrate DERs in
the 2025 IRP.22 This is discussed further in the Distribution Planning and Non-Wires
Alternatives section below.

Energy efficiency CETA has not made any notable changes to the methods used to model energy efficiency (EE).
Avista once again retained AEG to perform the conservation potential assessment (CPA) for
both the electric and gas IRP. The draft IRP and associated data provide sufficient information to
calculate the ten-year, four-year, and two-year cost-effective conservation potential under both
CETA and the EIA. The pro-rata share of the ten-year potential is 101,566 MWh.23 Avista used an iterative process to identify the cost-effective EE to be removed from the load forecast.

Figure 3 below shows the avoided cost of EE for energy and capacity with components broken
out. Over the planning horizon the levelized price of EE is projected to be 3.5 cents per kWh.

22 Avista Draft Electric IRP at 2-11 and 14-8.
23 Id. at 5-8.
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Figure 3: Washington Energy Efficiency Avoided Cost24

Demand response
To identify all cost-effective demand response as required by CETA, Avista hired AEG to perform a demand response potential assessment (DRPA) like the CPA for conservation and
similar to the DRPA performed in the last IRP. 25 The DRPA includes sixteen residential and
commercial programs, and Avista added Large Industrial Curtailment potential outside of the
DRPA.26 The programs include both controllable DR and rate design programs. Where
automated metering infrastructure (AMI) is an enabling technology, Avista assumes AMI deployment will be complete in Washington in 2022 (in Idaho the company assumes full
deployment in 2024).

DR is treated consistently among the Washington IOUs, including peak reduction as the primary
use case of demand response. The amount of reliable capacity contribution from DR should vary by program type, number of events, and by length of event. PSE and Avista each appropriately
evaluated sixteen potential demand response programs, including direct load control and pricing
options. However, the utilities did not vary assumptions around the number and length of events,
potentially underestimating the potential that a different program design might provide a better
fit with the utility system needs. The amount of peak capacity credit given to DR for Avista was 60 percent of a gas-fired combustion turbine.

24 Avista Draft Electric IRP at 5-14, Figure 5.7.
25 WAC 480-100-610(4)(a)
26 Potential assessments assume average market penetration and savings over sizeable populations. Large industrial potentials in Avista’s service territory are more appropriately treated individually than on an average basis.
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In line with the NWPCC methodology for 2021, the utilities assumed that energy efficiency
takes place prior to demand response. In general, Staff agrees with this assumption. However, the
specifics of each company’s approach lacked the nuance needed to appropriately capture the potential for EE and DR programs to enhance or interfere with each other. Staff acknowledges that this is a complicated task but anticipates efforts to model the interaction effects will be
enhanced by utility efforts to integrate EE and DR program efforts during implementation.

In recent years, utility modelling of demand response potential has received negative critiques from stakeholders. With the new mandate to pursue all cost-effective demand response, Staff expected the utilities to refine the modeling of this resource. Unfortunately, this round of IRPs
has not made notable improvements over the last round. While Avista and AEG provided ample
opportunity for public involvement around the achievable potential for DR, costs for DR were
not made available during these meetings, thus not vetted by the advisory group. Staff has significant concerns regarding the treatment of grid enabled water heaters. Washington
has established that electric storage water heaters sold in the state that are manufactured after
January 1, 2021, must include a demand response communications port.27 Turnover of the state’s
electric water heater stock will take some time but will steadily increase the potential of this resource without additional equipment being required at customer premises. This technology allows frequent load curtailment requests by the utility while ensuring a large supply of hot water
remains available to the customer.28 While each utility included this technology in the potential
assessments, no utility provided sufficient discussion of potential program costs and assumptions
with the advisory group. Staff requests Avista give this technology additional consideration. Given the large size of a potential program and the current inexperience of northwest utilities with demand response, it is likely costs are overestimated and reliability is underestimated.

Recommendation In the Final IRP:
• Provide the conservation potential assessment model and underlying data.
• Provide the demand response potential model and underlying data. In the next IRP:
• Treat DERs as generation resource in modeling, not just net from load.
• Optimize DERs with supply-side resources.
• Account for rate increases or pricing signals that can move peak demand and change
DER uptake.
• Consider issuing a RFI for DR without prescriptive screens to better understand
potential.
In the CEIP:

27 RCW 19.260.080
28 See Bonneville Power Administration, CTA-2045 Water Heater Demonstration Report, (Nov. 9, 2018).
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• Take a proactive approach to DR program implementation, accounting for longer lead
time of customer-sited programs.
• Ensure programs are scalable.

Distribution Planning and Non-Wires Alternatives
The IRP rules require the utility to include assessments of a variety of distributed energy
resources and the effect of distributed energy resources on the utility's load and operations.29 Further, the commission strongly encourages utilities to engage in a distributed energy resource
planning process as described in RCW 19.280.100. If the utility elects to use a distributed energy
resource planning process, the IRP should include a summary of these results.
In the Draft IRP, Avista provides a narrative of its distribution planning efforts, explaining how
the company continually evaluates its distribution system for reliability and level of service
requirements, including voltage and power quality, for current and future loads. However, Avista
did not identify any projects meeting the criteria for an economic non-wire alternative in the
Draft IRP. The company contends its near-term distribution projects require capacity increases and duration requirements due to load growth exceeding the distributed energy resources (DERs)
capability.30

Although distribution systems will vary from one utility to another based on the unique
characteristics of each system, Staff points to Puget Sound Energy’s Draft IRP, which illuminates the capacity value of such resource additions and illustrates the nexus between distribution system and integrated resource planning. For example, PSE includes a line item of
distribution system planning incremental nameplate capacity for non-wires alternatives,
beginning in 2022 and growing to 118 MW total in the outer years of the plan.31 Staff supports
Avista’s continued efforts to continue to study new technologies and grow its situational awareness of other utilities’ actions in this space.32

Staff suggests Avista continue to engage Staff and keep stakeholders updated on their
commitment in the Draft IRP to start a public distribution planning process in 2022 to identify
and plan for future distribution needs. This will allow the company to better anticipate future impacts under CETA and:
• analyze interdependencies among customer-sited energy and capacity resources;
• reduce, defer, or eliminate unnecessary and costly transmission and distribution capital
expenditures;
• identify and quantify customer values that are not represented in volumetric electricity
rates and maximize system benefits for all retail electric customers; and

29 WAC 480-100-620(3) Distributed energy resources.
30 Avista Draft Electric IRP at 8-9.
31 Puget Sound Energy Draft 2021 IRP, Docket UE-200304, pp. 1-4, Figure 1-4 (“DSP Non-Wire Alternatives”).
32 Avista describes its distribution system as consisting of approximately 350 feeders covering 30,000 square miles, ranging in length from three to 73 miles.
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• identify opportunities for improving access to transformative technologies for low-
income and other underrepresented customer populations.33 Recommendation

In 2022:
• Start a public distribution planning process.

Nonenergy Impacts
As described in the appendix to this document, CETA has emphasized the consideration of
nonenergy costs and benefits of resources in system planning. In the past, Staff has pushed utilities to account for nonenergy impacts (NEIs) such as the expected emissions of greenhouse
gases and particulate matter with quantified health risks.34 Avista’s treatment of nonenergy costs
and benefits in this IRP has gone further than any past effort, in large part because of the
requirement to include the social cost of carbon.
To address other NEIs connected to public interest objectives such as public health, energy
security, environmental benefits, costs, and risks, all three electric IOUs relied on a proxy
method using data from the Environmental Protection Agency (EPA).35 The EPA data includes
NEI values generally applicable to all energy efficiency and renewable energy in the Pacific
Northwest. Avista analyzed this data to align with its service territory, landing on a benefit value of $8.90 per MWh. The company then applied this benefit uniformly to energy efficiency
measures to approximate unquantified NEIs.

While all utilities started with the EPA data, Avista’s proxy benefit value is approximately one
half what PSE used and one third of what Pacific Power plans to use in the 2021 IRPs.36 Staff acknowledges that none of these proxy values accurately capture the value of NEIs, but we
appreciate each utility acknowledging that the nonenergy benefits of EE are, on the whole,
greater than zero. Prior to the next IRP, Staff expects significant work with utilities and
stakeholders to identify which NEIs should be valued, what values can be adequately quantified,
and when the use of proxy values is most appropriate.
The primary limitation to the approach Avista took to account for NEIs in the IRP is only
applying NEIs (outside of the SCGHG) to energy efficiency. NEIs exist for all resources but
most have traditionally only been included when evaluating demand-side resources, as the
proximity of these resources to customers naturally increases impacts.

33 RCW 19.280.100.
34 Staff Comments on 2018-2019 Biennial Conservation Plans, Dockets UE-171087, UE-171091, and UE-171092, p. 8-9 (Dec. 1, 2017)
35 Environmental Protection Agency, Public Health Benefits per kWh of Energy Efficiency and Renewable Energy in the United States: A Technical Report, (July 2019).
36 PSE used a proxy value of $0.02 per kWh ($20.00 per MWh), Pacific Power used $28.70 per MWh, Avista used $8.90 per MWh.
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Recommendation In the next IRP:
• Identify which nonenergy impacts are required and allowed for resource
selection.
• Include NEIs for all resources, as appropriate.
• Consider how NEIs do and do not overlap with equity requirements.
• Identify where real data collection makes sense and where continued use of
proxy is fine.

Customer Benefit Provisions in CETA
In the Draft IRP, Avista did not perform a maximum customer benefit scenario or sensitivity as
required by the new rule.37 Staff understands that this work dramatically departs from the
traditional planning done in the IRP and including it in the Draft IRP may not have been feasible. Staff encourages Avista to make best efforts to model a scenario that would maximize customer
benefits in the Final IRP. Given that the maximum customer benefit scenario is a new
requirement that will be improved upon and clarified over time, Staff requests the company
develop a narrative describing Avista’s current interpretation of the rule and proposed next steps
regarding intent to model the scenario.
Avista completed commendable work by developing a preliminary methodology for
geographically identifying highly impacted communities and vulnerable populations. Avista
identified two census tracts as qualifying highly impacted communities. To identify vulnerable
populations, the company used the Environmental Health Disparities Map maintained by the Department of Health (DOH) to score areas based on pollution burdens and population
characteristics. The company acknowledges that this is an ongoing process that is currently
missing several important inputs.

For the Draft IRP, no utility was able to incorporate the Cumulative Impact Assessment (CIA) prepared by DOH, which was expected by the end of 2020.38 DOH’s work on this has been
delayed and may not be available for inclusion in the Final IRP. The baseline analysis Avista
performed in this IRP identified where there are significant differences in energy use, energy
cost, reliability, resiliency, and higher densities of power plant emissions. Avista will need to change its methods to incorporate the DOH data into the next IRP, but Staff is satisfied with the
progress to date.

Plans for an equity advisory group (EAG) are well underway at Avista.39 The company is
conducting outreach and carefully considering how to successfully engage marginalized and hard to reach populations. The EAG is separate from the IRP advisory group and will identify

37 WAC 480-100-620(10)(c).
38 RCW 19.405.140.
39 WAC 480-100-655(2).
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vulnerable populations and develop customer benefit indicators that will be incorporated into the
CEIP planning and the next IRP. Staff look forward to Avista growing its current robust low-
income programs to serve other highly impacted communities and vulnerable populations. Recommendation

In the Final IRP:
• Provide a maximum customer benefit scenario and a narrative regarding Avista’s current interpretation of the rule and next steps for improvement.
• If available and time permits, incorporate the DOH data in the CIA.
Before the next IRP:
• Create the Equity Advisory Group by May 1, 2021, to provide useful and timely
input for the planning cycle. Staff understands that Avista has already begun
organizing this group and commends the company approach.
• Incorporate the DOH CIA into the IRP CIA.
• Utilize the customer benefit indicators developed through the equity advisory
group to design and model a maximum customer benefit scenario.

Resource Adequacy Assessment and Uncertainty Analysis As required by CETA, Avista must determine “resource adequacy metrics for the resource plan,”
and identify “an appropriate resource adequacy requirement and measurement metric consistent
with prudent utility practice.”40 The IRP uses Avista’s Reliability Assessment Model (ARAM) to
test the current resource portfolio’s reliability metrics and the contribution of each resource.
Continuing from previous IRPs, Avista retains a 5 percent LOLP metric to ensure future system reliability.

In Table 11.5, Avista also shows resource adequacy analysis related to three other reliability
metrics, including Loss of Load Hours (LOLH), Loss of Load Expectation (LOLE), and
Expected Unserved Energy (EUE). The company currently targets a 16 percent planning margin to meet winter peaks, and 7 percent for summer peaks. This is in addition to meeting operating
reserves and regulation requirements.

Avista begins its resource adequacy analysis narrative with a discussion of regional coordination,
signaling that it is participating in the development of a potential regional resource adequacy program. The company estimates participation in a resource adequacy program will reduce its
needs for new capacity by up to 70 MW in 2031 based on the current draft program design,
where these savings will potentially allow the utility to require lower future resource acquisition
if the program is developed and implemented.
Avista’s draft IRP analysis shows a capacity need of 83 MW of natural gas-fired capacity for
Washington customers by 2026, replacing the Lancaster Power Purchase Agreement (PPA), to
maintain reliability targets for Washington customers during peak load hours. The company

40 RCW 19.280.030(1)(g) and (i).
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assumes 330 MW of market availability for the 2021 IRP, compared to 250 MW in the
2017/2020 IRPs. Avista also indicates that a future RFP may identify a lower cost clean resource
to meet this reliability shortfall, but the current IRP modeling results selected a gas-fired resource in 2026.
The analysis of the contribution to RA by storage, DR, and variable energy resources is of
particular interest to Staff in the first post-CETA IRP review. For the Final IRP, and into next
IRP cycle, Staff suggest Avista include more information about how the company treats, or plans to treat, uncertainty in RA modeling within the IRP, including the following elements of its RA assessment:

Resource ELCC Analysis
For its (effective load carrying capability) ELCC analysis, Avista assigned peak credits to renewable and storage resources depending on resource ability to meet peak loads using its ARAM model. The company’s ELCC calculations should be a measurement of that resource’s
ability to produce energy when the company is most likely to experience electricity shortfall,
showing how that resource uniquely contributes to reliability requirements. Avista appears to translate its “peak savings” for demand response into a peak credit that differs depending on duration. Specifically, Staff requests more description about how Avista derived
the Peak Credit shown in Table 9.12. For energy storage, when an 8-hour resource only gets a 30
percent credit and a 70-hour resource only gets to 90 percent, Staff questions how the utility
uniquely defines peak and peak-related demand terms.41 Staff requests additional narrative related to the company’s methodology related to Peak Credit, including how Avista specifically defines the terms “peak” and “peak-related” in the Final IRP.

Incorporation of uncertainty into RA assessment
Avista indicates “resource analysis identifies a natural gas CT to replace resource deficits if pumped hydro is not a feasible resource to meet the 2026 shortfall. Avista will conduct transmission and air permitting studies to prepare for this contingency. Avista expects this
process to take at least two years.”42 Relatedly, in the Draft IRP narrative for resource adequacy,
risk, and uncertainty analyses, it is not clear how the company accounts for renewable contribution, storage efficiency, or construction.43 For example, construction risks could include delays for new assets, other future considerations for resource maintenance, plant upgrades, or transmission expansion uncertainties. Staff request additional narrative how the company
incorporates uncertainty in the RA assessment in the Draft IRP, or if the company plans to
address these elements in the next IRP cycle.

41 See Natalie Mims Frick et al., Peak Demand Impacts From Electricity Efficiency Programs Report, Energy
Analysis and Environmental Impacts Division, Lawrence Berkeley National Laboratory, Appendix B, Table B-2 (Nov. 2019).
42 Avista Draft Electric IRP at 14-5.
43 See Juan Pablo Carvallo et al., Implications of a regional resource adequacy program on utility integrated
resource planning - Study for the Western United States, Energy Analysis and Environmental Impacts Division, Lawrence Berkeley National Laboratory, p.17, Table 3.5 (Nov. 2020).
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Recommendation

In the Final IRP:
• Clarify the company’s peak credit methodology, including the definition of
“peak” terms.
• Explain how the company incorporates uncertainty in the RA assessment in the
Draft IRP, or if the company plans to address these elements in the next IRP cycle.
In the next IRP:
• Incorporate the results of the regional resource adequacy program, as
appropriate.
• Discuss “peak” definitions within the advisory group.

State Allocation of Resource Need
Historically, Avista’s allocation of planned electric system resources between states has been determined using the Production-Transportation ratio, which is approximately 65 percent
Washington and 35 percent Idaho. As the two states’ policy objectives diverge, capacity and
energy needs result from different drivers. In the Draft IRP, Avista has done an admirable job
attempting to assign resource needs between one hundred percent Washington, one hundred
percent Idaho, and a combined system need. Soon, both state commissions will need to grapple with complicated cost recovery allocation.

Avista faces difficult questions related to future rate recovery resulting from long-term resource
planning in two states for one utility system: Idaho customers will not want to pay increased
rates that may result from CETA and Washington customers will not want to pay for potentially stranded assets from new gas resources. Staff encourages the company to bring stakeholders
together for an in-depth discussion and analysis prior to any formal filing. Ultimately interstate
cost allocation must be adjudicated, but Staff believes a collaborative process is worth pursuing.
Recommendation
Before the next IRP:
• Facilitate a discussion between Washington and Idaho stakeholders concerning
state allocation of resources.

Electrification Scenarios
In the electric IRP Avista performed three separate scenarios considering the effects that
electrification of space and water heat in Washington could have on the portfolio. Avista states that the IRP is not the best vehicle to conduct these studies and recommends a separate regional
study. While Staff does not disagree about the usefulness of a regional or statewide study, the
company should continue to consider local policy trends towards electrification in both the
electric and natural gas IRPs.

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Recommendation

In future IRPs:
• Consider effects of policy trends towards electrification on both the electric and
natural gas systems.

Public Participation Avista demonstrated a robust public participation process during this IRP. They began by
seeking input on a draft work plan and once filed, stayed true to the plan. Avista originally
scheduled five technical advisory group meetings. When the scheduled meetings could not cover
all the material with the depth the company and advisory group members wanted, Avista added additional webinars and a workshop. Avista provided Staff and the advisory group meaningful opportunities to discuss complex resource planning processes, data assumptions, and other
interest topics throughout the IRP planning process. Avista’s IRP advisory group is open to all
members of the public who wish to participate.
Avista’s IRP Team is exceptionally responsive to members of the advisory group, taking input under consideration and taking time to explain complex issues to ensure members were
comfortable with their understanding. Deadlines on comments and requests were clear but not
rigid. Further, the company provided draft presentations before meetings and followed-up with a
final version that contained any last-minute changes or corrections. Staff recommends more time to review presentations before IRP advisory group meetings, which
is crucial for utilities to receive meaningful feedback during the meetings, especially considering
Avista’s IRP meetings now cover both gas and electric IRP topics. The company should provide
advisory group members meeting minutes and follow-up documentation promptly, allowing members an opportunity to suggest revisions or clarifications as necessary. In the future, the company may need to expand its core IRP team to include additional administrative support,
especially considering the new customer benefit provisions.

The company filed its Draft IRP on January 4, 2021, mostly complete, except for appendices. Staff notes the lack of appendices is mostly balanced by the excellent data access and availability of Avista staff to stakeholders. Staff also highlights the company’s outstanding approach to
transparent data access in the Data Disclosure section of this document.

In 2020, Avista put out a request for proposals (RFP) for renewable resources. The RFP process is in its final stages, and there is a possibility that the company will finalize the acquisition of a resource before filing the Final IRP. To the degree possible, Avista should update the
Final IRP with any known resource. If an acquisition occurs soon after the Final IRP is filed,
Staff recommends the company file, at minimum, an update to the preferred resource strategy
and clean energy action plan so it can develop its CEIP based on the best available information. Overall, Avista’s public participation process is comprehensive and facilitates trust and
transparency in the IRP development process. Staff provides recommendations to improve its
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public participation process for the next IRP cycle, particularly related to the new documentation
and administrative requirements outlined in the rule.44
Recommendation
In the Final IRP:
• Provide an update based on any recently completed resource acquisition. In the next IRP:
• Provide additional time to review presentations prior to meetings.
• Post meeting minutes in a timely manner and allow opportunity for revision.
• Consider if additional staffing is required to adequately meet new IRP requirements.

Data Disclosure
Avista appears to have best satisfied the data disclosure objectives Staff have highlighted for this
first CETA-compliant 2021 IRP cycle of the three Washington electric investor-owned utilities. Overall, the company seems to have provided the data stakeholders requested during the 2021
planning process on time.

Staff notes the record of stakeholder comments and company responses is one of the appendices
not included in the draft.45 Unlike peer utilities, Avista’s IRP website does not contain an ongoing record of stakeholder comments, data requests, and questions received and addressed by
the company.46 Staff understands that Avista plans to provide this information in the Final IRP
but suggests a contemporaneous documentation strategy.47

Avista made many data input files available in native format to facilitate stakeholder review of data underlying the company’s planning decisions. Staff applauds Avista’s commitment to make
data and models accessible to stakeholders by posting them to the company’s website and
providing a webinar dedicated to understanding the PRiSM long-term capacity expansion model.

To further increase accessibility and transparency, the company should provide contextual aids and organize its Final IRP deliverable by including a master table of contents, readme files, and
categorically grouping related data.
Recommendation In the Final IRP:
• Ensure appendices include a record of stakeholder feedback and the company’s

44 WAC 480-100-620, -625, and -630.
45 Appendix C of Avista’s Draft Electric IRP serves as the placeholder for public participation comments. However,
the company has not filed any appendices with its draft deliverable.
46 PacifiCorp’s 2021 IRP stakeholder feedback website posts stakeholder feedback forms and company responses to
said forms, when available. Avista’s IRP website does not appear to include similar postings.
47 WAC 480-100-620(17).
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response.
• Provide context for the data files provided on the company’s website and submit data files in the docket. In the next IRP:
• Provide contextual aids alongside data input files.

Natural Gas Design Day (Planning Standard)
Avista’s peak day planning standard for natural gas is new to this IRP. In previous plans, the
company had used a coldest-on-record standard and has changed to a 99 percent probability of
experiencing an extremely cold temperature in each of its service areas. The data underlying
Avista’s new design day calculation indicates a warming trend in parts of its service territory, but it is still based on historic data, not projections of future temperatures.

Staff requests Avista include a future climate change sensitivity similar to that provided by PSE
in its next natural gas IRP and provide more explanation around the new design day
methodology, including why this new standard is the appropriate choice. Staff believes a few extra sentences explaining how it combines temperatures “with a 99% probability of a weather
occurrence” would make the methodology clearer. In its explanation, Avista should provide
additional narrative around Table 2.4 and Figures 2.4 through 2.8 to further describe the trends
they depict. On the surface, it seems counterintuitive, for instance, that the new design day
methodology has Medford’s planning standard significantly warmer than the previous methodology did, while Klamath Falls’ peak day has gotten slightly colder, even though the two
cities are not that far apart.

Recommendation In the Final IRP:
• Explain the new design day methodology, providing a more detailed narrative.
• Further explain why the new design day standard is now the most appropriate one.
In future IRPs:
• Explore the feasibility of using projected future weather conditions in its design day
methodology, rather than relying exclusively on historic data. The company is
conducting a similar analysis for a climate change scenario in its electric IRP.

Natural Gas CPA and Conservation Targets
Avista once again retained AEG to perform the potential assessment for both the electric and gas
IRP in Washington and Idaho. (Avista uses the Energy Trust of Oregon to conduct its Oregon
CPA.) The continuity in CPA contractors allowed Avista to make very few minor changes to the CPA methodology. AEG estimated that Avista’s achievable economic conservation potential for
its Washington territory is 3.6 million dekatherms by 2040.

Staff has no suggested changes concerning natural gas CPA and conservation targets at this time.
It is important to note that Staff will be further analyzing the details of the CPA, including
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avoided costs, as part of the CPA approval process described in Appendix 1 to these comments.
Renewable Natural Gas (RNG) The Draft IRP discusses RNG at length, including state and regional policy considerations, internal steps the company has been taking to prepare for an RNG program, gas quality
specifications, and options to build or buy projects. Avista acknowledges that its cost-
effectiveness evaluation methodology for RNG is a work in progress. A voluntary RNG program
is currently in development. Staff look forward to reviewing detailed assumptions of RNG in the Final IRP.
Recommendation:

In the Final IRP:
• Include details of RNG cost assumptions in the appendices.
In future IRPs:
• Use any up-to-date cost data that is available to model potential RNG resources.

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Appendix 1

Introduction
The passage of the Clean Energy Transformation Act (CETA, E2SSB 5116) in 2019 introduced many critical changes to the ways in which electric utilities conduct their integrated resource
planning (IRP) processes. CETA also created a separate, new planning requirement called the
clean energy implementation plan (CEIP). The new legislation directed the Commission to issue
rules related to IRPs, which occurred midway through the previous IRP 2019 planning cycle. Faced with the likelihood the 2019 IRPs may not be fully CETA-compliant, Staff petitioned, and the Commission ordered, the 2019 IRPs be considered IRP progress reports.1 The Utilities and
Transportation Commission (Commission) initiated rulemakings2 in January 2020 to develop
rules that would implement the new law. The IRP and CEIP rules were finalized on December
28, 2020.3 The new rules require IRPs to be submitted on January 1, 2021, and on January 1 every four
years thereafter.4 However, given the changes to the IRP process required by CETA, the
Commission ordered each electric utility (Puget Sound Energy [PSE], Avista Corporation
[Avista], and PacifiCorp) to submit draft 2021 IRPs by January 4, 2021, with the final versions
by April 1, 2021.5

All three utilities filed their draft IRPs on January 4, 2021. Both Avista and PSE filed joint electric and gas IRPs. On January 5, 2021, the Commission issued a notice of opportunity for
comment from interested parties in the IRP dockets for these three companies by February 5,
2021.6 The notices also announced recessed open meeting dates and times where the companies
will present their draft plans and respond to questions from the Commission and interested
stakeholders. The recessed open meeting dates are:
• PacifiCorp: Monday, February 22, 9:30 a.m.
• Avista: Tuesday, February 23, 9:30 a.m.
• PSE: Friday, February 26, 10:30 a.m.

1 PacifiCorp, Docket UE-180259, Order 03, ¶¶ 24-25; Puget Sound Energy, Dockets UE-180607 & UG-180608,
Order 02, ¶ 15 (Puget Sound Energy); Avista, Docket UE-180738, Order 02, ¶ 15.
2 Dockets UE-191023 & UE-190698 (Consolidated), implementing the Clean Energy Transformation Act codified as RCW 19.405 and changes to RCW 19.280 - Electric Utility Resource Plans.
3 In re Adopting Rules Relating to Clean Energy Implementation Plans and Compliance with the Clean Energy Transformation Act and Amending or Adopting rules relating to WAC 480-100-238, Relating to Integrated Resource
Planning, Dockets UE-191023 & UE-109698 (Consolidated), General Order 601, pp. 58-59, ¶ 168 (CETA Rulemaking Order) (Dec. 28, 2020).
4 WAC 480-100-625(1). 5 See supra n.1.
6 Notice of Opportunity to File Written Comments, Avista, Dockets UE-200301 and UG-190724, and UE-200420; Puget Sound Energy, UE-200304 and UG-200305; and PacifiCorp, Docket UE-200420 (Jan. 5, 2021).
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This appendix is organized by subject area as they appear in the Commission’s rules and describes the statute and rule requirements that govern the IRP process for both electric and
natural gas IRPs. The main body of Staff’s comments (to which the current document serves as
an appendix) is also organized by subject area, and discusses three things:

• How each IRP meets (or does not meet) the requirements laid out in this appendix;
• Whether each utility’s IRP modeling is consistent with its peers; and
• What changes Staff recommends to enable acknowledgment of the 2021 final IRP and
Clean Energy Action Plan (CEAP), support the development of the Clean Energy Implementation Plan (CEIP), or in each company’s next IRP.

Overview of Electric IRP Statute and Rule Requirements by Topic
Public Participation

The Commission’s new rules facilitate more opportunities for deeper, cross-topical conversations
between interested persons and utilities on a variety of IRP issues, such as equity, to implement
CETA directives.7 Staff highlights two of these public engagement components: participation and involvement of the IRP advisory group, and the two-step draft IRP and final IRP submittal,
which will eventually help inform the shape and style of a CEIP. 8

First, to develop an effective IRP, CEAP, two-year progress report, and CEIP, the utility must
demonstrate and document how it considered input from its advisory group, including scenarios and sensitivities the utility used.9 Throughout the IRP planning processes, it is incumbent upon
each utility to provide staff, the advisory group, and the public meaningful opportunities to
engage and discuss complex resource planning processes, data assumptions, and other topics
such as upstream emissions and the SCGHG emissions used in IRP modeling analyses.
Second, utilities are now required to submit a draft IRP, which provides stakeholders, the media,
and the public a meaningful first glimpse into the utility’s thinking around energy and capacity
resource planning in the post Clean Energy Transformation Act world, before the utility files its
final IRP four months later.10 Presenting a draft plan for complex energy and capacity planning
is not new. In fact, requiring a mostly complete draft to be filed prior to the issuance of a final document is common practice. For example, the Northwest Power and Conservation Council’s
(NWPCC or Council) power plan development process includes a two-stage process of issuing a
draft plan, taking public comment, conducting the appropriate analysis to respond to public
comment, and issuing a final plan.11
Due to the ongoing COVID-19 public health crisis, the 2021 IRP public participation process

7 WAC 480-100-620; -625; and -630.
8 WAC 480-100-625; WAC 480-100-630; CETA Rulemaking Order at ¶ 137. 9 WAC 480-100-625; -630; and -655.
10 WAC 480-100-625(3). 11 CETA Rulemaking Order at ¶ 166.
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cycle looked very different as compared with previous IRP cycles. Staff is acutely aware the first post-CETA IRP cycle was decidedly more difficult for all involved, with most advisory group
meetings held virtually via webinar. Plus, the utility faced unprecedented CETA modeling and
timing challenges. Staff comments highlight specific areas of success in the public engagement
arena and potential areas of improvement for future IRP cycles.
Data Disclosure

To comply with CETA, electric utilities should address three primary data disclosure themes
during the 2021 IRP cycle. First, companies should provide the information that stakeholders
request during the planning process in a timely manner or provide clear justification why the request cannot be met.12 This circulation of information in the development and reporting of
IRPs should primarily occur during the advisory group process.13 Adherence to this principle is
important as it will align utility planning with the overarching ethos of CETA – one of
accessibility, transparency, responsiveness, and clarity.
Second, to maximize transparency, the electric utilities must file with the Commission all data
input files in native format as appendices to the draft IRPs.14 The Commission, Commission
Staff, Public Counsel, and other parties with a substantial interest in a company’s plan must be
able to understand a utility’s decisions. Companies disclosing such data in native format
facilitates parties independently determining if those actions were in the public interest and represent the lowest reasonable cost option.15

Finally, the data a utility provides during the IRP planning process should be easily accessible.16
Release of such information should be more than large data dumps, whose sheer size can
overwhelm the recipients thus reducing the likelihood questions get answered. Instead, companies should tailor the data provided to the requestor’s specific query.17 While utilities can
still designate relevant data confidential in keeping with the Commission’s rules,18 Staff’s
expectation that accessible information is readily shared amongst stakeholders fosters
meaningful and inclusive public engagement throughout the IRP advisory group process.
Load Forecasting and Climate Change Impacts

One of the most critical steps in the IRP analyses involves the assessment of how much total
energy the utility’s customers are expected to consume over a 20-year period (load), including
the maximum amount expected to be consumed instantaneously (peak demand). In the IRP, the utility must assess projected economic and population growth for the region. Further, recently
updated IRP rules set forth additional requirements in the load forecasting step of the IRP

12 Id., at ¶ 178. 13 WAC 480-100-630(3).
14 WAC 480-100-620(14) requires utilities undertake IRP data disclosure actions suggested in RCW 19.280.030(10)(a).
15 CETA Rulemaking Order at ¶ 173. 16 WAC 480-100-620(14).
17 CETA Rulemaking Order at ¶ 178. 18 WAC 480-07-160.
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development process. These include requiring the utility to conduct a new assessment of Distributed Energy Resources or DERs, develop climate change scenarios, and other relevant
load assessments.19

In addition to their existing requirement to pursue all cost-effective, reliable, and feasible energy
efficiency, CETA now requires utilities to pursue all “cost-effective, reliable, and feasible” demand response (DR).20 Thus, utilities must perform forecasts of cost-effective potential of
both resources, where these forecasts must in turn inform the load forecast. Second, CETA
requires utilities to conduct an overarching DER forecast, “and an assessment of their effect on
the utility’s load.” The Commission’s rules adopted to implement CETA require such forecasts
to include energy efficiency, DR, and energy assistance, as well as other DERs like energy storage, electric vehicles (EVs), and solar photovoltaics (PV).21

Finally, risks are changing because of climate change. The recently revised IRP rules require
utilities to include at least one future climate change scenario, incorporating “load changes
resulting from climate change.”22 As compared to the expected ‘base case’ or ‘do nothing’ portfolio, the utility should also consider load impacts, higher risks of changing river flows,
disaster frequency, and temperature effects over time on the utility’s load-resource balance.

IRP Modeling
Modeling is central to a utility’s resource planning because the IRP is essentially a numerical
solution for how the company will keep the lights on in the short- and long-term, addressing
resource need and balancing supply and demand, given a host of constraints.23 In determining
this IRP solution, the company and stakeholders must examine a range of forecasts and analyses
when identifying options for how to meet customer demand, compare these options, and ultimately decide what resources to build or acquire.24 The 2021 IRPs are the utilities’ first
roadmaps for realizing the transformative change required by CETA as these plans couple
modeling with the supporting narrative required to explain companies’ decisions to a wide
stakeholder audience.
Utilities must develop and validate their planning models with additional rigor since electric
IOUs’ 2021 preferred portfolios will establish the baseline for achieving CETA’s coal
elimination, GHG neutral, and clean electricity targets over the next 25 years.25 To comply with
CETA directives and adaptively manage modeling methodologies, utilities must determine how
best to incorporate the social cost of greenhouse gases (SCGHG) into their analytics, properly integrate distributed energy resource (DER) assessments into resource planning, and undertake
more sophisticated scenario and sensitivity modeling as compared with previous IRP cycles.
These three modeling topics constitute focal points of the 2021 draft IRP staff review.

19 WAC 480-100-620(3) and (10).
20 RCW 19.405.040(6)(a); -.050(3). 21 WAC 480-100-620(3).
22 WAC 480-100-620(10)(b). 23 RCW 19.280.030(1).
24 WAC 480-100-620(11). 25 RCW 19.405.030(1); -.040(1); -.050(1).
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As required by statute and rule, utilities must incorporate SCGHG as a cost adder when
evaluating and selecting conservation and resource options. Within their IRP narrative
companies should evaluate the robustness of their analytical approaches and describe how the
IRP solution incorporates the SCGHG cost adder throughout the modeling stages. Appropriately
handling SCGHG within IRP analyses is likely the most important modeling consideration for utilities during the 2021 cycle as this adder applies across the range of resource strategies
considered.26 Modeling SCGHG also serves as an insightful linkage for comparing how
Washington’s three IOUs are pricing new CETA requirements into resource selection.

Reflective of CETA, both statute and accompanying rule continue to require the lowest reasonable cost (LRC) solution,27 but are now more prescriptive when it comes to the types of
resources, especially clean alternatives, and analyses that must be considered when planning for
future targets. Utilities must now consider a wide range of DER options and undertake
quantitative methods (e.g., forecasts of demand response and other demand side management) to
determine the impact such efforts will have on utility planning.28 Utilities should appropriately incorporate DER potential into portfolio development. Staff’s goal is to ensure appropriate utility
valuation of resources like demand response (DR) and energy efficiency (EE), which is crucial to
meet CETA standards and implement specific targets identified in the CEIP.

Additionally, utilities’ portfolio development must quantify the impact and risk associated with crosscutting concerns like ensuring resource adequacy and equitably distributing customer
benefits and costs.29 Companies need to develop a CETA “counter factual” scenario that
identifies the alternative LRC portfolio the companies would have implemented if the CETA
requirements around greenhouse gas neutrality by 2030 and clean electricity by 2045 were not in
effect. Second, companies need to run a climate change scenario that incorporates the best science available to assess climate change impacts, including hydrological conditions,
temperature, and load changes.

Finally, utilities are required to run a sensitivity that examines how their 2021 preferred portfolio
performs when benefits for all customers are maximized, before balancing other objectives.30 This analysis seeks to quantify how all customers, including vulnerable populations or highly
impacted communities, are benefiting from the transition to clean energy.31 The analysis should
only adjust variables specific to an IOU’s Washington service territory. The intent of this
modeling exercise is to maximize the hypothetical benefit utilities’ Washington customers could
realize. There is no “right answer” for how to optimize this benefit so utilities should brainstorm what activities or actions are most efficacious. Once determined, companies could “hardcode”
given levels of these benefits and subsequently co-optimize other modeling variables. Staff
recognize competing constraints may prevent a company’s 2021 IRP from ultimately reflecting
these sensitivity attributes. For the 2021 IRP, the primary result of this sensitivity is additional

26 RCW 19.280.030(3)(a); WAC 480-100-620(11)(j). 27 RCW 19.280.030(1)(d); WAC 480-100-620(7) and (11)(a).
28 RCW 19.280.030(1)(h) and (j); WAC 480-100-620(3) and (11)(c). 29 RCW 19.280.030(1)(g), (i), and (k); WAC 480-100-620(8), (11)(f) and (g).
30 WAC 480-100-620(10)(a) – (c). 31 RCW 19.405.040(8).
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data and analyses utilities can further refine for their 2022 CEIP and subsequent planning cycles.32

Nonenergy Impacts

The IRP statute changes in CETA require the IRP to address the clean energy transformation standards.33 This results in the need for nonenergy impacts (NEIs) of the utility’s energy system
and programs to be included in the 2021 IRP more prominently as compared with previous IRP
cycles. Historically, NEIs were nearly all associated with energy efficiency programs and
measures. Under CETA, NEIs should be included with all resources when applicable.
Utilities are required to account for nonenergy costs and benefits not fully valued elsewhere in an
IRP model within distributed energy resource assessments.34 For example, a CPA should not
include a separate value for the SCGHG if that value is appropriately accounted for elsewhere in
the selection of energy efficiency. A nonenergy benefit that occurs exclusively or primarily on
the demand-side should be included within the CPA (or other DER assessment). Some values of
nonenergy impacts are well documented in the region, particularly those vetted by the Regional
Technical Forum. However, there are many impacts for which data is currently unavailable, not
monetized, attributable to a program instead of a measure, out-of-date, or not applicable to a
particular utility service territory. In these instances, Staff finds it appropriate to use proxy data
to identify nonenergy costs and benefits.

Finally, nonenergy costs and benefits are required by the new rules to be listed in the avoided
costs section of the IRP and identify if they accrue to utility, customers, participants, vulnerable
populations, highly impacted communities, or the public.35
New Customer Benefit Provisions of CETA
The clean energy transformation standards described in rule address the affirmative mandate to
ensure all customers are benefiting from the transition to clean energy, identifying three separate
components of the customer benefit requirement.36 Each component should be addressed in the
IRP in multiple ways.
Specifically, the rule requires each utility to include an assessment of economic, health, and
environmental burdens and benefits in the IRPs.37 While the cumulative impact analysis (CIA)
conducted by the department of health that should inform the assessment was not available in

32 Conservation Energy Planning and Energy Policy staff customer benefit discussion, January 20, 2021.
33 RCW 19.280.030(1) requires an IRP to address the “. . . implementing [of] RCW 19.405.030 through 19.405.050, at the lowest reasonable cost and risk to the utility and its customers, . . .” including an assessment of “Energy and
nonenergy benefits and reductions of burdens to vulnerable populations and highly impacted communities; long-term and short-term public health and environmental benefits, costs, and risks; and energy security and risk;”
34 WAC 480-100-620(3). 35 WAC 480-100-620(13).
36 WAC 480-100-610(4)(c)(i)-(iii). 37 WAC 480-100-620(9).
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time for the 2021 IRP, the requirement that the assessment be informed by the CIA does not waive the requirement for an assessment if the CIA is unavailable.38 Each utility IRP must
include an assessment of energy and nonenergy benefits and reductions of burdens to vulnerable
populations and highly impacted communities; long-term and short-term public health and
environmental benefits, costs, and risks; and energy security and risk using other sources of
information relevant to the assessment. One use of this assessment is to inform the current distribution of benefits and burdens within a utility’s service territory.

While it is hard to overstate the impact of CETA’s clean energy mandates, the statute’s customer
benefit provisions are perhaps even more of a divergence from the utilities’ (and the
Commission’s) traditional approaches to system planning and operations. For decades, utilities
have been tasked with building a plan that can meet anticipated system needs at lowest
reasonable cost, considering risk. CETA has added another priority that the utilities must
achieve: ensuring all customers are benefiting from the transition to clean energy.

In future IRPs, this customer benefit mandate will largely focus on customer benefit indicators
(CBIs). However, the utilities’ inaugural CEIPs will emphasize CBI determination and details.39
Instead, the CETA statutory and rule applicable to the 2021 planning cycle covers three topical
areas: current-state assessment of economic, health, and environmental burdens and benefits;40
maximum customer benefit modeling sensitivity discussed above;41 and each utility’s formation
of an equity advisory group.42

The new economic, health, and environmental burdens and benefits assessment includes
developing a current-state “snapshot” of the energy impacts and NEIs vulnerable populations and
highly impacted communities experience within the electric IOUs’ Washington service
territories. Similarly, the IRP also needs to consider risks associated with long-term and short-
term public health and environmental impacts as well as energy security.43 These current
conditions are the basis for determining whether the allocation of benefits and burdens from the
utility’s transition to clean energy results in equitable distribution.44 This current-state
assessment is critical for establishing baseline geographic and demographic datapoints, including
identifying the vulnerable populations and highly impacted communities a given utility serves.45
While the original intent was for electric IOUs to consider the Washington Department of
Health’s cumulative impact analysis (CIA) in developing their assessments,46 the CIA’s delay
past December 31, 2020, does not waive the assessment requirement. Utilities should consider

38 CETA Rulemaking Order at ¶ 54.
39 WAC 480-100-640(4). 40 WAC 480-100-620(9).
41 WAC 480-100-620(10)(c). 42 WAC 480-100-625(2)(b), WAC 480-100-655(1)(b).
43 WAC 480-100-620(9). 44 CETA Rulemaking Order at ¶ 53.
45 See WAC 480-100-605 for definitions of “highly impacted community” and “vulnerable populations.” 46 RCW 19.280.030(1)(k).
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alternative references (e.g., U.S. Census data) relevant to the assessment.47 Each electric utility
must provide this assessment as part of its 2021 IRP to comply with CETA.48

Lastly, the equity advisory group required for utilities’ forthcoming CEIPs should also inform
IRP planning.49 In this fashion, an IOU’s comprehensive attention to vulnerable populations and
highly impacted communities serve as a common thread linking successive CETA deliverables
(i.e., IRPs, CEAPs, CEIPs).50 Hence, each company should create an equity advisory group by
May 1, 2021, to provide useful and timely input for the planning cycle. Further, this advisory
group must be Washington-focused, comprised of Washington stakeholders, and include
representatives from highly impacted communities and vulnerable populations. A multi-state
utility cannot simply apply a systemwide advisory group to also serve as the company’s equity
advisory group to comply with CETA.

Conservation and CPA

The Energy Independence Act (EIA) (RCW 19.285) was not replaced or modified by the passage of CETA. When the activities undertaken to comply with the EIA meet the requirements of
CETA, they qualify for compliance with both statutes. Staff expects that the customer benefit
mandate, with its provisions to account for additional nonenergy impacts such as public health
benefits, and requirement to reduce of burdens to vulnerable populations and highly impacted
communities, will make additional energy efficiency a cost-effective resource choice. The new IRP rule requires an energy efficiency and conservation potential assessment of current
and potential policies and programs needed to obtain all cost-effective conservation, efficiency,
and load management improvements; including the ten-year conservation potential used in
calculating a biennial conservation target under WAC 480-109.51 This requirement should not change utility standard practice to any real degree. Staff expects that incremental improvements
to the potential assessment are ongoing.

Each IRP should, at minimum, provide sufficient data points to calculate the ten-year, four-year,
and two-year cost-effective conservation potential under both CETA and the EIA.
Demand Response

The IRP must contain a demand response potential assessment of current and potential policies
and programs needed to obtain all cost-effective demand response.52 The statutory definition of demand response is broad and includes pricing structures (such as time of use or critical peak
pricing), measure-based programs controlled by the utility, and behavioral programs that include

47 CETA Rulemaking Order at ¶ 54. 48 Conservation Energy Planning and Energy Policy staff customer benefit discussion, January 20, 2021.
49 WAC 480-100-625(2)(b), WAC 480-100-655(1)(b). 50 CETA Rulemaking Order at ¶ 162.
51 WAC 480-100-620(3)(b)(i). 52 WAC 480-100-620(3)(b)(ii).
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an incentive payment.53 In order to determine all cost-effective demand response as required by CETA, a potential assessment must include a broad range of options that include each of these
types of demand response.54

Energy Storage
Energy storage is identified in CETA and in the recently adopted WAC rules implementing
CETA as a key component of the transition to clean energy.55 Energy storage can address many
types of system needs: energy, capacity, ancillary services, integration of renewable resources,
balancing, spinning and non-spinning reserves, and emergency power. Energy storage can also
play a role in deferring or preventing some transmission and distribution projects. The newly
adopted WAC includes the following requirements related to energy storage:

• WAC 480-100-605 – energy storage included in definition of a DER.
• WAC 480-100-620(3)(a) – DER assessments in a utility’s IRP “must incorporate
nonenergy costs and benefits not fully valued elsewhere within any integrated resource
plan model.”
• WAC 480-100-620(3)(b)(iv) – storage identified as a DER “that may be installed by the
utility or the utility’s customers,” and which the “IRP must assess[.]”
• WAC 480-100-620(5) – battery and pump storage identified as potential way to
integrate renewable resources and address overgeneration events.
• WAC 480-100-620(11)(e) – acquisitions made after CETA’s passage must “rely on
renewable resources and energy storage, insofar as doing so is at the lowest reasonable
cost.”

While CETA has changed the regulatory landscape in Washington, energy storage is not new to the Commission.56 Accurate modeling and optimal use of energy storage within a utility’s
system planning tools was identified as the main limitation to full consideration of energy
storage as a resource in the Commission’s policy statement. The value of energy storage is more
apparent when a system planning model uses a granular timescale – the more granular the
modeling timescale, such as an hourly or sub-hourly dispatch simulation, the more value of energy storage can be identified. Many IRP modeling tools’ optimizations are not typically
performed on an hourly or sub-hourly basis.

In the policy statement, the Commission also discussed policy principles related to energy

53 "Demand response" means changes in electric usage by demand-side resources from their normal consumption
patterns in response to changes in the price of electricity, or to incentive payments designed to induce lower electricity use, at times of high wholesale market prices or when system reliability is jeopardized. "Demand
response" may include measures to increase or decrease electricity production on the customer's side of the meter in response to incentive payments.
54 WAC 480-100-610(4)(a). 55 RCW 19.405.040(6)(a)(iii); RCW 19.405.050(3)(c); WAC 480-100-620(11)(e).
56 Report and Policy Statement on Treatment of Energy Storage Technologies in Integrated Resource Planning and Resource Acquisition, Dockets UE-151069 and U-161024, ¶ 15 (Oct. 11, 2017) (Policy statement identified
”barriers that prevent energy storage from being fairly considered in resource planning and develop[ed] policies to overcome them”).
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storage, many of which are also reflected in the newly adopted Part VIII of Chapter 480-100 WAC. We briefly summarize some components of the policy statement that continue to be
relevant in the context of CETA and the revised WAC:

• Utilities should move toward a “new planning framework that more cohesively considers the relationship between generation, transmission, and distribution, allowing
for a fair evaluation of hybrid resources such as energy storage.”57
• Utilities should adopt modeling platforms capable of sub-hourly modeling, and in the
interim should use an external model capable of modeling the sub-hourly benefits of
storage over the resource’s useful life, including transmission and distribution benefits, then calculate the net present value of those benefits and deduct that value from the
resource’s modeled capital cost in the IRP.”58
• Utilities should consider at least “a reasonable, representative range of storage
technologies and chemistries,” working with their advisory groups to identify these resources, 59
• Utilities should vet storage cost assumptions by reviewing third-party data and applying
“a reasonable learning curve to storage costs to account for forecasted declines.”60
• Finally, utilities should ensure that storage is considered in evaluating distribution system projects, including all locational benefits.61

As utilities use resource modeling software that is more sophisticated as compared with previous
IRP cycles, and as CETA’s equity components are better understood, Staff expects that the importance of energy storage as a resource that can address multiple system needs and inequities will only grow, as will Staff’s focus on its accurate modeling and full consideration in each
utility’s IRP.
Qualifying Facilities – Avoided Cost Methodology The Public Utilities Regulatory Policies Act, or PURPA, requires utilities to purchase energy and
capacity made available to them by qualified facilities (QFs) at a price based on the utility’s
avoided costs.62 The IRP estimates what the utility’s system needs, and at what cost. The goals
of making avoided costs understandable for all stakeholders and of strengthening the connection between the IRP analysis and PURPA rates were both key factors driving the adoption of the new WAC 480-100-620(13) and (15).

57 Id. at ¶ 36.
58 Id. at ¶ 43. 59 Id. at ¶ 46.
60 Id. at ¶ 47 61 Id. at ¶ 48.
62 The Commission revised its implementation of PURPA recently through a rulemaking that culminated in Chapter 480-106 WAC, which prescribes a methodology for setting PURPA rates for QFs with a nameplate capacity of 5
MW or less, and which requires that utilities file for the Commission‘s consideration and approval a methodology to calculate avoided cost rates QFs larger than 5 MW. These methodologies were submitted by all three utilities and
approved by the Commission in the following dockets: UE-191062 for PSE, UE-200455 for Avista, and UE-200573 for PacifiCorp.
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• WAC 480-100-620(13): “Avoided cost and nonenergy impacts. The IRP must include
an analysis and summary of the avoided cost estimate for energy, capacity, transmission,
distribution, and greenhouse gas emissions costs. The utility must list nonenergy costs
and benefits addressed in the IRP and should specify if they accrue to the utility,
customers, participants, vulnerable populations, highly impacted communities, or the general public. The utility may provide this content as an appendix.”

• WAC 480-100-620(15): “Information relating to purchases of electricity from
qualifying facilities. Each utility must provide information and analysis that it will use
to inform its annual filings required under chapter 480-106 WAC. The detailed analysis must include, but is not limited to, the following components:

(a) A description of the methodology used to calculate estimates of the avoided
cost of energy, capacity, transmission, distribution and emissions averaged
across the utility; and (b) Resource assumptions and market forecasts used in the utility's schedule of
estimated avoided cost required in WAC 480-106-040 including, but not limited
to, cost assumptions, production estimates, peak capacity contribution estimates
and annual capacity factor estimates.”
Resource Adequacy and Uncertainty Analysis

Resource adequacy (RA) studies in the IRP, including RA metrics and methodologies, are
extremely important to ensure the lights stay on. Specifically, CETA requires an electric utility’s IRP to determine “resource adequacy metrics for the resource plan” and to identify “an
appropriate resource adequacy requirement and measurement metric consistent with prudent
utility practice.”63 Staff’s review of resource adequacy in the IRP is broad in scope and involves
all aspects of load service and modeling, including: energy, capacity, flexibility, availability, and
performance characteristics of specific resources, such as demand-side, storage, wind resources, and batteries.64 The analysis of the contribution to RA by storage and variable energy resources
is of particular interest to Staff in the first post-CETA IRP review. Staff comments also address
the incorporation of uncertainty into the RA assessment, often in the form of sensitivity analysis.
Distribution Planning Process
The IRP rules require that the utility must include assessments of a variety of distributed energy
resources and the effect of distributed energy resources on the utility's load and operations.65
Further, the commission strongly encourages utilities to engage in a distributed energy resource
planning process as described in RCW 19.280.100. If the utility elects to use a distributed energy resource planning process, the IRP should include a summary of these results.

63 See RCW 19.280.030(1)(g) and (i).
64 WAC 480-100-620(8). 65 WAC 480-100-620(3).
Avista Corp.2021 Electric IRP Appendices 817
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Page 12 Overview of Clean Energy Action Plan (CEAP) Requirements
To comply with statute and rules, each utility must develop a ten-year clean energy action plan
that works toward implementing the IRP’s lowest reasonable cost solution, including
incorporation of the social cost of greenhouse gas emissions as a cost adder in its analysis.66 As
the intermediary plan between the IRP and the CEIP, the CEAP should identify the utility’s ten-
year resource “ramp” needed to meet energy, capacity, and associated flexibility in order to
maintain and protect safe, reliable operation and balancing of the electric system, while
achieving other clean energy transformation objectives.67 Specifically, each CEAP should:

• meet clean energy transformation standards, including customer benefit provisions68;
• be informed by the utility’s ten-year cost-effective conservation potential assessment;
• identify the potential cost-effective demand response and load management programs that
may be acquired;
• establish a resource adequacy requirement and demonstrate how each resource, including
renewable, nonemitting, and DERs, may reasonably be expected to contribute to meeting
the utility’s resource adequacy requirement;
• identify any need to develop new, or to expand or upgrade existing, bulk transmission and distribution facilities; and
• identify the nature and extent to which the utility intends to rely on an alternative
compliance option identified under RCW 19.405.040(1)(b), if appropriate.

Overview of Natural Gas IRP Statute and Rule Requirements by Topic

Design Day (Planning Standard), particularly in the context of climate change data or future studies
“Design day” refers to the peak temperature assumption that natural gas local distribution
companies (LDCs) use to develop the plan for their natural gas supply and distribution pipeline
systems. Neither statute nor rule impose any specific requirements for design day in the natural
gas IRPs. Each LDC has the flexibility to identify its design day as appropriate. The utility must include the design day in its natural gas IRP, and provide a discussion justifying its selection,
particularly addressing climate change risk of gradually increasing temperatures over time.

Upstream Emissions & SCGHG
For the first time, statute requires LDCs to model a price on greenhouse gas emissions in the
IRP. The statute specifies the price assigned to these emissions, but only for the purposes of

66 WAC 480-100-620(12).
67 WAC 480-100-610(4)(b). 68 WAC 480-100-610.
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Page 13
setting conservation targets.69 That price is set at the social cost of greenhouse gases (SCGHG), using a 2.5 percent discount rate, where the utility must also model and account for upstream
emissions or “emissions occurring in the gathering, transmission, and distribution of natural gas
to the end user.”

CPA and Conservation Targets

RCW 80.28.380 requires gas companies to identify and acquire all conservation measures that
are available and cost-effective, with an acquisition target approved by the commission every
two years beginning in 2022. The target will be reviewed with the next conservation plan, but the IRP will be a main source of the data. A determination of cost-effective conservation in the IRP
will be the start of the target calculation and must be clearly included in the IRP.

The cost-effectiveness analysis required by this section must include the costs of greenhouse gas
emissions established in RCW 80.28.395. This could be included in the CPA or in a different IRP model. The IRP must include a clear description of how and where the SCGHG is included.

The targets must be based on a conservation potential assessment (CPA) prepared by an
independent third party and approved by the commission. In order for Staff to recommend the
commission approve a CPA there must be:
1. Transparent review of model.
2. Vetting through advisory groups.
3. Consistency with the Council’s method.
4. Internal consistency with load forecast.
While it has been the practice of the utilities to exclude gas transportation customers from
participating in their conservation programs, Staff struggles to find an exclusion for gas
transportation customers in the statutory language of RCW 80.28.380. Thus, in order to identify
all cost-effective conservation, it will be necessary for the utility to separately consider and
evaluate the energy efficiency potential of any customers too large to include in the CPA.70 All available and cost-effective conservation potential must be included. The method chosen should
be discussed with the advisory groups. Staff expects that if this conservation from large
industrial customers is included in the IRP analysis, it is likely to reduce the utility’s need for
distribution system improvements. Renewable Natural Gas (RNG)

Natural gas LDCs “must” offer their customers a voluntary RNG service by tariff.71 Such service

69 RCW 80.28.395. The conservation targets for LDCs are also a new requirement: HB 1257 for the first time
requires LDCs to identify and acquire all cost-effective conservation and requires them to set two-year acquisition targets that will accomplish this goal. RCW 80.28.380.
70 Potential assessments assume average market penetration and savings over sizeable populations. Conservation potential from large industrial customers, including transportation customers, are more appropriately treated
individually than on an average basis. 71 RCW 80.28.390.
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Page 14
would “replace any portion of the natural gas that would otherwise be provided by the gas company.” Second, LDCs “may” propose an RNG program that “would supply renewable
natural gas for a portion of the natural gas sold or delivered to its retail customers.”72 These two
provisions contain an important distinction: The first requires LDCs to offer RNG to those
customers that want it, while the second allows them to offer an RNG program that would serve
all customers. The latter is subject to cost and environmental limitations. Analysis in the IRP will support the utility’s proposals in this area. Further, the utility’s IRP must discuss its plans
concerning RNG.

Storage
WAC 480-90-238(3) requires LDCs to “assess” opportunities to use company-owned or
contracted storage in their IRPs, and also includes storage options as one of many resource
options to be evaluated using a “consistent method to calculate cost-effectiveness.”
Distribution Planning

Each LDC must provide a short-term plan outlining the specific actions to be taken to implement
the long-range integrated resource plan during the two years following submission.73 Each LDC
also typically outlines a multi-year budget for engineering projects through a distribution
scenario decision-making process. LDCs identify areas with growth forecasted to create capacity issues, focusing on areas for future improved distribution capacity needs, and highlight these projects in the IRP.

72 RCW 80.28.385. 73 WAC 480-90-238(3)(h).
Avista Corp.2021 Electric IRP Appendices 820
1
Gall, James
From:Andrew Argetsinger <[e-mail]>
Sent:Tuesday, February 16, 2021 4:31 PM
To:Lyons, John; Gall, James
Cc:Kevin Calhoon; Stuart McCausland
Subject:[External] RE: Avista's Draft 2021 Electric IRP
John / James – Hope all is well. We are reviewing the current draft of the 2021 IRP and had a few questions:

(1) We noticed that there was not a Lancaster PPA extension scenario included in the 2021 draft IRP. Why the
change from last year?
(2) Would you consider revising this draft to include a 10 year Lancaster PPA extension scenario? It seems unlikely
to us that choosing not to extend the Lancaster PPA and turning around to immediately add 210+ MW of new
peaking capacity in 2027 would be economically advantageous enough (compared to a Lancaster PPA extension
scenario) to exclude the extension scenario from the IRP.
(3) Will you share with us the unit parameters for Lancaster that would be used for a Lancaster PPA extension
scenario? We’d like to understand what level of operational flexibility would be assumed in a Lancaster PPA
extension scenario.

Please let me know if you have any questions or clarifications regarding these requests.

Best,

Andrew Argetsinger
Senior Director, Corporate Strategy
Tyr Energy, Inc.
7500 College Blvd., Ste. 400
Overland Park, KS 66210
913.626.0772 (mobile)
[e-mail]

From: Lyons, John <[e-mail]>
Sent: Monday, January 4, 2021 5:20 PM
To:
Subject: Avista's Draft 2021 Electric IRP

CAUTION: This email originated from outside your organization. Exercise caution when opening attachments or clicking
links, especially from unknown senders.
Hello TAC Members,

Attached is a copy of the draft 2021 Electric IRP for your review. Please provide any comments or edits back to us by
Monday, March 1, 2021 to me at [e-mail]. The final IRP and completed appendices will be filed on
April 1, 2021 with the Idaho and Washington Commissions.

Our fifth and final TAC meeting will be held on Thursday, January 21, 2021. The meeting invitation and agenda will be
available by the end of this week. There will also be an opportunity to provide written comments about the draft IRP to
the Washington Commission and a public meeting on February 23, 2020. We will provide more details at the fifth TAC
meeting.

Avista Corp.2021 Electric IRP Appendices 821
2
Thank you for all of your participation in the 2021 IRP,

John Lyons
Avista Corp.
509-495-8515

CONFIDENTIALITY NOTICE: The contents of this email message and any attachments are intended solely for the addressee(s) and may contain
confidential and/or privileged information and may be legally protected from disclosure. If you are not the intended recipient of this message or an agent
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USE CAUTION - EXTERNAL SENDER
Do not click on links or open attachments that are not familiar.
For questions or concerns, please e-mail [e-mail]
Avista Corp.2021 Electric IRP Appendices 822
November 14, 2020
To: John Lyons, John Barber, Dennis Vermillion, IPUC, WPUC & TAC committee members
From: Dave Van Hersett, TAC Member Emeritus
Subject: Biomass Generation omitted from considered IRP Options
Just read the draft IRP and found that Biomass Generation has been omitted from considered
options for analysis. We have a substantial renewable biomass fuel supply in our Inland
Empire. We should utilize it for the good of man rather than fuel for forest fires. So here is the
case for Biomass Generation to provide new generation that meets CETA and brings back the
forest products industry to the Inland Empire.
1. CETA approved three options for new power generation, Wind, Solar and Biomass.
2. Kettle Falls 50 MW Biomass generation plant has been operating since the early 80’s
utilizing sawmill biomass fuels generated during the processing of round logs to make
rectangular lumber and other products.
3. The logging process does not utilize the tops and branches of the tree. The tops and
branches equal the weight of the saw logs delivered to the sawmill.
4. Sawmill biomass fuel is ten percent of the weight of the saw logs brought into the
sawmill.
5. The tops and branches weigh ten times the weight of the sawmill biomass fuel. This
ratio is dependent on type and specie of forest growth.
6. Since the 50 MW Kettle falls Biomass power plant utilizes sawmill biomass fuels, the
tops and branches logging biomass would have enough fuel for 500 MW of biomass
generation.
7. Biomass fueled generation works when the sun does not shine and works when the
wind is not blowing and can be scheduled to meet the load profile of the customers.
Thus, less generation capacity is needed due to load factors of Wind and Solar to meet
given customer loads.
8. Avista has the experience and trained staff to operate thermal biomass power
generation plants.
9. Note that every year Logging fuels are left in the forest to rot and/or be fuels for forest
fires. This is because the trees grow every year independent of politics. Forest fuels are
a renewable bioenergy resource. We have been wasting this energy source for years.
Utilizing Logging Biofuels would reduce the fuel available for forest fires. Utilizing Logging
biofuels would provide excellent forest management practices to optimize the production of
timber products for the good of mankind. Eliminating forest fire fuels would bring back timber
supplies to the 11 former sawmill towns in the Inland Empire. Bringing back the forest products
industry would bring back jobs needed for the ever-increasing population (2% per year).
Avista Corp.2021 Electric IRP Appendices 823
Both Wind and Solar receive financial incentives to make them competitive with existing
generation resources. Biomass fuels should qualify for the same incentives. These incentives
would then improve the cost of recovering the logging biofuels and delivering them to one or
more power plant locations. The assumption here is that the wind and solar resource utilized in
the draft IRP will continue to receive incentives.
A typical sawmill supports a 5 MW biomass power plant utilizing sawmill biomass fuel. Thus,
each sawmill’s logging biofuels would support a 50 MW biomass power plant utilizing logging
biofuels. This would minimize fuel transportation expense. Integrating 55 MW into the local
electrical distribution system would be easier than one 500 MW power plant.
As the demand for wind and solar increases, the supply of these resources will be subject to the
market demand. The price of wind and solar will likely increase as demand increases and
delivery extended. Biomass fueled power plants are readily available today from several
experienced builders and contractors.
From an operating perspective, Avista could go into partnerships with the sawmills, building
and operating the biomass power plants. The sawmills would provide fuel and utilize steam for
their dry kiln operations. Timber from area forests has been for hundreds of years assuring a
firm fuel supply. Sawmills have been operating in this area since the 1800’s and will continue to
operate as long as the ever-growing population requires timber products for their use. In the
recent 40 years the supply of timber has been subject to politics and the degrading of forest
management practices.
The above concept would be like the former TWWPCO management committing to the
development and investing in hydro and fossil fuel power plants to insure a reliable and low-
cost power cost for its customers. TWWPCO sold excess capacity until it was needed for its
own customers loads.
Biomass generation option should be included as one of the alternatives
evaluated to determine relative economics of the three approved new
generation types, wind, solar and biomass here in the Inland Empire. We have
the moral obligation to utilize the forests for the benefit of mankind not to fuel
forest fires to destroy property and kill our neighbors.

Avista Corp.2021 Electric IRP Appendices 824
Guest Commentary
THE GREEN OPPORTUNITY: Executive Summary
The 40-year Green movement has brought devastation to the forests, destruction
to property and death to inhabitants and created 11 sawmill ghost towns in the
Inland Empire. In 2020 the Conservation Energy Transformation Act (CETA) was
enacting into law providing the key ingredient enabling complete recovery from
40 years of devastation. This act requires that any new electric generation be
from Wind, Solar and BIOMASS. Biomass is wood fuel remaining from harvesting
forests to make products for mankind. We now can bring back the vibrant forest,
clean air, and return the forest products industry and jobs for the inhabitants of
the Inland Empire.
A little history: When I grew up in Spokane in the 50’s I do not remember smoke
filled skies at the lake in the summer. We had lots of towns participating in the
Lilac Parade, logging contests, and fun high school games all around the area.
I remember EXPO 74. All the rides and summer entertainment it brought. EXPO
74 brought the River Front Park that cleaned up the town and provide a major
improvement to the Spokane downtown. This came about from the foresight and
leadership of local businesses and government at the time. No smoke-filled skies
during the EXPO.
Now it is time for our current leadership to take advantage of the enabling CETA
law to bring back our forest products industry and the 30,000 or so jobs with it.
We need this to provide employment for our children and our ever-growing
population. We need to utilize our forests for the benefit of mankind rather than
fuel for forest fires and to clean up the air.
BIOMASS FOREST RESOURCES is our solution!
A BIOMASS project is an electric generating plant that uses wood waste for fuel
instead of fossil fuels. The Kettle Falls 50 Megawatt Biomass fueled power plant
has been operating since the 1980’s. What do we have to do to make this
happen?

Avista Corp.2021 Electric IRP Appendices 825
First, we have to educate our local governments, our captains of industry, our
utility leadership, and our congressional representatives on the biomass recovery
opportunity that is here today. Then they must put their heads and resources
together for the betterment of its citizens and the husbanding of our local forest
resources.
Second, we have to pre-license Biomass Project sites at the former sawmill towns.
These sites are in the logical locations to minimize the cost of the transportation
of the forest harvested products. These sites will receive a very enthusiastic
approval from the occupants of the former mill towns. Pre-licensing sites will
prove that the public has an extremely high approval of biomass electric
generation. Pre-licensing sites will verify the acceptance of utilization of the local
forests for the benefit of mankind rather than fuel for forest fires. The local
utilities have the skills and resources to accomplish this.
Third, the forest management practices must be changed to allow the use of
timber for products for mankind instead of growing fuel for forest fires. This will
require the assistance of our congressional representatives to make changes to
US Forest Service and State forest management practices.
Fourth, the utilities in this area must require that Biomass be their preferred new
generation resource instead of Wind and Solar. They must incorporate the
benefits of the renewed 10,000 mill jobs and supporting 30,000 jobs in our area
into their financial evaluations when comparing to the Wind and Solar options.
The infrastructure for the utility distribution systems remains in place from the
days of the operating sawmills. No major transmission systems are needed as
compared to Wind and Solar. Benefits from the Biomass investment to the local
area would include more jobs, more tax basis to support local government and
schools, reduction in forest fire prevention and recovery costs, and cleaner air to
name a few.
Finally, bringing back the forest products industry will create a major economic
boon to the Inland Empire. As our population grows our children will not have to
leave the area to find employment. Our region’s natural resource will be
returned to be used to benefit mankind. The forest and our population grow
every year independent of politics.
Bringing back the forest products industry will be our legacy!!
Avista Corp.2021 Electric IRP Appendices 826
Now for more detail:
Consequences of Going Green
The consequences of going green for the past 40 years are as follows:
1. More fuel for forest fires, property destruction and killing persons.
2. Loss of timber supplies for local sawmills.
3. Lost jobs for the inland empire population.
4. Loss of land for growing food.
5. Loss of scenery viewing from wind and solar.
6. Loss of investment in Inland Empire towns.
7. Loss of tax revenue to support local schools and government.
8. Double to triple electric rates.
9. Triple the generation capacity installed needed to meet customer loads.
10. Increased mining of resources over traditional generation to provide
materials to manufacture and build wind and solar.
11. Loss of birds. Wind power plants kill 30% of the bird population from blade
strikes.
Reflections of a lifetime
Author: A 5th generation of Spokanite, 82-year-old, Veteran, Retired Professional
Engineer, businessman, four great children, Jaycee, Rotarian, Eagle Scout, Scout
Master, Soccer Coach, Spokane School District Citizens Advisory Committee, 50-
year home owner in Spokane, NCHS graduate, WSU BSME & MBA. Career in coal,
oil, natural gas and biomass fueled Power Plant Development and performance-
based Energy Conservation in the commercial, industrial and institutional sectors.
I am 82 now in my twilight and have limited time left to pass on my observations
of a lifetime. My classmates are showing up in an ever-increasing number in the
obituary notices daily. Time is getting short for me give something back. I am a
product of the values of our area and the education system provided by our
citizens. My name is Dave Van Hersett, SR., a proud Spokane citizen.

Avista Corp.2021 Electric IRP Appendices 827
INLAND EMPIRE NATURAL RESOURCES
We have been blessed with the following natural resources in our area to manage
and harvest for the benefit of mankind. They are (1) Water, (2) Mineral resources
underground, (3) farmlands to produce food, (4) forests to grow products for
mankind and finally, our (5) population. We need to husband each of the
resources to support our ever-growing population.
Our forefathers found minerals, gold, silver & lead in the Kellogg wilderness.
Timber from the forests built the railroads to ship the minerals to markets.
Timber provided housing and heat for the population. Water was used to make
electric power to enable mining, industry and support the population. We enjoy
the benefits of our predecessors efforts.
AVISTA ABANDONED THE MAJORITY:
Since renaming The Washington Water Power Company to Avista we customers
have increased the officers compensation from hundreds of thousands to
millions. This makes their compensation ten times that of the President of the
USA and the Gov of Washington State. The average income of Avista customers
is $40,000 per year, about 100 times less than the Avista management
compensation. For what we customers pay Avista management, we expect that
they can accomplish the impossible like Superman and make real improvements
for their 300,000 customers. So, what has the Avista MGT done for its
customers?
(1) They have adopted a strategy to increase the customer monthly billing by
up to three times.
They took their knee to the Green movement indifferent to the will of majority of
its customers. 99% of the customers chose not to participate in Avista’s option’s
to purchase higher cost wind and solar power. The customers gave an
extraordinarily strong signal that they want reliable and low-cost electrical power.
The Avista Utility 20 year plan for generation removes fossil fuel generation and
adds wind and solar. The utility has not come up with any plans to develop
additional revenue to offset the huge increase coming to our energy costs and
bills.

Avista Corp.2021 Electric IRP Appendices 828
(2) They abandoned their Forest Products industry
The result is the creation of 11 ghost towns from the loss of the sawmills in these
towns. These natural forest industries were one of the reasons that founded the
WWP over 100 years ago in 1889. The forest products industry has been
abandoned to grow fuel for forest fires instead of products for mankind. This
accounts for a loss of over 10,000 forest industry jobs and the 30,000 people
supporting the forest products industry in Avista’s service area. Where do these
people go now? Our children leave the area to find employment. To get an idea
of the impact on our forest products towns compare the vibrant town of Colville
with former sawmill towns like Usk, Cusick, Republic, Kellogg, Athol to name a
few.
(3) Tried to sell the utility two times.
Washington and Idaho Utility Commissions did not approve these sales. In both
cases the management would have received a substantial sale commission. I was
never in favor of selling our utility.

Historical Innovation and Leadership in Inland Empire
We enjoy the benefits of our forefathers innovation and leadership to bring
benefits to the local economy and provide employment of our population. In the
1889 The Washington Water Power Company was formed to provide power and
energy to the industries of the time, timber, mining and agriculture. Hydro power
was developed to provide low cost and reliable energy for the ever-growing
industry and populations of this region. Noxon and Cabinet Hydro power projects
were developed to serve the ever-increasing population and industrial customers.
The 1400 MW Centralia Coal Plant and Coal Strip projects were partnered in to
provide reliable and low-cost power for the ever-growing customer loads. Excess
power was sold to other utilities here in the PNW to keep our energy costs low.
In the 70’s TWWPCO developed the Kettle Falls 50 megawatt Biomass Power
Plant utilizing sawmill wood waste that was disposed of in sawmill teepee burners
smoking up the air. This biomass project provided a waste disposal solution for
the forest products industry in the Inland Empire. This plant is operating today.
Avista Corp.2021 Electric IRP Appendices 829
Proposed Action Plan to offset higher energy costs:
In 2020 WA legislature passed a law that requires the utilities to eliminate the use
of plentiful fossil fuels to provide electric power to its customers. It is called the
Clean Energy Transformation Act (CETA). Eliminating fossil fuel generation will
triple our electric rates. The approved new electric generation resources are
Wind, Solar and Biomass.
CETA creates the opportunity to develop up to 750 MW of renewable biomass
generation utilizing our regions biofuels from the improved management of our
region’s forests. Excess generation would be sold to offset the increase in power
costs from the adoption of wind and solar generation in place of low cost and
reliable fossil fueled power generation. This similar to selling our excess hydro
generation until needed for our customers. These biomass projects would also
bring back thousands of jobs to the abandoned forest products industry and
revive the ghost towns in our area. The infrastructure for these ghost towns is
still in place so the incremental revenue benefits would again benefit the
customers.
Develop Renewable Bioenergy Power Plants like Kettle Falls. Install 5 to 10 MW
wood fueled power plants at each of the 11 ghost towns former sawmills and 50
MW like Kettle Falls Power Plant at each of these ghost towns to bring back the
forest products industry. Initiate an aggressive program to clean up the forests in
our area due to the lack of management for the past 40 years. Refer to the
Vaagen Brothers web site to see what a managed forest looks like. Cleaning up
the forest floor will bring biomass fuels along with the residue from logging
operations. There is some 750 MW of biofuels for renewable electric generation
available from the forests in the Inland Empire.
Solicit the help from our congresswoman, Kathy McMorris Rodgers to change
federal laws to enable the forest management practices to support utilizing
biomass for benefit of mankind instead for fuel for forest fires. We need jobs for
our population, we do not want to destroy forests, property or kill persons.
Developing these generation resources will give us the ability to sell excess
energy to the other areas in WA state that will have to meet the 2005 date
required by CETA regulation passed by our Legislature. The sale of this renewable
energy will offset the higher cost of wind and solar such that our electric rates will
Avista Corp.2021 Electric IRP Appendices 830
not increase three times. This development effort will also bring 10,000 forest
products jobs and their supporting 30,000 population back to our area and reduce
the fuel available for forest fires. We will go back to the notion of raising trees to
produce products for the ever-increasing population and not for fuel for forest
fires. Let’s provide jobs for our children instead of forcing them to leave our area
for employment.
Pre-license Biomass Project sites
Development of Biomass generation requires more effort than wind and solar.
Biomass plants utilizing forest residues will require changes to forest
management practices, changes to new generation priorities, enacting legislative
changes and changes to forest industry logging practices. This is in addition to the
more complicated Environmental Impact Statements and a mirid of permits from
multiple agencies. Our utility management can make these changes happen for
the benefit of their customers. It is easier to develop wind and solar as you only
need vacant land.
Wind and solar benefit from the government incentives to reduce their net
generation costs to compete with fossil fuel generation. These same financial
incentives should be made available to Biomass Generation. The utility should be
working to make this happen.
To make Biomass electric generation possible, the utilities pre-license plants sites
would enable biomass project contractors to be competitive with wind and solar
proposals. Pre-licensing will eliminate the unknown from their proposals and
allow them to focus on what they do best, build power plants. Thus, we would get
competitive prices and that is good for the customers and the region forests.
Renewable generation from Garbage.
Populations generate garbage, a fuel. The fuel heating value of garbage is the
same as forest fuels. Each person generates about 1 ton of garbage per year.
Thus the 500,000 persons in our area generate about 500,000 tons of fuel per
year, enough for 50 MW of power. The city of Spokane uses about 300 MW of
electric power. We have an existing 25 MW at the waste-to-energy plant at the
Spokane Airport. There is enough unused fuel in our area for an additional 25
MW from Spokane County and Coeur’ d Alene’s garbage.
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Right now, the extra non burned garbage is hauled 210 miles by truck to
Roosevelt, Washington landfill. This creates land that is unusable for decades. A
local example of this is the former land fill you can see south of the I-90 at Liberty
Lake. The vacant land between the apartment units on the hill is a former land fill
site.

TIME FOR OUR LEADERSHIP TO STEP UP AND CREATE A LEGACY
Only once in your lifetime do you get the opportunity to really create a legacy
that will stand the test of time. Bringing back the forest products industry to
the Inland Empire is one of those unique opportunities. Our home grown talent
can make this happen just like our predecessors. We ,the customers, will all
benefit from this effort and like our predecessors you will have the gratitude of
your fellow men and women forever. This task will not be easy. It will take the
cooperative efforts of all of us to make it happen. So let us be like our
predecessors who against all odds, made legacies like mining, hydro power,
forest products industry, EXPO 74 to name a few.

Avista Corp.2021 Electric IRP Appendices 832

2021 Electric Integrated
Resource Plan

Appendix D – Confidential
Historical Generation Operation
Data

Idaho – Confidential pursuant to Sections 74-109, Idaho Code
Washington – Confidential per WAC 480-07-160

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Avista Corp.2021 Electric IRP Appendices 834

2021 Electric Integrated
Resource Plan

Appendix E – AEG Conservation
Potential & Demand Response
Potential Assessments

Avista Corp.2021 Electric IRP Appendices 835

Energy Solutions. Delivered.
AVISTA CONSERVATION POTENTIAL
ASSESSMENT FOR 2022-2045
De cember 1 , 2020
AVISTA CORPORATION
Avista Corp.2021 Electric IRP Appendices 836

This work was performed by Applied Energy Group, Inc. (AEG) 500 Ygnacio Valley Rd, Suite 250 Walnut Creek, CA 94596
Project Director: E. Morris Project Manager: K. Walter Project Team: G. Wroblewski
M. McBride
K. Marrin T. Williams

AEG would also like to acknowledge the contributions of
R. Finesilver L. Haley
J. Gall
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C ONTENTS
1 INT RODUCTI ON....................................................................................................... 9
Abbreviations and Acronyms .................................................................................. 10
2 ANALYS IS APPROACH AND D ATA DEVEL OPMENT ................................................. 13
Ov erview of Analysis Approach............................................................................... 13
LoadMAP Model ......................................................................................... 13
Definitions of Potential................................................................................. 15
Market Characterization.............................................................................. 15
Baseline P rojection...................................................................................... 17
Conservation Measure Analysis .................................................................... 17
Representative Conservation Measure Data Inputs ....................................... 19
Conservation Potential ................................................................................ 21
Data Development ................................................................................................ 21
Data Sources .............................................................................................. 21
AEG Data ................................................................................................... 23
Other Secondary Data and Reports ............................................................. 24
Data Application ................................................................................................... 24
Data Application for Market Characterization .............................................. 24 Data Application for Market Profiles ............................................................. 25
Data Application for Baseline Projection ...................................................... 25
Conservation Measure Data Application ...................................................... 31
Data Application for Technical Achievable Potential .................................... 32
3 MARKET CH ARACTE RIZATI ON AND M ARKET PROFILE S .......................................... 33
Energy Use Summary .............................................................................................. 33
Residential Sector .................................................................................................. 34
Commercial Sector ................................................................................................ 41
Industrial Sector ..................................................................................................... 48
4 BAS ELI NE PROJECTI ON ......................................................................................... 53
Residential Sector .................................................................................................. 53
Annual Use ................................................................................................. 53
Commercial Sector Baseline Projections .................................................................. 56
Annual Use ................................................................................................. 56
Industrial Sector Baseline Projections ....................................................................... 59
Annual Use ................................................................................................. 59
Summary of Baseline Projections across Sectors and States ....................................... 61
Annual Use ................................................................................................. 61
5 CONSE RV ATI ON POTE NTIAL .................................................................................. 62
Ov erall Summary of Energy Efficiency Potential........................................................ 62
Summary of Annual Energy Savings .............................................................. 62
Summary of Conservation Potential by Sector .......................................................... 66
Residential Conservation Potential .......................................................................... 67
Commercial Conservation Potential ........................................................................ 73
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Industrial Conservation Potential ............................................................................. 78
6 DEMAND RES PONSE POTENTI AL .......................................................................... A-1
Market Characterization ....................................................................................... A-1
Market segmentation ................................................................................ A-1
Customer Counts by Segment.................................................................... A-2
Forecasts of Winter and Summer Peak Demand .......................................... A-3 System and Coincident Peak Forecasts by State ......................................... A-4
Equipment End Use Saturation ................................................................... A-6
DSM Program Options........................................................................................... A-8
Program Descriptions ................................................................................ A-8
Program Assumptions and Characteristics .................................................A-11
Other Cross-cutting Assumptions ...............................................................A-18
DR Potential and Cost Estimates ...........................................................................A-19
Integrated Potential Results ......................................................................A-19
Winter TOU Opt-in Scenario ......................................................................A-19
Cost Results .............................................................................................A-22 Winter TOU Opt-out Scenario ....................................................................A-23
Cost Results .............................................................................................A-26
Summer TOU Opt-in Scenario ....................................................................A-27
Cost Results .............................................................................................A-31 Summer TOU Opt-out Scenario..................................................................A-32
Cost Results .............................................................................................A-36
Stand-alone Potential Results ....................................................................A-37
Winter Results...........................................................................................A-37
Summer Results ........................................................................................A-40 Ancillary Serv ices .....................................................................................A-44
Winter Results...........................................................................................A-44
A MARKET PROFILES.................................................................................................. A-1
B MARKET ADOPTION (RAMP) RATES ........................................................................... B-1
C MEASURE DATA ..................................................................................................... C-1

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LIST OF FIGURES
Figure 2-1 LoadMAP Analysis Framework......................................................................... 14
Figure 2-2 Approach for Conservation Measure Assessment............................................. 18
Figure 3-1 Sector-Lev el Electricity Use in Base Year 2017, Washington ............................... 33
Figure 3-2 Sector-Lev el Electricity Use in Base Year 2017, Idaho ........................................ 34
Figure 3-3 Residential Electricity Use and Winter Peak Demand by End Use (2017),
Washington ................................................................................................... 35
Figure 3-4 Residential Electricity Use and Winter Peak Demand by End Use (2017), Idaho... 36
Figure 3-5 Residential Intensity by End Use and Segment (Annual kWh/HH, 2017),
Washington ................................................................................................... 37
Figure 3-6 Residential Intensity by End Use and Segment (Annual kWh/HH, 2017), Idaho .... 38
Figure 3-7 Commercial Electricity Use and Winter Peak Demand by End Use (2017),
Washington ................................................................................................... 43
Figure 3-8 Commercial Electricity Use and Winter Peak Demand by End Use (2017), Idaho
.................................................................................................................... 44
Figure 3-9 Commercial Electricity Usage by End Use Segment (GWh, 2017), Washington.... 45
Figure 3-10 Commercial Electricity Usage by End Use Segment (GWh, 2017), Idaho ............ 45
Figure 3-11 Industrial Electricity Use and Winter Peak Demand by End Use (2017), All
Industries, WA ................................................................................................ 48
Figure 3-12 Industrial Electricity Use and Winter Peak Demand by End Use (2017), All
Industries, ID .................................................................................................. 49
Figure 4-1 Residential Baseline Projection by End Use (GWh), Washington ......................... 54
Figure 4-2 Residential Baseline Projection by End Use – Annual Use per Household,
Washington ................................................................................................... 55
Figure 4-3 Residential Baseline Projection by End Use (GWh), Idaho.................................. 56
Figure 4-4 Residential Baseline Sales Projection by End Use – Annual Use per Household,
Idaho............................................................................................................ 56
Figure 4-5 Commercial Baseline Projection by End Use, Washington ................................. 58
Figure 4-6 Commercial Baseline Projection by End Use, Idaho .......................................... 58
Figure 4-7 Industrial Baseline Projection by End Use (GWh), Washington............................ 60
Figure 4-8 Industrial Baseline Projection by End Use (GWh), Idaho .................................... 60
Figure 4-9 Baseline Projection Summary (GWh), WA and ID Combined ............................. 61
Figure 5-1 Summary of EE Potential as % of Baseline Projection (Annual Energy),
Washington ................................................................................................... 64
Figure 5-2 Summary of EE Potential as % of Baseline Projection (Annual Energy), Idaho...... 64
Figure 5-3 Baseline Projection and EE Forecast Summary (Annual Energy, GWh),
Washington ................................................................................................... 65
Figure 5-4 Baseline Projection and EE Forecast Summary (Annual Energy, GWh), Idaho ..... 65
Figure 5-5 Technical Achievable Conservation Potential by Sector (Annual Energy, GWh)
.................................................................................................................... 66
Figure 5-6 Residential Conservation Savings as a % of the Baseline Projection (Annual
Energy), Washington ...................................................................................... 68
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Figure 5-7 Residential Conservation Savings as a % of the Baseline Projection (Annual
Energy), Idaho............................................................................................... 68
Figure 5-8 Residential Technical Achievable Sav ings Forecast (Cumulative GWh),
Washington ................................................................................................... 70
Figure 5-9 Residential Technical Achievable Savings Forecast (Cumulativ e GWh), Idaho ... 72
Figure 5-10 Commercial Conservation Savings (Energy), Washington ................................. 74
Figure 5-11 Commercial Conservation Savings (Energy), Idaho .......................................... 74
Figure 5-12 Commercial Technical Achiev able Sav ings Forecast (Cumulative GWh),
Washington ................................................................................................... 76
Figure 5-13 Commercial Technical Achievable Savings Forecast (Cumulative GWh), Idaho
.................................................................................................................... 78
Figure 5-14 Industrial Conservation Potential as a % of the Baseline Projection (Annual
Energy), Washington ...................................................................................... 79
Figure 5-15 Industrial Conservation Potential as a % of the Baseline Projection (Annual
Energy), Idaho............................................................................................... 80
Figure 5-16 Industrial Technical Achievable Sav ings Forecast (Cumulative GWh),
Washington ................................................................................................... 82
Figure 5-17 Industrial Technical Achievable Savings Forecast (Annual Energy, GWh), Idaho
.................................................................................................................... 83
Figure 6-1 Contribution to Estimated System Coincident Peak Forecast by State (Summer)
.................................................................................................................. A-5
Figure 6-2 Contribution to Estimated System Coincident Peak Forecast by State (Winter). A-6
Figure 6-3 Summary of Potential Analysis for Av ista (TOU Opt-In Winter Peak MW
@Generator) ..............................................................................................A-20
Figure 6-4 Summary of Winter Potential Analysis for Avista (TOU Opt-Out MW @Generator)
.................................................................................................................A-24
Figure 6-5 Summary of Summer Potential by Option (TOU Opt-In MW @Generator) .........A-28
Figure 6-6 Summary of Summer Potential – TOU Opt-Out (MW @Generator) ...................A-32
Figure 6-7 and Table A-1 show the winter demand savings from individual DR options for
selected years of the analysis. These sav ings represent stand-alone savings
from all av ailable DR options in Av ista’s Washington and Idaho serv ice
territories. ...................................................................................................A-37
Figure 6-8 Summary of Potential Analysis for Avista (Winter Peak MW @Generator).........A-38
Figure 6-9 Summary of Summer Potential by Option (MW @Generator) ..........................A-41

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LIST OF TABLES
Table 1-1 Explanation of Abbrev iations and Acronyms.................................................... 10
Table 2-1 Ov erview of Avista Analysis Segmentation Scheme.......................................... 16
Table 2-2 Example Equipment Measures for Central AC – Single-Family Home .................. 20
Table 2-3 Example Non-Equipment Measures – Single Family Home, Existing ..................... 20
Table 2-4 Number of Measures Evaluated ...................................................................... 20
Table 2-5 Data Applied for the Market Profiles ............................................................... 26
Table 2-6 Data Needs for the Baseline Projection and Potentials Estimation in LoadMAP... 27
Table 2-7 Residential Electric Equipment Standards ........................................................ 28
Table 2-8 Commercial Electric Equipment Standards ...................................................... 29
Table 2-9 Industrial Electric Equipment Standards ........................................................... 30
Table 2-10 Data Needs for the Measure Characteristics in LoadMAP ................................. 31
Ta ble 3-1 Avista Sector Control Totals (2017), Washington ............................................... 33
Table 3-2 Avista Sector Control Totals (2017), Idaho........................................................ 34
Table 3-3 Residential Sector Control Totals (2017), Washington ........................................ 34
Table 3-4 Residential Sector Control Totals (2017), Idaho................................................. 35
Table 3-5 Average Market Profile for the Residential Sector, 2017, Washington ................. 39
Table 3-6 Average Market Profile for the Residential Sector, 2017, Idaho ......................... 40
Table 3-7 Commercial Sector Control Totals (2017), Washington...................................... 41
Table 3-8 Commercial Sector Control Totals (2017), Idaho .............................................. 42
Table 3-9 Average Electric Market Profile for the Commercial Sector, 2017, Washington ... 46
Table 3-10 Average Electric Market Profile for the Commercial Sector, 2017, Idaho ........... 47
Table 3-11 Industrial Sector Control Totals (2017) .............................................................. 48
Table 3-12 Average Electric Market Profile for the Industrial Sector, 2017, Washington ........ 51
Table 3-13 Average Electric Market Profile for the Industrial Sector, 2017, Idaho................. 52
Table 4-1 Residential Baseline Sales Projection by End Use (GWh), Washington ................ 54
Table 4-2 Residential Baseline Sales Projection by End Use (GWh), Idaho ......................... 55
Table 4-3 Commercial Baseline Sales Projection by End Use (GWh), Washington .............. 57
Table 4-4 Commercial Baseline Sales Projection by End Use (GWh), Idaho ....................... 57
Table 4-5 Industrial Baseline Projection by End Use (GWh), Washington............................ 59
Table 4-6 Industrial Baseline Projection by End Use (GWh), Idaho .................................... 59
Table 4-7 Baseline Projection Summary (GWh), WA and ID Combined ............................. 61
Table 5-1 Summary of EE Potential (Annual Energy, GWh), Washington ............................ 63
Table 5-2 Summary of EE Potential (Annual Energy, GWh), Idaho..................................... 63
Table 5-3 Technical Achievable Conservation Potential by Sector (Annual Use), WA and
ID ................................................................................................................. 66
Table 5-4 Residential Conservation Potential (Annual Energy), Washington ...................... 67
Table 5-5 Residential Conservation Potential (Annual Energy), Idaho............................... 67
Table 5-6 Residential Top Measures in 2019 (Annual Energy, MWh), Washington ............... 69
Table 5-7 Residential Top Measures in 2019 (Annual Energy, MWh), Idaho ........................ 71
Table 5-8 Commercial Conservation Potential (Annual Energy), WA ................................ 73
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Table 5-9 Commercial Conservation Potential (Annual Energy), Idaho ............................ 73
Table 5-10 Commercial Top Measures in 2019 (Annual Energy, MWh), Washington ............. 75
Table 5-11 Commercial Top Measures in 2019 (Annual Energy, MWh), Idaho ...................... 77
Table 5-12 Industrial Conservation Potential (Annual Energy), WA ..................................... 78
Table 5-13 Industrial Conservation Potential (Annual Energy), Idaho ................................. 79
Table 5-14 Industrial Top Measures in 2019 (Annual Energy, GWh), Washington .................. 81
Table 5-15 Industrial Top Measures in 2019 (Annual Energy, GWh), Idaho ........................... 82
Table 6-1 Market Segmentation .................................................................................. A-2
Table 6-2 Baseline C&I Customer Forecast by State and Customer Class........................ A-2
Table 6-3 Baseline System Winter Peak Forecast (MW @Meter) ...................................... A-3
Table 6-4 Winter Load Factors and Baseline Coincident Peak Forecast by Segment (MW
@Meter) ...................................................................................................... A-4
Table 6-5 Summer Load Factors and Baseline Coincident Peak Forecast by Segment (MW
@Meter) ...................................................................................................... A-4
Table 6-6 2017 End Use Saturations by Customer Class, Washington............................... A-7
Table 6-7 2017 End Use Saturation by Customer Class, Idaho......................................... A-7
Table 6-8 Class 1 DSM Products Assessed in the Study ..................................................A-12
Table 6-9 DSM Steady-State Participation Rates (% of eligible customers) .....................A-13
Table 6-10 DSM Per Participant Impact Assumptions......................................................A-15
Table 6-11 DSM Program Operations Maintenance, and Equipment Costs (Washington) .A-16
Table 6-12 Marketing, Recruitment, Incentiv e, and Development Costs (Washington) .....A-17
Table 6-13 DSM Program Operations Maintenance, and Equipment Costs (Idaho) ..........A-17
Table 6-14 Marketing, Recruitment, Incentiv e, and Development Costs (Idaho) ..............A-18
Table 6-15 Achievable DR Potential by Option (TOU Opt-In Winter MW @Generator) .......A-20
Table 6-16 Achievable DR Potential by Option for Washington (TOU Opt-In Winter MW
@Generator) ..............................................................................................A-21
Table 6-17 Achievable DR Potential by Option for Idaho (TOU Opt-In Winter MW
@Generator) ..............................................................................................A-22
Table 6-18 DR Program Costs and Potential (TOU Opt-In Winter).....................................A-23
Table 6-19 Achievable DR Potential by Option – TOU Opt-Out (Winter MW @Generator) .A-24
Table 6-20 Achievable DR Potential by Option for Washington - TOU Opt-Out (MW
@Generator) ..............................................................................................A-25
Table 6-21 Achievable DR Potential by Option for Idaho – TOU Opt-Out (MW @Generator)
.................................................................................................................A-26
Table 6-22 DR Program Costs and Potential – TOU Opt Out Winter ..................................A-27
Table 6-23 Achievable DR Potential by Option TOU Opt-In (Summer MW @Generator) ....A-28
Table 6-24 Achievable DR Potential by Option for WashingtonTOU Opt-In (Summer MW
@Generator) ..............................................................................................A-29
Table 6-25 Achievable DR Potential by Option for Idaho TOU Opt-In (Summer MW
@Generator) ..............................................................................................A-30
Table 6-26 DR Program Costs and Potential – Summer TOU Opt-In ..................................A-31
Table 6-27 Achievable DR Potential by Option – TOU Opt-Out (Summer MW @Generator)A-34
Table 6-28 Achievable DR Potential by Option for Washington – TOU Opt-Out (Summer MW
@Generator) ..............................................................................................A-35
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Table 6-29 Achievable DR Potential by Option for Idaho – TOU Opt-Out (Summer MW
@Generator) ..............................................................................................A-35
Table 6-30 DR Program Costs and Potential – Summer TOU Opt-Out ...............................A-36
Figure 6-7 and Table 6-31 show the winter demand sav ings from indiv idual DR options for
selected years of the analysis. These sav ings represent stand-alone savings
from all av ailable DR options in Av ista’s Washington and Idaho serv ice
territories. ...................................................................................................A-37
Table 6-32 Achievable DR Potential by Option (Winter MW @Generator) ........................A-38
Table 6-33 Achievable DR Potential by Option for Washington (Winter MW @Generator).A-39
Table 6-34 Achievable DR Potential by Option for Idaho (Winter MW @Generator) .........A-40
Table 6-35 DR Program Costs and Potential (Winter).................. Error! Bookmark not defined.
Table 6-36 Achievable DR Potential by Option (Summer MW @Generator) .....................A-41
Table 6-37 Achievable DR Potential by Option for Washington (Summer MW @Generator)A-42
Table 6-38 Achievable DR Potential by Option for Idaho (Summer MW @Generator) .......A-43
Table 6-39 DR Program Costs and Potential – Summer ............... Error! Bookmark not defined.
Table A-1 Washington Residential Single Family Market Profile ....... Error! Bookmark not defined.
Table A-2 Washington Residential Multi Family Market Profile......... Error! Bookmark not defined.
Table A-3 Washington Residential Mobile Home Market Profile ...... Error! Bookmark not defined.
Table A-4 Washington Residential Low -Income Market Profile ........ Error! Bookmark not defined.
Table A-5 Washington Commercial Large Office Market Profile ..... Error! Bookmark not defined.
Table A-6 Washington Commercial Small Office Market Profile ...... Error! Bookmark not defined.
Table A-7 Washington Commercial Retail Market Profile................ Error! Bookmark not defined.
Table A-8 Washington Commercial Restaurant Market Profile ........ Error! Bookmark not defined.
Table A-9 Washington Commercial Grocery Market Profile ............ Error! Bookmark not defined.
Table A-10 Washington Commercial Health Market Profile ............ Error! Bookmark not defined.
Table A-11 Washington Commercial College Market Profile .......... Error! Bookmark not defined.
Table A-12 Washington Commercial School Market Profile ............ Error! Bookmark not defined.
Table A-13 Washington Commercial Lodging Market Profile .......... Error! Bookmark not defined.
Table A-14 Washington Commercial Warehouse Market Profile...... Error! Bookmark not defined.
Table A-15 Washington Commercial Miscellaneous Market Profile . Error! Bookmark not defined.
Table A-16 Washington Industrial Market Profile ............................ Error! Bookmark not defined.
Table A-17 Idaho Residential Single Family Market Profile .............. Error! Bookmark not defined.
Table A-18 Idaho Residential Multi Family Market Profile ................ Error! Bookmark not defined.
Table A-19 Idaho Residential Mobile Home Market Profile ............. Error! Bookmark not defined.
Table A-20 Idaho Residential Low-Income Market Profile ............... Error! Bookmark not defined.
Table A-21 Idaho Commercial Large Office Market Profile ............ Error! Bookmark not defined.
Table A-22 Idaho Commercial Small Office Market Profile ............. Error! Bookmark not defined.
Table A-23 Idaho Commercial Retail Market Profile....................... Error! Bookmark not defined.
Table A-24 Idaho Commercial Restaurant Market Profile ............... Error! Bookmark not defined.
Table A-25 Idaho Commercial Grocery Market Profile ................... Error! Bookmark not defined.
Table A-26 Idaho Commercial Health Market Profile ..................... Error! Bookmark not defined.
Table A-27 Idaho Commercial College Market Profile ................... Error! Bookmark not defined.
Table A-28 Idaho Commercial School Market Profile ..................... Error! Bookmark not defined.
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Table A-29 Idaho Commercial Lodging Market Profile ................... Error! Bookmark not defined.
Table A-30 Idaho Commercial Warehouse Market Profile .............. Error! Bookmark not defined.
Table A-31 Idaho Commercial Miscellaneous Market Profile .......... Error! Bookmark not defined.
Table A-32 Idaho Industrial Market Profile..................................... Error! Bookmark not defined.
Table D-1 Impacts of HB 1444 on EE Potential .......................... Error! Bookmark not defined.

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INTRODUCTION
Avista Corporation (Avista) engaged Applied Energy Group (AEG) to conduct a Conservation Potential Assessment (CPA). The CPA is a 20-year study, performed in accordance with Washington Initiative 937 (I-937), that provides data on conservation resources to support development of Avista’s 2022 Integrated Resource Plan (IRP). AEG first performed an electric CPA for Avista in 2013, and since then has performed both electric and gas CPAs for Avista’s planning cycles to date.
Notable udates to this study from prior CPAs include:
• The base-year for the analysis was brought forward from 2017 to 2019.
• 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. This 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 (RBSA II) supplemented the GenPOP survey to account for trends in the intervening years.
• For the commercial sector, analysis was performed for the major building types in the service territory. Results from the 2019 Commercial Building Stock Assessment (CBSA), including hospital and university data, provided useful information for this characterization.
• This study also incorporated changes to the list of energy conservation measures, as a result of research by the Regional Technical Forum (RTF). In particular, LED lamps continue to drop in price and provide a significant opportunity for savings even under market transformation assumptions by the RTF.
• Measure characterizations which previously relied on data from the Northwest Power Council’s Sventh Power Plan is now updated to the 2021 Power Plan, including measure data, adoption rates, and updated measure applicability.
• The study incorporates updated forecasting assumptions that line up with the most recent Avista load forecast.
Enhancements retained from the 2019 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 a Technical Achievable 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.
• Finally, this year’s study included an update to the 2019 assessment of demand-response potential, including analysis of residential programs as well as commercial and industrial (C&I), and options for both summer and winter demand reduction.
Compared to the 2019 Study, 10-year technical achievable potential has increased from 110.1 aMW to 150.3 aMW. This is a net effect of changes in the measure list, market transformation, and baseline growth.
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Abbreviations and Acronyms
Table 1-1 provides a list of abbreviations and acronyms used in this report, along with an explanation.
Table 1-1 Explanation of Abbreviations and Acronyms
Acronym Explanation
ACS American Community Survey
AEO Annual Energy Outlook forecast developed by EIA
AHAM Association of Home Appliance Manufacturers
AMI Advanced Metering Infrastructure
AMR Automated Meter Reading
Auto-DR Automated Demand Response
B/C Ratio Benefit to Cost Ratio
BEST AEG’s Building Energy Simulation Tool
C&I Commercial and Industrial
CAC Central Air Conditioning
CFL Compact fluorescent lamp
CPP Critical Peak Pricing
C&I Commercial and Industrial
DHW Domestic Hot Water
DLC Direct Load Control
DR Demand Response
DSM Demand Side Management
EE Energy Efficiency
EIA Energy Information Administration
EUL Estimated Useful Life
EUI Energy Usage Intensity
FERC Federal Energy Regulatory Commission
HH Household
HID High intensity discharge lamps
HVAC Heating Ventilation and Air Conditioning
ICAP Installed Capacity
IOU Investor Owned Utility
LED Light emitting diode lamp
LoadMAP AEG’s Load Management Analysis and Planning™ tool
LCOE Levelized cost of energy
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Acronym Explanation
MW Megawatt
NPV Net Present Value
O&M Operations and Maintenance
TRC Total Resource Cost test
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ANALYSIS APPROACH AND DATA DEVELOPMENT
This section describes the analysis approach taken for the study and the data sources used to develop the potential estimates.
Overview of Analysis Approach
To perform the potential analysis, AEG used a bottom-up approach following the major steps listed below. We describe these analysis steps in more detail throughout the remainder of this chapter.
1. Perform a market characterization to describe sector-level electricity use for the residential, commercial, and industrial sectors for the base year, 2019.
2. Develop a baseline projection of energy consumption and peak demand by sector, segment, and end use for 2019 through 2045.
3. Define and characterize several hundred conservation measures to be applied to all sectors, segments, and end uses.
4. Estimate technical and Technical Achievable Potential at the measure level in terms of energy and peak demand impacts from conservation measures for 2019-2045.
LoadMAP Model
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 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 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, and 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
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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.
• 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 (CHP) and distributed generation options and fuel switching.
Consistent with the segmentation scheme and the market profiles we describe below, the LoadMAP model provides projections of baseline energy use by sector, segment, end use, and technology for existing and new buildings. It also provides forecasts of total energy use and energy-efficiency savings associated with the various types of potential.1
Figure 2-1 LoadMAP Analysis Framework

1 The model computes energy and peak-demand forecasts for each type of potential for each end use as an intermediate calculation.
Annual-energy and peak-demand savings are calculated as the difference between the value in the baseline projection and the value in the potential forecast (e.g., the technical potential forecast).
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Definitions of Potential
In this study, the conservation potential estimates represent gross savings developed for two levels of potential: technical potential and Technical Achievable Potential. These levels are described below.
• Te chnical Potential is defined as the theoretical upper limit of conservation potential. It assumes that customers adopt all feasible measures regardless of their cost. At the time of existing equipment failure, customers replace their equipment with the efficient option available. In new construction, customers and developers also choose the most efficient equipment option.
o In new construction, customers and developers also 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 a theoretical construct and is provided primarily for planning and informational purposes.
• Te chnical Achievable Potential re fines Technical Potential by applying customer participation rates that account for market barriers, customer awareness and attitudes, program maturity, and other factors that may affect market penetration of DSM measures. We used achievability assumptions from the Council’s 2021 Power Plan, adjusted for Avista’s recent program accomplishments, as the customer adoption rates for this study. For the technical achievable case, ramp rates are applied to bewteen 85%-100% of the applicable market, per Council methodology. This achievability factor represents potential which can reasonably be acquired by all mechanisms available, regardless of how conservation is achieved. Thus, the market applicability assumptions utilized in this study include savings outside of utility programs.2
o Note that in the 2019 CPA, ramp rates used Sventh Plan methdology, which assumed a fixed 85% achievability for all measures. In the 2021 Power Plan, some measures have this limit increased.
o Details regarding the market adoption factors appear in Appendix B.
Market Characterization
The first step in the analysis approach is market characterization. In order 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. This 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. We rely primarily 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.

2 Council’s 7th Power Plan applicability assumptions reference an “Achievable Savings” report published August 1, 2007. http://www.nwcouncil.org/reports/2007/2007-13/
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Table 2-1 Overview of Avista Analysis Segmentation Scheme
Dimension Segmentation Variable Description
1 Sector Residential, commercial, industrial
2 Segment
Residential: single family, multifamily, manufactured home, low
income
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
Technologies such as lamp type, air conditioning equipment,
motors by application, etc.
6 Equipment efficiency levels
for new purchases
Baseline and higher-efficiency options as appropriate for each
technology

With the segmentation scheme defined, we then performed a high-level market characterization of electricity sales in the base year to allocate sales to each customer segment. We 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 2017 billing data. This information provided control totals at a sector level for calibrating the LoadMAP model 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. A market profile includes the following elements:
• Ma rket size is a representation of the number of customers in the segment. For the residential sector, it is number of households. In the commercial sector, it is floor space measured in square feet. For the industrial sector, it is overall electricity use.
• S a turations define the fraction of homes or square feet with the various technologies. (e.g., homes with electric space heating).
• U E C (unit energy consumption) or EUI (energy-use index) describes the amount of energy consumed in 2019 by a specific technology in buildings that have the technology. For electricity, UECs are expressed in kWh/household for the residential sector, and EUIs are expressed in kWh/square foot for the commercial sector.
• Annual E nergy Intensity for the residential sector represents the average energy use for the technology across all homes in 2019. It is computed as the product of the saturation and the UEC and is defined as kWh/household for electricity. For the commercial sector, intensity, computed as the product of the saturation and the EUI, represents the average use for the technology across all floor space in 2019.
• Annual U sage 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.
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• Pe ak De mand for each technology, summer peak and winter peak are calculated using peak fractions of annual energy use from AEG’s EnergyShape library and Avista system peak data.
o The market characterization results, and the market profiles are presented in Chapter 3.
Baseline Projection
The next step was to develop the baseline projection of annual electricity use and summer peak demand for 2019 through 2045 by customer segment and end use without new utility programs. The end-use projection includes the impacts of relatively certain codes and standards which will unfold over the study timeframe. All such mandates that were defined as of July 2020 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.
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
We also developed a baseline projection for summer and winter peak by applying the peak fractions from the energy market profiles to the annual energy forecast in each year.
We present the baseline-projection results for the system as a whole and for each sector in Chapter 4.
Washington HB 1444
While the 2019 CPA was completed before the impacts of HB-1444 could be incorporated, requiring a separate analysis to estimate that impact, this study’s foundational setup included assumptions of HB-1444s impact on the available market for energy efficiency measures in Washington.
Conservation Measure Analysis
This section describes the framework used to assess the savings, costs, and other attributes of conservation measures. These characteristics form the basis for measure-level cost-effectiveness analyses as well as for determining measure-level savings. For all measures, AEG assembled information to reflect equipment performance, incremental costs, and equipment lifetimes. We used this information, along with the Seventh Plan’s updated ramp rates to identify technical achievable measure potential.
Conservation Measures
Figure 2-2 outlines the framework for conservation measure analysis. The framework for assessing savings, costs, and other attributes of conservation measures involves identifying the list of measures to include in the analysis, determining their applicability to each market sector and segment, fully characterizing each measure, and calculating the levelized cost of energy ($/MWh). 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.
We compiled a robust list of conservation measures for each customer sector, drawing upon Avista’s measure database, the Regional Technical Forum (RTF), and the Seventh Plan deemed measures database,
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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 have instead calculated the levelized cost of energy (LCOE) for each measure evaluated. This value, expressed in dollars per first-year megawatt hour (MWh) saved, can be used by Avista’s IRP model to evaluate cost effectiveness. To calculate a measure’s LCOE, first-year measure costs, annual non-energy benefits, 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 (TRC) economic screen, the LCOE benefits have not been monetized. Therefore, these benefits are instead subtracted from the costs portion of the test. These benefits are not included in the Utility Cost Test (UCT) used in Idaho.

Figure 2-2 Approach for Conservation Measure Assessment

The selected measures are categorized into two types according to the LoadMAP taxonomy: equipment measures and non-equipment measures.
• E q uipment 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 13 unit and spans a broad spectrum up to a maximum efficiency of a SEER 21 unit. The Seventh Plan’s “Lost Opportunity” ramp rates are primarily applied to equipment measures.
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• N on -equipment measure s 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 air conditioner). An example would be a programmable thermostat that is pre-set to run heating and cooling systems only when people are home. Non-equipment measures can apply to more than one end use. For instance, addition of wall insulation will affect the energy use of both space heating and cooling. The Seventh Plan’s “Retrofit” ramp rates are primarily applied to no-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, changing setpoints)
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)
o Displacement measures (ceiling fan to reduce 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 and is presented in the appendix to this volume.
Once we assembled the list of conservation measures, the project team characterized measure savings, incremental cost, service life, and other performance factors, drawing upon data from the Avista measure database, the Seventh Power Plan, the RTF deemed measure workbooks, simulation modeling, and other well-vetted sources as required.
Representative Conservation Measure Data Inputs
To provide an example of the conservation measure data, Table 2-2 and Table 2-3 present examples of the detailed data inputs behind both equipment and non-equipment measures, respectively, for the case of residential CAC in single-family homes. Table 2-2 displays the various efficiency levels available as equipment measures, as well as the corresponding useful life, energy usage, and cost estimates. The columns labeled “On Market” and “Off Market” reflect equipment availability due to codes and standards or the entry of new products to the market. Note that in this example no standards come into play and therefore all options are available throughout the forecast.
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Table 2-2 Example Equipment Measures for Central AC – Single-Family Home
Efficiency Level Useful Life (yrs) Equipment Energy Usage (kWh/yr)
On Off
Cost Market Market
SEER 13.0 10 to 20 $2,097 1,383 2019 n/a
SEER 14.0 10 to 20 $2,505 1,284 2019 n/a
SEER 15.0 10 to 20 $2,913 1,199 2019 n/a
SEER 16.0 10 to 20 $3,321 1,124 2019 n/a
SEER 18.0 10 to 20 $4,140 999 2019 n/a
SEER 20.0 10 to 20 $4,955 899 2019 n/a

Table 2-3 lists some of the non-equipment measures applicable to a CAC in an existing single family home. LCOE values for all measures are evaluated based on the lifetime costs of the measure divided by the first-year savings. The total costs and savings are calculated for each year of the study and depend on the base year saturation of the measure, the applicability3 of the measure, and the savings as a percentage of the relevant energy end uses.
Table 2-3 Example Non-Equipment Measures – Single Family Home, Existing
End Use Measure Saturation
in 2019 Applicability Lifetime
(yrs)
Measure
Installed Cost
Energy
Savings (%)
Cooling Insulation - Ceiling Installation 0% 10% 45 $2,084 21.8%
Cooling Insulation - Wall Cavity Installation 0% 10% 45 $4,374 3.5%
Cooling Windows - High Efficiency/ENERGY STAR 0% 95% 45 $4,421 7.1%
Cooling Thermostat – Connected 14% 70% 5 $265.00 6.0%

Table 2-4 summarizes the number of measures evaluated for each segment within each sector.
Table 2-4 Number of Measures Evaluated
Sector Total Measures Permutations w/ Permutations w/
Total Measures Evaluated 329 658 3,786

3 The applicability factors take into account whether the measure is applicable to a particular building type and whether it is feasible to install the measure. For instance, attic fans are not applicable to homes where there is insufficient space in the attic or there is no attic at all.

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Conservation Potential
The approach we used for this study to calculate the conservation potential adheres to the approaches and conventions outlined in the National Action Plan for Energy-Efficiency (NAPEE) Guide for Conducting Potential Studies (November 2007).4 The NAPEE Guide represents the most credible and comprehensive industry practice for specifying conservation potential. As described in Chapter 2, two types of potential were developed as part of this effort: Technical Potential and Technical Achievable Potential.
• Te chnical potential is a theoretical construct that assumes the highest efficiency measures that are technically feasible to install are adopted by customers, regardless of cost or customer preferences. Thus, determining the technical potential is relatively straightforward. LoadMAP “chooses” the efficient equipment options for each technology at the time of equipment replacement. In addition, it installs all relevant non-equipment measures for each technology to calculate savings. LoadMAP applies the savings due to the non-equipment measures one-by-one to avoid double counting of savings. The measures are evaluated in order of their LCOE ratio, with the measure with the lowest LCOE values (most likely to be cost effective) applied first. Each time a measure is applied, the baseline energy use for the end use is reduced and the percentage savings for the next measure is applied to the revised (lower) usage.
• Te chnical Achievable Potential refines Technical Potential by applying market adoption rates for each measure that estimate the percentage of customers who would be likely to select each measure, given consumer preferences (partially a function of incentive levels), retail energy rates, imperfect information, and real market barriers and conditions. These barriers tend to vary, depending on the customer sector, local energy market conditions, and other, hard-to-quantify factors. In addition to utility-sponsored programs, alternative acquisition methods, such as improved codes and standards and market transformation, can be used to capture portions of these resources, and are included within the Technical Achievable Potential, per 2021 Power Plan methodology.
The calculation of Technical Potential is a straightforward algorithm. To develop estimates for Technical Achievable Potential, we develop market adoption rates for each measure that specify the percentage of customers that will select the highest–efficiency economic option. With the beginning of a new power plan, technical achievable potential aligns with ramp assignments from the 2021 Power Plan. Over time, measure adoption increases from the starting point up to 85% or more, to model increasing market acceptance and program improvements. For measures within the 2021 Power Plan, the Council’s prescribed ramp rates were used. For measures outside the 2021 Plan, AEG assigned ramp rates comparable to similar measures within the 2021 Plan. The market adoption rates for each measure appear in Appendix B.
Results of all the potentials analysis are presented in Chapter 5.
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 data, and well-vetted national or other regional secondary sources.
Data Sources
The data sources are organized into the following categories:

4 National Action Plan for Energy Efficiency (2007). National Action Plan for Energy Efficiency Vision for 2025: Developing a Framework for Change. www.epa.gov/eeactionplan.
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• Avista data
• Northwest Energy Efficiency Alliance data
• Northwest Power and Conservation Council data
• AEG’s databases and analysis tools
• Other secondary data and reports
Avista Data
Our highest priority data sources for this study were those that were specific to Avista.
• Avista customer data : Avista provided billing data for 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.
• E conomic information: Avista Power provided a discount rate and line loss factor. Avoided costs were not provided due to the economic screen being moved to the IRP model.
• Avista program d ata: Avista provided information about past and current programs, including program descriptions, goals, and achievements to date.
Northwest Energy Efficiency Alliance Data
The Northwest Energy Efficiency Alliance conducts research on an ongoing basis for the Northwest region. The following studies were particularly useful for this study:
• N orthwest E nergy E fficiency Alliance, Residential Building S tock Assessment II, Single-Family Homes Report 2016-2017, https://neea.org/img/uploads/Residential-Building-Stock-Assessment-II-Single-Family-Homes-Report-2016-2017.pdf
• N orthwest E nergy E fficiency Alliance, R esidential Building S tock Assessment II, Manufactured Homes Report 2016-2017, https://neea.org/img/uploads/Residential-Building-Stock-Assessment-II-Manufactured-Homes-Report-2016-2017.pdf
• N orthwest E nergy E fficiency Alliance, R esidential Building S tock Assessment II, Multifamily Buildings Report 2016-2017, https://neea.org/img/documents/Residential-Building-Stock-Assessment-II-Multifamily-Homes-Report-2016-2017.pdf
• N orthwest E nergy E fficiency Alliance, 2019 Commercial Building Stock Assessment, May 21, 2020 https://neea.org/resources/cbsa-4-2019-final-report
• N orthwest E ne rgy E fficiency Alliance, 2014 Ind ustrial Fa cilities S ite Assessment, December 29, 2014, http://neea.org/docs/default-source/reports/2014-industrial-facilities-stock-assessment-final-report.pdf?sfvrsn=6
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 with AEG’s data sources to fill in any gaps.
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• R egional Technical Forum Deemed Measures. The NWPCC Regional Technical Forum maintains databases of deemed measure savings data, available at http://www.nwcouncil.org/energy/rtf/measures/Default.asp .
• N orthwest Power a nd Conservation Council 2021 Power Pla n Conservation Supply Cur ve Workbooks. To develop its 2021 Power Plan, the Council used workbooks with detailed information about measures, available at https://nwcouncil.box.com/s/u0dgjxkoxoj2tttym81uka3wrjcy6bo6
• N orthwest Power and Conservation Council, 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. Generalized Least Square (GLS) versions of these load shapes are available at https://nwcouncil.app.box.com/s/gacr21z8i89hh8ppk11rdzgm6fz4xlz3
AEG Data
AEG maintains several databases and modeling tools that we use for forecasting and potential studies. Relevant data from these tools has been incorporated into the analysis and deliverables for this study.
• AE G E nergy Ma rket Profiles: For more than 10 years, AEG staff has maintained profiles of end-use consumption for the residential, commercial, and industrial sectors. These profiles include market size, fuel shares, unit consumption estimates, and annual energy use by fuel (electricity and natural gas), customer segment and end use for 10 regions in the U.S. The Energy Information Administration surveys (RECS, CBECS and MECS) as well as state-level statistics and local customer research provide the foundation for these regional profiles.
• Building E nergy S imulation 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.
• AE G’s EnergyShape ™: AEG’s load shape database was used in addition to the Council’s load shape database for comparative purposes. This database of load shapes includes the following:
o Residential – electric load shapes for ten regions, three housing types, 13 end uses
o Commercial – electric load shapes for nine regions, 54 building types, ten end uses
o Industrial – electric load shapes, whole facility only, 19 2-digit SIC codes, as well as various 3-digit and 4-digit SIC codes
• AE G’s Database of Energy E fficiency Measures (DEEM): AEG maintains an extensive database of measure data for our studies. Our database draws 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
• R e cent studies. AEG has conducted numerous studies of EE potential in the last five years. We checked our input assumptions and analysis results against the results from these other studies, which include Tacoma Power, Idaho Power, PacifiCorp, Ameren Missouri, Vectren Energy, Indianapolis Power & Light, Tennessee Valley Authority, Ameren Missouri, Ameren Illinois, and Seattle City Light. In
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addition, we used the information about impacts of building codes and appliance standards from recent reports for the Edison Electric Institute5.
Other Secondary Data and Reports
Finally, a variety of secondary data sources and reports were used for this study. The main sources are identified below.
• Annual E nergy Outlook. The Annual Energy Outlook (AEO), conducted each year by the U.S. Energy Information Administration (EIA), presents yearly projections and analysis of energy topics. For this study, we used data from the 2019 AEO.
• Local Weather Data: Weather from NOAA’s National Climatic Data Center for Spokane, WA was used as the basis for building simulations.
• E PRI End-Use Models (REEPS and COMMEND). These models provide the elasticities we apply to electricity prices, household income, home size and heating and cooling.
• Da tabase for E nergy E fficient R esources (DEER). The California Energy Commission and California Public Utilities Commission (CPUC) sponsor this database, which is designed to provide well-documented estimates of energy and peak demand savings values, measure costs, and effective useful life (EUL) for the state of California. We used the DEER database to cross check the measure savings we developed using BEST and DEEM.
• Other relevant regional sources: These include reports from the Consortium for Energy Efficiency (CEE), the Environmental Protection Agency (EPA), and the American Council for an Energy-Efficient Economy (ACEEE).
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 the residential, commercial and industrial sectors, we used Avista billing data and customer surveys to estimate energy use.
• For the residential sector, Avista estimated the numbers of customers and the average energy use per customer for each of the three segments, based on its GenPOP survey, matched to billing data for surveyed customers. AEG compared the resulting segmentation with data from the American Community Survey (ACS) regarding housing types and income and found that the Avista segmentation corresponded well with the ACS data. (See Chapter 3 for additional details.)
• To segment the commercial and industrial segments, we relied upon the allocation from the previous energy efficiency potential study. For the previous study, customers and sales were allocated to
o 5 AEG staff has prepared three white papers on the topic of factors that affect U.S. electricity consumption, including appliance standards and building codes. Links to all three white papers are provided:
http://www.edisonfoundation.net/IEE/Documents/IEE_RohmundApplianceStandardsEfficiencyCodes1209.pdf
o http://www.edisonfoundation.net/iee/Documents/IEE_CodesandStandardsAssessment_2010-2025_UPDATE.pdf.
o http://www.edisonfoundation.net/iee/Documents/IEE_FactorsAffectingUSElecConsumption_Final.pdf

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building type based on SIC codes, with some adjustments between the commercial and industrial sectors to better group energy use by facility type and predominate end uses. (See Chapter 3 for additional details.)
Data Application for Market Profiles
The specific data elements for the market profiles, together with the key data sources, are shown in Table 2-5. To develop the market profiles for each segment, we did the following:
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, NEEA’s CBSA, NEEA’s IFSA, and AEG’s Energy Market Profiles database to develop existing appliance saturations, appliance and equipment characteristics, and building characteristics.
3. Ensured calibration to control totals 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.

Data Application for Baseline Projection
Table 2-5 summarizes the LoadMAP 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 2-5 Data Applied for the Market Profiles
Model Inputs Description Key Sources
Market size Base-year residential dwellings, commercial
floor space, and industrial employment
Avista billing data
Avista GenPOP Survey
NEEA RBSA and CBSA
AEO 2019
Annual intensity
Residential: Annual use per household
Commercial: Annual use per square foot
Industrial: Annual use per employee
Avista billing data
AEG’s Energy Market Profiles
NEEA RBSA and CBSA
AEO 2019
Other recent studies
Appliance/equipment
saturations
Fraction of dwellings with an
appliance/technology
Percentage of C&I floor space/employment
with equipment/technology
Avista GenPOP Survey
NEEA RBSA and CBSA
AEG’s Energy Market Profiles
UEC/EUI for each end-
use technology
UEC: Annual electricity use in homes and
buildings that have the technology
EUI: Annual electricity use per square
foot/employee for a technology in floor space
that has the technology
NWPCC RTF and Seventh Plan and
RTF
HVAC uses: BEST simulations using
prototypes developed for Idaho
Engineering analysis
DEEM
Recent AEG studies
Appliance/equipment
age distribution Age distribution for each technology
RTF and NWPCC Seventh Plan data
NEEA regional survey data
Utility saturation surveys
Recent AEG studies
Efficiency options for
each technology
List of available efficiency options and annual
energy use for each technology
AEG DEEM
AEO 2019
DEER
RTF and NWPCC 2021 Plan data
Previous studies
Peak factors Share of technology energy use that occurs
during the peak hour EnergyShape database

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Table 2-6 Data Needs for the Baseline Projection and Potentials Estimation in LoadMAP
Model Inputs Description Key Sources
Customer growth forecasts Forecasts of new construction in
residential and C&I sectors
Avista load forecast
AEO 2019 economic growth forecast
Equipment purchase shares
for baseline projection
For each equipment/technology, purchase
shares for each efficiency level; specified
separately for existing equipment
replacement and new construction
Shipments data from AEO and
ENERGY STAR
AEO 2019 regional forecast
assumptions6
Appliance/efficiency standards
analysis
Avista program results and
evaluation reports
Utilization model
parameters
Price elasticities, elasticities for other
variables (income, weather)
EPRI’s REEPS and COMMEND
models
AEO 2019

In addition, we implemented assumptions for known future equipment standards as of September 2018, as shown in Table 2-6, Table 2-7 and Table 2-8. The assumptions tables here extend through 2025, after which all standards are assumed to hold steady.

6 We developed baseline purchase decisions using the Energy Information Agency’s Annual Energy Outlook report (2016), which utilizes the National Energy Modeling System (NEMS) to produce a self-consistent supply and demand economic model. We calibrated equipment
purchase options to match manufacturer shipment data for recent years and then held values constant for the study period. This removes any effects of naturally occurring conservation or effects of future EE programs that may be embedded in the AEO forecasts.
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Table 2-7 Residential Electric Equipment Standards7
End Use Technology 2019 2020 2021 2022 2023 2024 2025
Cooling Central AC SEER 13.0
Room AC EER 10.8
Air-Source Heat Pump SEER 13.0 / HSPF 8.2 SEER 14.0 / HSPF 9.0 Heating
EF 0.95 (<=55 gallons)
EF 2.0 (Heat Pump Water Heater)
Lighting General Service Advanced Incandescent
(~20 lumens/watt) Advanced Incandescent (~45 lumens/watt)

25% more efficient than the 1997 Final Rule (62 FR 23102) Freezer
Clothes Dryer 3.73 Combined EF

7 The assumptions tables here extend through 2025, after which all standards are assumed to hold steady.
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Table 2-8 Commercial Electric Equipment Standards8

Cooling
Cooling/ Heating
Heat Pump
Lighting
General Service
Refrigeration

8 The assumptions tables here extend through 2025, after which all standards are assumed to hold steady.
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Table 2-9 Industrial Electric Equipment Standards9

Cooling
Cooling/ Heating
Heat Pump
Lighting
General Service

9 The assumptions tables here extend through 2025, after which all standards are assumed to hold steady.
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Conservation Measure Data Application
Table 2-9 details the energy-efficiency data inputs to the LoadMAP model. It describes each input and identifies the key sources used in the Avista analysis.
Table 2-10 Data Needs for the Measure Characteristics in LoadMAP
Model Inputs Description Key Sources
Energy Impacts
The annual reduction in consumption attributable to
each specific measure. Savings were developed as a
percentage of the energy end use that the measure
affects.
Avista measure data
NWPCC workbooks, RTF
NWPCC Seventh Plan
conservation workbooks
BEST
AEG DEEM
AEO 2019
DEER
Other secondary sources
Peak Demand Impacts
Savings during the peak demand periods are specified
for each electric measure. These impacts relate to the
energy savings and depend on the extent to which
each measure is coincident with the system peak.
Avista measure data
BEST
AEG DEEM
EnergyShape
Costs
Equipment Measures: Includes the full cost of
purchasing and installing the equipment on a per-household, per-square-foot, per employee or per
service point basis for the residential, commercial,
and industrial sectors, respectively.
Non-equipment measures: Existing buildings – full
installed cost. New Construction - the costs may be
either the full cost of the measure, or as appropriate, it may be the incremental cost of upgrading from a
standard level to a higher efficiency level.
Avista measure data
NWPCC workbooks, RTF
NWPCC 2021 Plan
conservation workbooks
AEG DEEM
AEO 2019
DEER
RS Means
Other secondary sources
Measure Lifetimes
Estimates derived from the technical data and
secondary data sources that support the measure
demand and energy savings analysis.
Avista measure data
NWPCC workbooks, RTF
NWPCC 2021 Plan
conservation workbooksAEG
DEEM
AEO 2019
DEER
Other secondary sources
Applicability
Estimate of the percentage of dwellings in the
residential sector, square feet in the commercial
sector, or employees in the industrial sector where the measure is applicable and where it is technically
feasible to implement.
Avista measure data
NWPCC workbooks, RTF
NWPCC 2021 Plan
conservation workbooks
AEG DEEM
DEER
Other secondary sources
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On Market and Off
Market Availability
Expressed as years for equipment measures to reflect
when the equipment technology is available or no
longer available in the market.
AEG appliance standards and
building codes analysis

Data Application for Technical Achievable Potential
To estimate Technical Achievable Potential, two sets of parameters are needed to represent customer decision making behavior with respect to energy-efficiency choices.
• Te chnical d iffusion 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 2019 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.
• Ad option rate s . Customer adoption rates or take rates are applied to technical potential to estimate Technical Achievable Potential. For equipment measures, the Council’s “Lost Opportunity” ramp rates were applied to technical potential with a maximum achievability of 85%-100% depending on the measure. For non-equipment measures, the Council’s “Retrofit” ramp rates have already been applied to calculate technical diffusion. In this case, we multiply each of these by 85% (for most measures) to calculate Technical Achievable Potential. Adoption rates are presented in Appendix B.

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MARKET CHARACTERIZATION AND MARKET PROFILES
In this section, we describe how customers in the Avista service territory use electricity in the base year of the study, 2019. It begins with a high-level summary of energy use across all sectors and then delves into each sector in more detail.
Energy Use Summary
Total electricity use for the residential, commercial, and industrial sectors for Avista in 2019 was 7,794 GWh; 5,205 GWh (WA) and 2,589 GWh (ID). As shown in the tables below, in both states the residential sector accounts for nearly 50% of annual energy use, followed by commercial at around 40% of annual energy use. In terms of winter peak demand, the total system peak in 2019 was 1,530 MW: 1,060 (WA) and 470 MW (ID). In both states, the residential sector contributes the most to the winter peak.
Figure 3-1 Sector-Level Electricity Use in Base Year 2019, Washington

Table 3-1 Avista Sector Control Totals (2019), Washington
Sector
Total 5,205 100% 1,060 100%

Residential
49%
Commerci
al
42%
Industrial
9%
Annual Use (GWh)
Residential
45%
Commerci
al
40%
Industrial
15%
Winter Peak (MW)
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Figure 3-2 Sector-Level Electricity Use in Base Year 2019, Idaho

Table 3-2 Avista Sector Control Totals (2019), Idaho
Sector
Total 2,589 100% 470 100%
Residential Sector
The total number of households and electricity sales for the service territory were obtained from Avista’s customer database. In 2019, there were 229,171 households in the state of Washington that used a total of 2,539 GWh with winter peak demand of 473 MW. Average use per customer (or household) at 11,080 kWh is about average compared to other regions of the country. We allocated these totals into four residential segments and the values are shown in Table 3-3.
Table 3-4 shows the total number of households and electricity sales in the state of Idaho. In 2019, there were 116,114 households that used a total of 1,236 GWh with winter peak demand of 223 MW. Average use per customer (or household) was 10,643 kWh.
Table 3-3 Residential Sector Control Totals (2019), Washington
Segment Number of
Customers Electricity Use % of Annual Use/Customer Winter Peak
Total 229,171 2,539 100% 11,080 473

Residential48%
Commercial39%
Industrial
13%
Annual Use (GWh)
Residential
48%
Commercial38%
Industrial
14%
Winter Peak (MW)
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Table 3-4 Residential Sector Control Totals (2019), Idaho
Segment Number of
Customers
Electricity
Use
% of
Annual
Annual Use/Customer
(kWh/HH)
Winter
Peak
Total 116,114 1,236 100% 10,643 223

As we describe in the previous chapter, the market profiles provide the foundation for development of the baseline projection and the potential estimates. The average market profile for the residential sector is presented in Table 3-5 (WA) and Table 3-6 (ID). Segment-specific market profiles are presented in Appendix A.
Figure 3-3 (WA) and Figure 3-4 (ID) show the distribution of annual electricity use by end use for all customers. Two main electricity end uses —appliances and space heating— account for approximately 55% of total use. Appliances include refrigerators, freezers, stoves, clothes washers, clothes dryers, dishwashers, and microwaves. The remainder of the energy falls into the water heating, lighting, cooling, electronics, and the miscellaneous category – which is comprised of furnace fans, pool pumps, electric vehicles, and other “plug” loads (all other usage not covered by those listed in Table 3-5 and Table 3-6 such as hair dryers, power tools, coffee makers, etc.).
The charts also show estimates of winter peak demand by end use. As expected, heating is the largest contributor to winter peak demand, followed by appliances, lighting, and water heating.
Figure 3-5 (WA) and Figure 3-6 (ID) present the electricity intensities by end use and housing type. Single family homes have the highest use per customer at 11,699 kWh/year (WA) and 11,158 kWh/year (ID).
Figure 3-3 Residential Electricity Use and Winter Peak Demand by End Use (2019), Washington

Cooling
7%
Space Heating38%
Water Heating17%
Interior Lighting
7%
Exterior Lighting1%
Appliances16%
Electronics
7%
Miscellaneous7%
Annual Use by End Use
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Figure 3-4 Residential Electricity Use and Winter Peak Demand by End Use (2019), Idaho

Space Heating
73%
Water Heating
11%
Interior Lighting4%
Exterior Lighting
1%
Appliances
4%
Electronics2%Miscellaneous
5%
Winter Peak Demand
Cooling6%
Space Heating37%
Water Heating13%Interior Lighting8%
Exterior Lighting2%
Appliances18%
Electronics7%
Miscellaneous9%
Annual Use by End Use
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Figure 3-5 Residential Intensity by End Use and Segment (Annual kWh/HH, 2019), Washington

Cooling0%
Space Heating72%
Water Heating
9%
Interior Lighting
5%
Exterior Lighting1%
Appliances5%
Electronics
2%
Miscellaneous
6%
Winter Peak Demand
0 2000 4000 6000 8000 10000 12000 14000
Single Family
Multi-Family
Mobile Home
Low Income
Total
kWh per Household
Cooling
Space Heating
Water Heating
Interior Lighting
Exterior Lighting
Appliances
Electronics
Miscellaneous
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Figure 3-6 Residential Intensity by End Use and Segment (Annual kWh/HH, 2019), Idaho

0 2000 4000 6000 8000 10000 12000 14000
Single Family
Multi-Family
Mobile Home
Low Income
Total
kWh per Household
Cooling
Space Heating
Water Heating
Interior Lighting
Exterior Lighting
Appliances
Electronics
Miscellaneous
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Table 3-5 Average Market Profile for the Residential Sector, 2019, Washington
End Use Technology Saturation
Total 11,080 2,539,174

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Table 3-6 Average Market Profile for the Residential Sector, 2019, Idaho
End Use Technology Saturation
Total 10,643 1,235,752

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Commercial Sector
The total electric energy consumed by commercial customers in Avista’s service area in 2017 was 2,166 GWh (WA) and 1,007 GWh (ID). 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, we infer floor space which is the unit of analysis in LoadMAP for the commercial sector. The values are shown in Table 3-7 (WA) and Table 3-8 (ID). The average building intensities by segment are based on regional information from the CBSA, therefore the intensity is the same both states. However, due to the different mix of building types, overall end use mix is different as shown in Figure 3-9 and Figure 3-10.
Table 3-7 Commercial Sector Control Totals (2019), Washington
Segment Electricity Sales % of Total Intensity (GWh) Usage
Small Office 192 9% 15.6
Large Office 507 23% 17.3
Restaurant 113 5% 40.9
Retail 278 13% 12.2
Grocery 193 9% 43.4
College 114 5% 16.2
School 146 7% 9.1
Health 119 5% 23.3
Lodging 86 4% 12.2
Warehouse 95 4% 4.7
Miscellaneous 324 15% 10.3
Total 2,166 100% 13.7

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Table 3-8 Commercial Sector Control Totals (2019), Idaho
Segment Intensity
Total 1,007 100% 12.7

Figure 3-7 (WA) and Figure 3-8 (ID) show the distribution of annual electricity consumption and summer peak demand by end use across all commercial buildings. Electric usage is dominated by lighting and ventilation, which comprise almost 44% 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.
Figure 3-9 (WA) and Figure 3-10 (ID) presents the electricity usage in GWh by end use and segment. In Washington, Large offices, retail, and miscellaneous buildings use the most electricity in the service territory. For Idaho, Large and Small Offices are more balanced in terms of total consumption. 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 3-7 Commercial Electricity Use and Winter Peak Demand by End Use (2019), Washington

Cooling
11%
Space Heating5%
Ventilation
18%
Water Heating2%
Interior Lighting20%Exterior Lighting6%
Refrigeration
11%
Food Preparation3%
Office Equipment10%
Miscellaneous
14%
Annual Use by End Use
Cooling
3%Space Heating12%
Ventilation
16%
Water Heating
4%Interior Lighting
24%Exterior Lighting2%
Refrigeration
9%
Food Preparation4%
Office Equipment
10%
Miscellaneous16%
Winter Peak Demand
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Figure 3-8 Commercial Electricity Use and Winter Peak Demand by End Use (2019), Idaho

Cooling11%
Space Heating
7%
Ventilation18%
Water Heating
3%
Interior Lighting21%Exterior Lighting6%
Refrigeration6%
Food Preparation2%
Office Equipment
10%
Miscellaneous16%
Annual Use by End Use
Cooling
3%
Space Heating
16%
Ventilation
16%
Water Heating
4%
Interior Lighting24%Exterior Lighting2%
Refrigeration
5%
Food Preparation
2%
Office Equipment
10%
Miscellaneous18%
Winter Peak Demand
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Figure 3-9 Commercial Electricity Usage by End Use Segment (GWh, 2019), Washington

Figure 3-10 Commercial Electricity Usage by End Use Segment (GWh, 2019), Idaho

Table 3-9 (WA) and Table 3-10 (ID) show the average market profile for electricity of the commercial sector as a whole, representing a composite of all segments and buildings. Market profiles for each segment are presented in the appendix to this volume.

0
100
200
300
400
500
600
Cooling
Space Heating
Ventilation
Water Heating
Interior Lighting
Exterior Lighting
Refrigeration
Food Preparation
Office Equipment
Miscellaneous
0
50
100
150
200
250
Cooling
Space Heating
Ventilation
Water Heating
Interior Lighting
Exterior Lighting
Refrigeration
Food Preparation
Office Equipment
Miscellaneous
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Table 3-9 Average Electric Market Profile for the Commercial Sector, 2019, Washington
End Use Technology Saturation
Total 13.17 2,166.0
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Table 3-10 Average Electric Market Profile for the Commercial Sector, 2019, Idaho
End Use Technology Saturation
Total 11.75 143.0
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Industrial Sector
The total electricity used in 2019 by Avista’s industrial customers was 846 GWh; 500 GWh (WA) and 346 GWh (ID). Avista billing data and load forecast, NEEA’s IFSA, and secondary sources were used to develop estimates of energy intensity (annual kWh/employee). Using the electricity use and intensity estimates, we infer the number of employees which is the unit of analysis in LoadMAP for the industrial sector. These are shown in Table 3-11.
Table 3-11 Industrial Sector Control Totals (2019)
State
Electricity Sales Intensity Winter Peak
(GWh) (Annual kWh/employee) (MW)
Washington 500 42,527 164
Idaho 346 29,394 68

Figure 3-12 shows the distribution of annual electricity consumption and summer peak demand by end use for all industrial customers. Motors are the largest overall end use for the industrial sector, accounting for 47% of energy use. Note that this end use includes a wide range of industrial equipment, such as air compressors and refrigeration compressors, pumps, conveyor motors, and fans. The process end use accounts for 25% of annual energy use, which includes heating, cooling, refrigeration, and electro-chemical processes. Lighting is the next highest, followed by cooling, miscellaneous, heating and ventilation.
Table 3-12 and Table 3-13 show the composite market profile for the industrial sector.

Figure 3-11 Industrial Electricity Use and Winter Peak Demand by End Use (2019), All Industries, WA

Cooling4%Space Heating2%Ventilation11%
Interior Lighting9%
Exterior Lighting
2%
Motors47%
Process
25%
Miscellaneous
0%
Annual Use by End Use
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Figure 3-12 Industrial Electricity Use and Winter Peak Demand by End Use (2019), All Industries, ID

Cooling0%
Space Heating3%
Ventilation8%
Interior Lighting9%
Exterior Lighting1%
Motors
52%
Process27%
Miscellaneous0%
Winter Peak Demand
Cooling
4%Space Heating
2%
Ventilation
11%Interior Lighting9%
Exterior Lighting
2%
Motors47%
Process
20%
Miscellaneous
5%
Annual Use by End Use
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Cooling0%
Space Heating
3%Ventilation8%
Interior Lighting9%
Exterior Lighting0%
Motors
52%
Process22%
Miscellaneous
6%
Winter Peak Demand
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Table 3-12 Average Electric Market Profile for the Industrial Sector, 2019, Washington
End Use Technology Saturation EUI Intensity Usage
Cooling Air-Cooled Chiller 2.5% 10,819.85 270.50 3.2
Cooling Air-Source Heat Pump 1.7% 10,077.53 170.41 2.0
Heating Electric Room Heat 2.6% 15,324.53 394.31 4.6
Heating Geothermal Heat Pump 0.0% 1.00 0.00 0.0
Interior Lighting High-Bay Lighting 100.0% 1,912.71 1,912.71 22.5
Exterior Lighting Area Lighting 100.0% 254.16 254.16 3.0
Motors Pumps 100.0% 4,252.64 4,252.64 50.0
Motors Material Handling 100.0% 8,505.29 8,505.29 100.0
Process Process Cooling 100.0% 1,275.79 1,275.79 15.0
Process Process Electrochemical 100.0% 2,625.61 2,625.61 30.9
Total 42,526.45 500.1

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Table 3-13 Average Electric Market Profile for the Industrial Sector, 2019, Idaho
End Use Technology Saturation EUI Intensity Usage
Cooling Air-Cooled Chiller 2.5% 15,505.86 387.65 2.2
Cooling Air-Source Heat Pump 1.7% 14,442.05 244.21 1.4
Heating Electric Room Heat 2.6% 21,961.48 565.09 3.2
Heating Geothermal Heat Pump 0.0% 1.00 0.00 0.0
Interior Lighting High-Bay Lighting 100.0% 2,741.09 2,741.09 15.5
Exterior Lighting Area Lighting 100.0% 364.23 364.23 2.1
Motors Pumps 100.0% 6,094.44 6,094.44 34.6
Motors Material Handling 100.0% 12,188.87 12,188.87 69.1
Process Process Cooling 100.0% 1,828.33 1,828.33 10.4
Process Process Electrochemical 100.0% 426.33 426.33 2.4
Total 60,944.36 345.6

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BASELINE PROJECTION
Prior to developing estimates of energy-efficiency potential, we developed a baseline end-use projection to quantify what the consumption is likely to be in the future and in absence of any future conservation 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 baseline projection incorporates assumptions about:
• Customer population and economic growth
• Appliance/equipment standards and building codes already mandated (see Chapter 2)
• Forecasts of future electricity prices and other drivers of consumption
• Trends in fuel shares and appliance saturations and assumptions about miscellaneous electricity growth
Although it aligns closely with it, the baseline projection is not Avista’s official load forecast. Rather it was developed to serve as the metric against which EE potentials are measured. This chapter presents the baseline projections we developed for this study. Below, we present the baseline projections for each sector and state, which include projections of annual use in GWh and summer peak demand in MW. We also present a summary across all sectors.
Please note that the base-year for the study is 2019. Annual energy use and summer peak demand values for 2019 reflect weather-normalized values. In future years, energy use and peak demand reflect normal weather, as defined by Avista.
Residential Sector
Annual Use
Table 4-1 (WA) and Table 4-2 (ID) present the baseline projection for electricity at the end-use level for the residential sector as a whole. Overall in Washington, residential use increases from 2,539 GWh in 2019 to 2,976 GWh in 2041, an increase of 17%. Residential use in Idaho increases from 1,236 GWh in 2019 to 1,513 GWh in 2041, an increase of 22%. This reflects a substantial customer growth forecast in both states. Figure 4-1 (WA) and Figure 4-3 (ID) display the graphical representation of the baseline projection.
Figure 4-2 (WA) and Figure 4-4 (ID) present the baseline projection of annual electricity use per household. Most noticeable is that lighting use decreases throughout the time period – this is the combined effect of the RTF market baseline assumption in both states, and is further enhanced in Washington by state lighting standards in effect from 2020 forward.

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Table 4-1 Residential Baseline Sales Projection by End Use (GWh), Washington
End Use 2019 2022 2023 2026 2031 2041 % Change
('19-'41)
Cooling 187 202 205 218 247 350 87%
Space Heating 956 924 926 932 940 958 0%
Water Heating 420 408 405 398 387 369 -12%
Interior Lighting 177 158 149 118 93 82 -54%
Exterior Lighting 34 28 26 20 16 13 -61%
Appliances 414 425 429 442 463 498 20%
Electronics 170 185 190 206 234 294 73%
Miscellaneous 187 202 207 226 269 461 146%
Generation -5 -7 -8 -11 -18 -48 825%
Total 2,539 2,525 2,529 2,548 2,631 2,976 17%

Figure 4-1 Residential Baseline Projection by End Use (GWh), Washington

0
500
1000
1500
2000
2500
3000
3500
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Figure 4-2 Residential Baseline Projection by End Use – Annual Use per Household, Washington

Table 4-2 Residential Baseline Sales Projection by End Use (GWh), Idaho
End Use 2019 2022 2023 2026 2031 2041 % Change
('19-'41)
Cooling 77 88 91 102 125 185 142%
Space Heating 457 447 449 455 460 469 2%
Water Heating 157 155 155 153 150 143 -9%
Interior Lighting 106 101 95 73 55 48 -55%
Exterior Lighting 26 20 18 12 9 7 -75%
Appliances 220 229 232 241 253 271 23%
Electronics 85 92 94 101 110 131 54%
Miscellaneous 110 122 126 141 171 285 160%
Generation -3 -4 -4 -6 -9 -25 848%
Total 1,236 1,250 1,256 1,272 1,322 1,513 22%

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Figure 4-3 Residential Baseline Projection by End Use (GWh), Idaho

Figure 4-4 Residential Baseline Sales Projection by End Use – Annual Use per Household, Idaho

Commercial Sector Baseline Projections
Annual Use
In Washington, annual electricity use in the commercial sector grows during the overall forecast horizon, starting at 2,166 GWh in 2019, and increasing to 2,811 in 2041, an increase of 30%. In Idaho, annual
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electricity use grows from 1,007 GWh in 2017 to 1,112 GWh in 2041, an increase of 10%. The tables and graphs below present the baseline projection at the end-use level for the commercial sector as a whole.
Table 4-3 Commercial Baseline Sales Projection by End Use (GWh), Washington
End Use 2019 2022 2023 2026 2031 2041
Cooling 236 250 250 251 254 265 12%
Space Heating 114 112 112 115 120 130 14%
Ventilation 383 379 379 374 365 359 -6%
Water Heating 54 55 55 56 58 63 18%
Interior Lighting 434 417 411 395 388 404 -7%
Exterior Lighting 127 118 115 108 105 107 -16%
Refrigeration 233 243 247 260 283 346 48%
Food Preparation 66 69 70 72 81 106 60%
Miscellaneous 304 341 355 402 492 733 141%
Total 2,166 2,201 2,211 2,252 2,385 2,811 30%
Table 4-4 Commercial Baseline Sales Projection by End Use (GWh), Idaho
End Use 2019 2022 2023 2026 2031 2041
Cooling 114 122 122 124 126 134 18%
Space Heating 68 68 68 70 74 82 20%
Ventilation 185 185 185 184 181 182 -2%
Water Heating 29 30 30 31 32 36 24%
Exterior Lighting 58 56 55 51 49 51 -13%
Food Preparation 23 24 24 25 26 29 25%
Miscellaneous 160 165 167 172 181 201 26%
Total 1,007 1,022 1,023 1,022 1,041 1,112 10%

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Figure 4-5 Commercial Baseline Projection by End Use, Washington

Figure 4-6 Commercial Baseline Projection by End Use, Idaho

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Industrial Sector Baseline Projections
Annual Use
Annual industrial use declined by 8% through the forecast horizon, consistent with trends from Avista’s industrial load forecast. The tables and graphs below present the projection at the end-use level. Overall in Washington, industrial annual electricity use decreases from 500 GWh in 2017 to 455 GWh in 2041. In Idaho, annual electricity use drops from 346 GWh in 2019 to 325 GWh in 2041.
Table 4-5 Industrial Baseline Projection by End Use (GWh), Washington
End Use 2019 2022 2023 2026 2031 2041 % Change
('19-'41)
Cooling 21 21 21 20 20 19 -11%
Space Heating 8 8 8 8 8 8 -9%
Ventilation 56 51 51 50 47 42 -24%
Interior Lighting 46 42 42 41 40 38 -17%
Process 125 119 119 119 119 119 -5%
Miscellaneous 0 0 0 0 0 0 76%
Total 500 471 472 468 463 455 -9%

Table 4-6 Industrial Baseline Projection by End Use (GWh), Idaho
End Use 2019 2022 2023 2026 2031 2041 % Change
('19-'41)
Cooling 15 16 16 16 15 13 -9%
Ventilation 39 41 40 38 35 30 -23%
Interior Lighting 32 33 33 31 30 27 -15%
Exterior Lighting 6 6 6 5 5 4 -27%
Process 68 74 73 72 70 66 -3%
Motors 162 177 176 173 168 158 -3%
Miscellaneous 19 21 21 21 22 22 18%
Total 346 374 371 362 349 325 -6%

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Figure 4-7 Industrial Baseline Projection by End Use (GWh), Washington

Figure 4-8 Industrial Baseline Projection by End Use (GWh), Idaho

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Summary of Baseline Projections across Sectors and States
Annual Use
Table 4-7 and Figure 4-9 provide a summary of the baseline projection for annual use by sector for the entire Avista service territory. Overall, the projection shows steady growth in electricity use, driven primarily by customer growth forecasts.
Table 4-7 Baseline Projection Summary (GWh), WA and ID Combined
End Use 2019 2022 2023 2026 2031 2041
Residential 3,775 3,774 3,785 3,820 3,953 4,489 19%
Commercial 3,173 3,223 3,234 3,273 3,427 3,924 24%
Industrial 846 845 843 831 812 780 -8%
Total 7,794 7,842 7,863 7,925 8,192 9,193 18%

Figure 4-9 Baseline Projection Summary (GWh), WA and ID Combined

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CONSERVATION POTENTIAL
This section presents the conservation potential for Avista. This includes every measure that is considered in the measure list, regardless of delivery mechanism (program implementation, NEEA initiatives, or momentum savings).
We present the annual energy savings in GWh and aMW, as well as the winter peak demand savings in MW, for selected years. Year-by-year savings for annual energy and peak demand are available in the LoadMAP model, which was provided to Avista at the conclusion of the study.
This section begins a summary of annual energy savings across all three sectors. Then we provide details for each sector. Please note that all savings are provided at the customer meter.
Overall Summary of Energy Efficiency Potential
Summary of Annual Energy Savings
Table 5-1 (WA) and Table 5-2 (ID) summarize the EE savings in terms of annual energy use for all measures for two levels of potential relative to the baseline projection. Figure 5-1(WA) and Figure 5-2 (ID) displays the two levels of potential by year. Figure 5-3 (WA) and Figure 5-4 (ID) display the EE projections.
• Te chnical Potential reflects the adoption of all conservation measures regardless of cost-effectiveness. For Washington, first-year savings are 101 GWh, or 2.0% of the baseline projection. Cumulative savings in 2041 are 1,822 GWh, or 29.2% of the baseline. For Idaho, first-year savings are 58 GWh, or 2.2% of the baseline projection. Cumulative savings in 2041 are 948 GWh, or 32.1% of the baseline.
• Te chnical A chievable Potentia l modifies Technical Potential by accounting for customer adoption constraints. In Washington, first-year savings potential is 56 GWh, or 1.1% of the baseline. In 2041, cumulative technical achievable savings reach 1,309 GWh, or 21.0% of the baseline projection. This results in average annual savings of 1.0% of the baseline each year. Technical Achievable Potential is approximately 72% of Technical Potential in Washington throughout the forecast horizon. For Idaho, first year savings are 3 GWh or 1.2% of the baseline and by 2041 cumulative technical achievable savings reach 665 GWh, or 22.5% of the baseline. This results in average annual savings of 1% of the baseline each year. In Idaho, Technical Achievable Potential reflects 71% of Technical Potential throughout the forecast horizon.
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Table 5-1 Summary of EE Potential (Annual Energy, GWh), Washington
2022 2023 2024 2031 2041
Baseline projection (GWh) 5,196 5,212 5,229 5,479 6,243
Cumulative Savings (GWh)
Technical Potential 101 209 325 1,247 1,822
Cumulative Savings (aMW)
Achievable Technical Potential 6 14 22 99 149
Cumulative Savings as a % of Baseline
Achievable Technical Potential 1.1% 2.3% 3.7% 15.8% 21.0%
Technical Potential 2.0% 4.0% 6.2% 22.8% 29.2%

Table 5-2 Summary of EE Potential (Annual Energy, GWh), Idaho
2022 2023 2024 2031 2041
Baseline projection (GWh) 2,646 2,650 2,653 2,713 2,951

Achievable Technical Potential 33 70 110 448 665
Technical Potential 58 119 183 654 948
Cumulative Savings (aMW)
Achievable Technical Potential 4 8 13 51 76
Technical Potential 7 14 21 75 108
Cumulative Savings as a % of Baseline
Achievable Technical Potential 1.2% 2.6% 4.1% 16.5% 22.5%
Technical Potential 2.2% 4.5% 6.9% 24.1% 32.1%

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Figure 5-1 Summary of EE Potential as % of Baseline Projection (Annual Energy), Washington

Figure 5-2 Summary of EE Potential as % of Baseline Projection (Annual Energy), Idaho

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Figure 5-3 Baseline Projection and EE Forecast Summary (Annual Energy, GWh), Washington

Figure 5-4 Baseline Projection and EE Forecast Summary (Annual Energy, GWh), Idaho

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Summary of Conservation Potential by Sector
Table 5-3 and Figure 5-5 summarize the range of electric Technical Achievable Potential by sector, both states combined. The residential and commercial sectors contribute the most savings, with commercial lighting forming a strong early foundation, and later-blossoming residential potential from measures such as heat pump water heaters growing to surpass commercial savings by years 10-20.
Table 5-3 Technical Achievable Conservation Potential by Sector (Annual Use), WA and ID
2022 2023 2024 2031 2041
Cumulative Savings (GWh)
Residential 32 72 120 623 1,004
Commercial 46 97 152 583 819
Industrial 10 21 33 110 151
Total 88 190 304 1,317 1,974

Cumulative Savings (aMW)
Residential 4 8 14 71 115
Commercial 5 11 17 67 94
Industrial 1 2 4 13 17
Total 10 22 35 150 225

Figure 5-5 Technical Achievable Conservation Potential by Sector (Annual Energy, GWh)

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Residential Conservation Potential
Table 5-4 (WA) and Table 5-5 (ID) present estimates for measure-level conservation potential for the residential sector in terms of annual energy savings. Figure 5-6 (WA) and Figure 5-7 (ID) display the two levels of potential by year. For Washington, Technical Achievable Potential in 2022 is 20 GWh, or 0.8 % of the baseline projection. By 2041, cumulative technical achievable savings are 672 GWh, or 22.6% of the baseline projection. At this level, it represents over 66% of technical potential. For Idaho, 2022 technical achievable savings are 12 GWh or 1.0% of the baseline and by 2040 cumulative technical achievable savings reach 332 GWh, or 21.9% of the baseline. Technical Achievable Potential in Idaho in 2041 is 67% of technical potential.
Table 5-4 Residential Conservation Potential (Annual Energy), Washington
2022 2023 2024 2031 2041
Baseline projection (GWh) 2,525 2,529 2,534 2,631 2,976
Cumulative Savings (GWh)
Achievable Technical Potential 20 45 75 409 672
Technical Potential 49 103 162 655 1,005
Cumulative Savings (aMW)
Achievable Technical Potential 2 5 9 47 77
Technical Potential 6 12 18 75 115
Cumulative Savings as a % of Baseline
Achievable Technical Potential 0.8% 1.8% 3.0% 15.6% 22.6%
Technical Potential 1.9% 4.1% 6.4% 24.9% 33.8%

Table 5-5 Residential Conservation Potential (Annual Energy), Idaho
2022 2023 2024 2031 2041
Baseline projection (GWh) 1,250 1,256 1,262 1,322 1,513
Cumulative Savings (GWh)
Achievable Technical Potential 12 27 45 214 332
Technical Potential 27 56 88 334 494
Cumulative Savings (aMW)
Achievable Technical Potential 1 3 5 24 38
Technical Potential 3 6 10 38 56
Cumulative Savings as a % of Baseline
Achievable Technical Potential 1.0% 2.2% 3.5% 16.2% 21.9%
Technical Potential 2.1% 4.5% 6.9% 25.3% 32.6%
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Figure 5-6 Residential Conservation Savings as a % of the Baseline Projection (Annual Energy), Washington

Figure 5-7 Residential Conservation Savings as a % of the Baseline Projection (Annual Energy), Idaho

Below, we present the top residential measures from the perspective of annual energy use. Table 5-6 identifies the top 20 residential measures from the perspective of cumulative technical achievable energy savings potential for Washington in 2023, the second year of potential. The top three measures include ENERGY STAR- Connected Thermostat, Ductless Mini Split Heat Pump (Zonal), and Home Energy Management System (HEMS). Note that technical achievable savings do not screen for cost effectiveness and some measures are expected to be screened out during the IRP process.

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Table 5-6 Residential Top Measures in 2023 (Annual Energy, MWh), Washington
Rank Residential Measure
2023 Cumulative
Energy Savings % of
(MWh) Total
1 ENERGY STAR - Connected Thermostat 4,409 10%
2 Ductless Mini Split Heat Pump (Zonal) 4,280 10%
3 Home Energy Management System (HEMS) 3,428 8%
4 Windows - High Efficiency/ENERGY STAR 2,154 5%
5 Water Heater <= 55 Gal 2,016 5%
6 Insulation - Basement Sidewall Installation 1,826 4%
7 Insulation - Ducting 1,563 3%
8 Windows - Low-e Storm Addition 1,519 3%
9 Building Shell - Air Sealing (Infiltration Control) 1,228 3%
10 Ductless Mini Split Heat Pump with Optimized Controls (Ducted Forced Air) 1,128 3%
11 Connected Line-Voltage Thermostat 1,128 3%
12 Exempted Lighting 1,035 2%
13 Interior Lighting - Occupancy Sensors 1,004 2%
14 Exterior Lighting - Photovoltaic Installation 980 2%
15 Insulation - Floor Upgrade 898 2%
16 General Service Lighting 896 2%
17 Building Shell - Whole-Home Aerosol Sealing 840 2%
18 Insulation - Ceiling Upgrade 804 2%
19 Insulation - Wall Cavity Installation 770 2%
20 Windows - Cellular Shades 685 2%
Total of Top 20 Measures 32,591 73%
Total Cumulative Savings 44,799 100%

Figure 5-8 presents forecasts of cumulative energy savings for Washington. Space heating and water heating account for a substantial portion of the savings throughout the forecast horizon. Weatherization, ductless heat pumps, 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 realm of codes and market transformation.
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Figure 5-8 Residential Technical Achievable Savings Forecast (Cumulative GWh), Washington

Table 5-7 shows the top residential measures for Idaho in 2023. The top three measures include high efficiency windows, Ductless Mini Split Heat Pump (Zonal), and LEDs in General Service Lighting. Since Idaho does not have the same state standard regarding lighting, LEDs for general service have a greater remaining market of potential captured in the CPA. in Note that technical achievable savings do not screen for cost effectiveness and some measures are expected to be screened out during the IRP process.

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Table 5-7 Residential Top Measures in 2022 (Annual Energy, MWh), Idaho
Rank Residential Measure
2023 Cumulative
Energy Savings % of
(MWh) Total
1 Windows - High Efficiency/ENERGY STAR 3,654 13%
2 Ductless Mini Split Heat Pump (Zonal) 2,319 9%
3 General Service Lighting 2,302 8%
4 Home Energy Management System (HEMS) 1,547 6%
5 ENERGY STAR - Connected Thermostat 1,480 5%
6 Windows - Low-e Storm Addition 1,312 5%
7 Insulation - Basement Sidewall Installation 1,107 4%
8 Connected Line-Voltage Thermostat 689 3%
9 Building Shell - Air Sealing (Infiltration Control) 688 3%
10 Water Heater - Faucet Aerators 634 2%
11 Water Heater <= 55 Gal 630 2%
12 Exterior Lighting - Photovoltaic Installation 621 2%
13 Insulation - Ducting 580 2%
14 Insulation - Floor Upgrade 520 2%
15 Interior Lighting - Occupancy Sensors 452 2%
16 Insulation - Wall Cavity Installation 425 2%
17 Insulation - Wall Sheathing 383 1%
18 Insulation - Ceiling Upgrade 376 1%
19 Building Shell - Whole-Home Aerosol Sealing 369 1%
20 Ductless Mini Split Heat Pump with Optimized Controls 357 1%
Total of Top 20 Measures 20,445 75%
Total Cumulative Savings 27,260 100%

Figure 5-9 presents forecasts of cumulative energy savings for Idaho. Results are similar to Washington where the majority of the savings come from heating and water heating measures.
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Figure 5-9 Residential Technical Achievable Savings Forecast (Cumulative GWh), Idaho

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Commercial Conservation Potential
Table 5-8 (WA) and Table 5-9 (ID) present estimates for the two levels of conservation potential for the commercial sector from the perspective of annual energy savings and average MW.
Table 5-8 Commercial Conservation Potential (Annual Energy), WA
2022 2023 2024 2031 2041
Baseline projection (GWh) 2,201 2,211 2,224 2,385 2,811
Cumulative Savings (GWh)
Achievable Technical Potential 30 64 101 397 551
Technical Potential 44 90 139 514 712
Cumulative Savings (aMW)
Achievable Technical Potential 3 7 12 45 63
Technical Potential 5 10 16 59 81
Cumulative Savings as a % of Baseline
Achievable Technical Potential 1.4% 2.9% 4.5% 16.6% 19.6%
Technical Potential 2.0% 4.1% 6.3% 21.5% 25.3%

Table 5-9 Commercial Conservation Potential (Annual Energy), Idaho
2022 2023 2024 2031 2041
Baseline projection (GWh) 1,022 1,023 1,023 1,041 1,112
Cumulative Savings (GWh)
Achievable Technical Potential 16 33 51 186 268
Technical Potential 25 50 76 260 375
Cumulative Savings (aMW)
Achievable Technical Potential 2 4 6 21 31
Technical Potential 3 6 9 30 43
Cumulative Savings as a % of Baseline
Achievable Technical Potential 1.6% 3.2% 5.0% 17.9% 24.1%
Technical Potential 2.5% 4.9% 7.5% 25.0% 33.7%
Figure 5-10 (WA) and Figure 5-11 (ID) display the two levels of potential by year. For Washington, the first year of the projection, Technical Achievable Potential is 30 GWh, or 1.4% of the baseline projection. By 2041, technical achievable savings are 551 GWh, or 19.6% of the baseline projection. Throughout the forecast horizon, Technical Achievable Potential represents about 77% of technical potential. For Idaho, first year technical achievable savings are 16 GWh or 1.6% of the baseline and by 2041, cumulative technical
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achievable savings reach 268 GWh, or 24.1% of the baseline. Throughout the forecast horizon, Technical Achievable Potential represents about 71% of technical potential in Idaho.
Figure 5-10 Commercial Conservation Savings (Energy), Washington

Figure 5-11 Commercial Conservation Savings (Energy), Idaho

Below, we present the top commercial measures from the perspective of annual energy use.
Table 5-10 (WA) and Table 5-11 (ID) identify the top 20 commercial-sector measures from the perspective of annual energy savings in 2019. In both states, lighting applications make up three out of the top five 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.
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Figure 5-12 (WA) and Figure 5-13 (ID) present forecasts of cumulative energy savings by end use. Lighting savings from interior and exterior applications account for a substantial portion of the savings throughout the forecast horizon, due in part to revised turnover assumptions for C&I lighting consistent with RTF assumptions.
Table 5-5-10 Commercial Top Measures in 2019 (Annual Energy, MWh), Washington
Rank Commercial Measure
2023 Cumulative
Energy Savings % of
(MWh) Total
1 Retrocommissioning 6,538 10%
2 Linear Lighting 5,887 9%
3 Strategic Energy Management 4,771 7%
4 Space Heating - Heat Recovery Ventilator 2,401 4%
5 High-Bay Lighting 2,306 4%
6 General Service Lighting 2,010 3%
7 Chiller - Variable Flow Chilled Water Pump 1,876 3%
8 Exterior Lighting - Photovoltaic Installation 1,857 3%
9 HVAC - Dedicated Outdoor Air System (DOAS) 1,679 3%
10 Interior Lighting - Embedded Fixture Controls 1,568 2%
11 Refrigeration - Evaporative Condenser 1,505 2%
12 Ventilation - Permanent Magnet Synchronous Fan Motor 1,379 2%
13 Thermostat - Connected 1,364 2%
14 Area Lighting 1,317 2%
15 Ventilation - Variable Speed Control 1,084 2%
16 Refrigeration - Variable Speed Compressor 982 2%
17 Ventilation - ECM on VAV Boxes 970 2%
18 RTU - Evaporative Precooler 958 1%
19 HVAC - Economizer Maintenance and Repair 876 1%
20 Water Heater - Solar System 754 1% Total of Top 20 Measures 42,082 66%
Total Cumulative Savings 64,043 100%

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Figure 5-12 Commercial Technical Achievable Savings Forecast (Cumulative GWh), Washington

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Cooling
Space Heating
Ventilation
Water Heating
Interior Lighting
Exterior Lighting
Refrigeration
Food Preparation
Office Equipment
Miscellaneous
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Table 5-11 Commercial Top Measures in 2023 (Annual Energy, MWh), Idaho
Rank Commercial Measure
2023 Cumulative
Energy Savings % of
(MWh) Total
1 Linear Lighting 3,251 10%
2 Retrocommissioning 2,780 8%
3 Space Heating - Heat Recovery Ventilator 2,727 8%
4 Strategic Energy Management 2,276 7%
5 High-Bay Lighting 1,817 6%
6 HVAC - Dedicated Outdoor Air System (DOAS) 1,375 4%
7 General Service Lighting 1,171 4%
8 Ductless Mini Split Heat Pump 1,131 3%
9 Chiller - Variable Flow Chilled Water Pump 1,048 3%
10 Exterior Lighting - Photovoltaic Installation 1,016 3%
11 Interior Lighting - Embedded Fixture Controls 902 3%
12 Area Lighting 882 3%
13 Thermostat - Connected 801 2%
14 Ventilation - Permanent Magnet Synchronous Fan Motor 636 2%
15 Ventilation - Variable Speed Control 508 2%
16 Exterior Lighting - Enhanced Controls 477 1%
17 Office Equipment - Advanced Power Strips 473 1%
18 HVAC - Economizer Maintenance and Repair 470 1%
19 Ventilation - ECM on VAV Boxes 460 1%
20 RTU - Evaporative Precooler 439 1%
Total of Top 20 Measures 24,638 75%
Total Cumulative Savings 32,778 100%

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Figure 5-13 Commercial Technical Achievable Savings Forecast (Cumulative GWh), Idaho

Industrial Conservation Potential
Table 5-12 (WA) and Table 5-13 (ID) present potential estimates at the measure level for the industrial sector, from the perspective of annual energy savings. Figure 5-14 (WA) and Figure 5-15 (ID) display the two levels of potential by year. For Washington, technical achievable savings in the first year, 2022, are 6 GWh, or 1.2% of the baseline projection. In 2041, savings reach 86 GWh, or 18.8% of the baseline projection. For Idaho, technical achievable savings in the first year, 2022, are 4 GWh, or 1.2% of the baseline projection. In 2041, savings reach 65 GWh, or 20.0% of the baseline projection.
Table 5-12 Industrial Conservation Potential (Annual Energy), WA
2022 2023 2024 2031 2041
Baseline projection (GWh) 471 472 471 463 455
Cumulative Savings (GWh)
Achievable Technical Potential 6 12 18 62 86
Technical Potential 8 17 25 78 105
Cumulative Savings (aMW)
Achievable Technical Potential 1 1 2 7 10
Technical Potential 1 2 3 9 12
Cumulative Savings as a % of Baseline
Achievable Technical Potential 1.2% 2.5% 3.8% 13.4% 18.8%
Technical Potential 1.7% 3.5% 5.2% 16.8% 23.1%

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Commercial Technical Achievable Potential Savings by End Use
Cooling
Space Heating
Ventilation
Water Heating
Interior Lighting
Exterior Lighting
Refrigeration
Food Preparation
Office Equipment
Miscellaneous
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Table 5-13 Industrial Conservation Potential (Annual Energy), Idaho
2022 2023 2024 2031 2041
Baseline projection (GWh) 374 371 368 349 325
Cumulative Savings (GWh)
Achievable Technical Potential 4 10 14 49 65
Technical Potential 6 13 19 60 79
Cumulative Savings (aMW)
Achievable Technical Potential 1 1 2 6 7
Technical Potential 1 1 2 7 9
Cumulative Savings as a % of Baseline
Achievable Technical Potential 1.2% 2.6% 3.9% 13.9% 20.0%
Technical Potential 1.6% 3.4% 5.2% 17.2% 24.3%

Figure 5-14 Industrial Conservation Potential as a % of the Baseline Projection (Annual Energy), Washington

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Figure 5-15 Industrial Conservation Potential as a % of the Baseline Projection (Annual Energy), Idaho

Below, we present the top industrial measures from the perspective of annual energy use.
Table 5-14 and Table 5-15 identify the top 20 industrial measures from the perspective of annual energy savings in 2020. For both states, the top measure is High-Bay Lighting. The measure with the second highest savings is Interior Lighting- Embedded Fixture Controls, and retrocomissioning rounds out the top three in both states.
Figure 5-16 (WA) and Figure 5-17 (ID) present forecasts of energy savings by end use as a percent of total annual savings and cumulative savings. Various motor savings and lighting make up the majority of savings potential in the study horizon.
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Table 5-14 Industrial Top Measures in 2023 (Annual Energy, GWh), Washington
Rank Industriall Measure
2023 Cumulative
Energy Savings % of
(MWh) Total
1 High-Bay Lighting 3,542 30%
2 Interior Lighting - Embedded Fixture Controls 862 7%
3 Retrocommissioning 740 6%
4 Fan System - Equipment Upgrade 656 5%
5 Strategic Energy Management 613 5%
6 Fan System - Flow Optimization 550 5%
7 Compressed Air - Leak Management Program 379 3%
8 Material Handling - Variable Speed Drive 378 3%
9 Pumping System - System Optimization 342 3%
10 Interior Lighting - Networked Fixture Controls 303 3%
11 Interior Fluorescent - Delamp and Install Reflectors 252 2%
12 Compressed Air - End Use Optimization 246 2%
13 LED Lighting for Indoor Agriculture 236 2%
14 Pumping System - Variable Speed Drive 225 2%
15 Fan System - Variable Speed Drive 215 2%
16 Exterior Lighting - Photovoltaic Installation 205 2%
17 Interior Lighting - Skylights 193 2%
18 Ventilation 179 1%
19 Pumping System - Equipment Upgrade 171 1%
20 Advanced Refrigeration Controls 166 1%
Total of Top 20 Measures 10,454 87%
Total Cumulative Savings 11,959 100%

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Figure 5-16 Industrial Technical Achievable Savings Forecast (Cumulative GWh), Washington

Table 5-15 Industrial Top Measures in 2019 (Annual Energy, GWh), Idaho
Rank Industrial Measure
2023 Cumulative
Energy Savings % of
(MWh) Total
1 High-Bay Lighting 2,514 26%
2 Interior Lighting - Embedded Fixture Controls 613 6%
3 Retrocommissioning 550 6%
4 Fan System - Equipment Upgrade 518 5%
5 Strategic Energy Management 485 5%
6 Fan System - Flow Optimization 435 5%
7 Compressed Air - Equipment Upgrade 396 4%
8 Compressed Air - Leak Management Program 299 3%
9 Material Handling - Variable Speed Drive 299 3%
10 Pumping System - System Optimization 270 3%
11 Destratification Fans (HVLS) 241 3%
12 Interior Lighting - Networked Fixture Controls 215 2%
13 Interior Fluorescent - Delamp and Install Reflectors 199 2%
14 Compressed Air - End Use Optimization 194 2%
15 LED Lighting for Indoor Agriculture 184 2%
16 Pumping System - Variable Speed Drive 178 2%
17 Fan System - Variable Speed Drive 170 2%
18 Exterior Lighting - Photovoltaic Installation 161 2%
19 Pumping System - Equipment Upgrade 135 1%
20 Interior Lighting - Skylights 126 1% Total of Top 20 Measures 8,184 86%
Total Cumulative Savings 9,510 100%
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Motors
Process
Miscellaneous
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Figure 5-17 Industrial Technical Achievable Savings Forecast (Annual Energy, GWh), Idaho

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Exterior Lighting
Motors
Process
Miscellaneous
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DEMAND RESPONSE POTENTIAL
In 2014, AEG and The Brattle Group performed an assessment of winter demand response potential for Avista’s commercial and industrial (C&I) sectors. As part of this conservation potential assessment, Avista asked AEG to update the DR analysis for C&I sectors in Washington and Idaho. In 2016, AEG provided an update to the 2014 assessment. For the 2019 study, Avista asked that AEG include the demand response potential for their residential sector and since Avista is a dual-peaking utility, AEG was asked to provide summer demand response potential as well. This year for the 2020 study, to achieve a more accurate representation of ancillary services, viable programs were evaluated on an individual basis for ancillary savings potential.
The updated analysis provides demand response potential and cost estimates for the 24-year planning horizon of 2022-2045 to inform the development of Avista’s 2021 Integrated Resource Plan (IRP). It primarily seeks to develop reliable estimates of the magnitude, timing, and costs of DR resources likely available to Avista over the 24-year 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.
This section describes our analysis approach and the data sources used to develop potential and cost estimates. The following three steps broadly outline our analysis approach:
1. Segment residential service, general service, large general service, and extra-large general service customers for DR analysis and develop market characteristics (customer count and coincident peak demand values) by segment for the base year and planning period.
2. Identify and describe the relevant DR programs and develop assumptions on key program parameters for potential and cost analysis.
3. Assess achievable potential by DR program for the 2022-2045 planning period and estimate program budgets and levelized costs.
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 the number of eligible customers in each market segment and their coincident peak demand.
Market segmentation
Like the 2014, 2016, and 2019 studies, we used Avista’s rate schedules as the basis for customer segmentation by state and customer class. Table 6-1 summarizes the market segmentation we developed for this study.

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Table 6-1 Market Segmentation
Market Dimensions Segmentation Variable Description
1 State Idaho
Washington
2 Customer Class
By rate schedule:
Residential Service
General Service: Rate Schedule 11
Large General Service: Rate Schedule 21
Extra Large General Service: Rate Schedule 2510
We excluded Avista’s two largest industrial customers from our analysis because they are so large and unique that a segment-based modeling approach is not appropriate. To accurately estimate demand reduction 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 with these large customers directly to gauge interest in participating in DR programs.
Customer Counts by Segment
Once the customer segments were defined, we developed customer counts and coincident peak demand values for the three C&I segments. We developed these estimates separately by state for Washington and Idaho. We considered 2019 as the base year for the study, since this is the most recent year with a full 12 months of available customer data. This also coincides with the base year used for the CPA study. The forecast years are 2022 to 2045.
Avista provided actual customer counts by rate schedule for Washington and Idaho over the 2016-2019 timeframe and forecasted customer counts over the 2020-2025 period. We used this data to calculate the growth rate across the final two years of the forecast. We then applied these growth rates to develop customer projections over the rest of the study timeframe, 2026-2045. The average annual growth rate for all sectors is 1.1%. Table 6-2 below shows the number of customers by state and customer class for the base year and selected future years.

Table 6-2 Baseline C&I Customer Forecast by State and Customer Class
Customer Class 2022 2025 2035 2045
Washington
General Service 23,328 24,029 26,470 29,159
Large General Service 1,847 1,840 1,822 1,808
Extra Large General Service 22 22 22 22
Total 260,146 267,489 292,881 320,712

10 Excluding the two largest Schedule 25 and Schedule 25P customers.
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Customer Class 2022 2025 2035 2045
Idaho
Residential Service 120,797 125,479 141,680 159,973
General Service 16,897 17,505 19,692 22,158
Large General Service 1,012 1,007 992 982
Extra Large General Service 11 11 11 11
Total 138,717 144,002 162,376 183,124

Forecasts of Winter and Summer Peak Demand
System Peak Demand
Avista provided the 2019 system winter and summer peak values as well as annual energy forecasts through 2025. AEG used the growth rate across the final two forecasted years by state and sector to forecast annual peak demands through 2045, Table 6-3 shows the winter and summer system peaks for the base year and selected futures years. These peaks exclude the demand for Avista’s largest industrial customers. The winter and summer system peaks are each expected to increase around 10% between 2022-2045.
Table 6-3 Baseline System Winter Peak Forecast (MW @Meter) 11
Peak Demand 2022 2025 2035 2045
Winter System Peak 1,331 1,349 1,403 1,444
Summer System Peak 1,369 1,389 1,446 1,508

Coincident Peak Demand by Segment
To develop the coincident peak forecast for each segment, we started with electricity sales by customer class. Avista provided actual electricity sales for the years 2016-2019 and forecasted electricity sales by rate schedule for the years 2020 through 2025. For the remaining years of the forecast, 2026 through 2045, we projected electricity sales using the growth rate from the last two years of each forecast timeframe.
Next, we relied on electricity sales and coincident peak demand values for 2010 provided in the 2010 load research study conducted by Avista to calculate the load factors for Residential Service, General Service, Large General Service, and Extra Large General Service customers for Washington and Idaho. We then applied the load factors to the 2019 electricity sales data to derive coincident peak demand estimates for the four segments. Table 6-4 and Table 6-5 below show the load factors and coincident peak values for the base year and selected future years.

11 The system peak forecast shown here is the net native load forecast from data provided by Avista, excluding the two largest industrial loads.
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Table 6-4 Winter Load Factors and Baseline Coincident Peak Forecast by Segment (MW @Meter)
Customer Class Load Factor 2022 2025 2035 2045
Washington
Residential 0.63 473 481 502 522
General Service 0.60 82 85 93 103
Large General Service 0.60 185 184 182 180
Extra Large General Service 0.68 83 83 83 84
Total 823 834 861 889
Idaho
Residential 0.65 226 232 252 274
General Service 0.66 65 67 75 85
Large General Service 0.66 91 90 87 85
Extra Large General Service 0.60 49 49 47 45
Total 431 437 461 489

Table 6-5 Summer Load Factors and Baseline Coincident Peak Forecast by Segment (MW @Meter)
Customer Class Load Factor 2022 2025 2035 2045
Washington
Residential 0.50 509 518 540 562
General Service 0.51 83 85 94 103
Large General Service 0.51 186 185 183 181
Extra Large General Service 0.65 74 74 75 75
Total 852 863 892 922
Idaho
Residential 0.53 237 243 264 287
General Service 0.57 64 66 75 84
Large General Service 0.57 90 89 86 84
Extra Large General Service 0.53 48 47 45 44
Total 438 445 470 499

System and Coincident Peak Forecasts by State
The next step in market characterization is to define the estimated peak load forecast for the study timeframe. This is done at the Avista system level, and also by state. We used Avista’s peak demand data
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to develop the individual state contribution to the estimated coincident peak values. These represent a state’s projected demand at the time of the system peak for both summer and winter.
Figure 6-1 shows the statewide contribution to the estimated system coincident summer peak, developed based on load forecast data provided by Avista. In 2022, system peak load for the summer is 1,369 MW at the grid or generator level. Washington contributes 66% of summer system peak while Idaho contributes 34%. Summer coincident peak load is expected to grow by an average of 0.42% annually from 2022-2044.
Figure 6-1 Contribution to Estimated System Coincident Peak Forecast by State (Summer)

Figure 6-2 shows the jurisdictional contribution to the estimated system coincident winter peak forecast, developed based on load forecast data provided by Avista. In 2022, system peak load for the winter (a typical December weekday at 6:00 pm) is 1,331 MW at the grid or generator level. The winter system peak is about 3% lower than the summer peak. Washington contributes 66% of winter system peak while Idaho contributes 34%. Over the study period, winter coincident peak load is expected to grow by an average of 0.41% annually.
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Figure 6-2 Contribution to Estimated System Coincident Peak Forecast by State (Winter)

Equipment End Use Saturation
Another key component of market characterization for DR analysis is end use saturation data. This is required to further segment the market and identify eligible customers for direct control of different equipment options. The relevant space heating equipment for DR analysis are electric furnaces and air-source heat pumps. We obtained C&I saturation data from the CPA study, which had updated figures from the 2019 NEEA Commercial Building Stock Assessment (CBSA). We obtained Residential saturation data from the 2016 NEEA Residential Building Stock Assessment (RBSA). Table 6-6 and Table 6-7 below show saturation estimates by state and customer class for Washington and Idaho respectively. We assume slight growth trends in Central AC, Space Heating, and Electric Vehicle saturations through 2040. For AMI, Avista began their rollout in Washington in 2019 and expects to complete it by the end of 2020. Currently Avista has 99.5% of their rollout complete in their electric only service areas in Washington. In Idaho, the AMI rollout is projected to begin in 2022 and be complete by 2024.
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Table 6-6 2019 End Use Saturations by Customer Class, Washington
End Use Saturation by Equipment Type Residential C&I
Space Heating Saturation
Air-Source Heat Pump 40.8% 14.2%
Total (Applicable for DR Analysis) 40.8% 14.2%
Water Heating Saturation
CTA-2045 Water Heater 0.0% 0.0%
Electric Vehicle Saturation

Central AC Saturation
All Equipment 27.8% 27.8%
AMI Saturation
All Equipment 2.0% 2.0%
Appliance Saturation

Table 6-7 2019 End Use Saturation by Customer Class, Idaho
End Use Saturation by Equipment Type Residential C&I
Space Heating Saturation
Air-Source Heat Pump 40.8% 14.2%
Total (Applicable for DR Analysis) 40.8% 14.2%
Water Heating Saturation
Electric Resistance Water Heater 52.2% 60.1%

All equipment 0.8% -
Central AC Saturation
All Equipment 27.8% 27.8%
AMI Saturation
All Equipment 0.0% 0.0%
Appliance Saturation
All Equipment 100.0% -

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DSM Program Options
The next step in the analysis is to characterize the available DSM options for the Avista territory. We considered the characteristics and applicability of a comprehensive list of options available in the DSM marketplace today as well as those projected into the 24-year study time horizon. We included for quantitative analysis those options which have been deployed at scale such that reliable estimates exist for cost, lifetime, and performance. Each selected option is described briefly below.
Program Descriptions
Direct Load Control of Central Air Conditioners
The DLC Central AC program targets Avista’s Residential and General Service customers in Washington and Idaho. This program directly controls Central AC load in summer through a load control switch placed on a customer’s AC unit. During events, the AC units will be cycled on and off. Participation in the program is expected to be shared with the Smart Thermostat- Cooling Program in the integrated scenario since the programs are similar. However, if only one program is rolled out of the two, then participation would be expected to double for the program implemented. In the fully integrated case, we assume it would take three full time employees to manage all the DLC programs (five total).
The DLC Domestic Hot 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 winter months. Water heaters of all sizes are eligible for control. We assume 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).
The CTA-2045 Hot 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 prevalant in the Avista territory. Idaho is not mandating this equipment yet and therefore this program is only modeled for Washington. Water heaters would be completely turned off during the DR event period. The event period is assumed to be 75 hours during the summer months and another 75 hours during winter months. Water heaters of all sizes are eligible for control. We assume a $150 cost to Avista for each module as well as an additional provisioning cost of $100 for each customer (since only 20% of customers will need help provisioning, so we assume a $20 average provisioning cost.)
This program uses the two-way communicating ability of smart thermostats to cycle them on and off during events. The Smart Thermostat program targets Avista’s Residential and General Service customers in Washington and Idaho. We assume this will be a Bring your own Thermostat program (BYOT) and therefore assume no installation costs to Avista. Since the cooling and heating programs are quite different as far as impact assumptions and participation rates, we modeled them separately. As mentioned in the DLC Central AC program description, participation in the DLC Smart Thermostat Cooling program is expected to be split between the two programs in the integrated scenario.
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The Smart Appliances DLC 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 will be cycled on and off. The Smart Appliances DLC program targets Avista’s Residential and General Service customers in Washington and Idaho. We assume a low steady-state participation rate of 5% for this program.
Third Party Contracts are assumed to be available for General Service, Large General Service, and Extra Large General Service customers year-round. For the Large and Extra Large General Service customers, we assume they will engage in firm curtailment. Under this program option, it is 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 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.
For the general service customers, we simulate a demand buyback program. In a demand buyback program, customers volunteer to reduce what they can on a day-ahead or day-of basis during a predefined event window. Customers then receive an energy payment based on their performance during the events.
DLC Smart Chargers for Electric Vehicles can be switched off during on-peak hours throughout the year to offset demand to off-peak hours. Avista currently has an Electric Vehicle Supply Equipment (EVSE) pilot program in place for residential, commercial electric vehicle fleets, and workplace charging locations. In 2018, we based our assumptions off of the EVSE pilot results. However, this year Avista revised several program assumptions internally and AEG used those numbers for the study. The program start year was updated to 2024 to reflect technology rollout, the peak reduction was increased, annual O&M Costs were lowered, the Cost of Equipment was lowered, and the annual incentive costs were removed in lieu of a rebate or the utility providing a rate-based charger to participate in the program.
The Time-of-Use (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
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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. We assume this rate will be available to all service classes.
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. We assume that this rate will be offered to all service classes
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. We assume ancillary services demand response capabilities can be available in all sectors. This year we modeled individual ancillary programs based on several parent programs: Smart Thermostats- Heating/Cooling, DLC Water Heating, CTA-2045 Water Heating, Electric Vehicle Charging, and Battery Energy Storage.
Ice Energy Storage, a type of thermal energy storage, is an emerging technology that 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 at a later time for space cooling. More specifically, the freezing 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 is low, typically night time. 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 the ice energy storage is used for space cooling, we assume this program would be available during the summer months only.
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. We assume the battery energy storage option will be available for all service classes with the size and cost of the battery varying depending upon the level of demand of the building.
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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.
For this 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
Table 6-8 lists the DSM options considered in the study, including the eligible sectors, the mechanism for deployment and the expected annual event hours (summer and winter hours combined if both seasons are considered). The 2018 study revised the 2016 study by adding Space Heating as an additional option, however Avista ultimately decided the Smart Thermostat DLC Heating program would be sufficient for DLC space heating options. For cooling, both Central AC DLC and Smart Thermostats DLC were considered as options. 2018 was also the first year that the CTA-2045 Water Heaters were considered as an option. In 2020, several other changes were made to provide a more realistic forecast of DR potential. Since CTA-2045 Water Heaters are only being mandated in Washington, we used a DLC Water Heating program for Idaho instead. Real Time Pricing was removed as a rate option as it is becoming more of a rarely implemented program. In addition, ancillary services were broken out this year as subsets of viable parent programs to capture a more accurate depiction of their potential savings.
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Table 6-8 Class 1 DSM Products Assessed in the Study
DSM Option Eligible Sectors Mechanism
Annual
Event
Hours
DLC of central air
conditioners
Residential, General
Service
Direct load control switch installed on customer’s
equipment. 100
DLC of domestic hot
water heaters
(DHW)
Residential, General
Service
Direct load control switch installed on customer’s
equipment. 100
CTA-2045 hot water
heaters
Residential, General
Service Communicating module installed on water heater 150
Smart Thermostats
DLC Heating
Residential, General
Service Internet-enabled control of thermostat set points 36
Smart Thermostats
DLC Cooling
Residential, General
Service Internet-enabled control of thermostat set points 36
Smart Appliances
DLC
Residential, General
Service
Internet-enabled control of operational cycles of
white goods appliances 1056
Thermal Energy
Storage
General Service, Large
General Service, Extra
Large General Service
Peak shifting of space cooling loads using stored
ice 72
Third Party
Contracts
General Service, Large
General Service, Extra
Large General Service
Customers enact their customized, mandatory
curtailment plan. Penalties apply for non-
performance. 60
Electric Vehicle DLC
Smart Chargers Residential Automated, level 2 EV chargers that postpone or
curtail charging during peak hours. 1056
Time-of-Use Pricing All Sectors
Higher rate for a particular block of hours that
occurs every day. Requires either on/off peak
meters or AMI technology.
1056
Variable Peak Pricing All Sectors
Much higher rate for a particular block of hours
that occurs only on event days. Requires AMI
technology. 80
Ancillary Services All Sectors
Automated control of various building
management systems or end-uses through one of
the mechanisms already described
varies by
program
Thermal Energy
Storage
General Service, Large
General Service, Extra
Large General Service
Peak shifting of primarily space cooling or heating
loads using a thermal storage medium such as
water or ice 72
Battery Energy
Storage All Sectors
Peak shifting of loads using stored
electrochemical energy

72
Behavioral Residential
Voluntary DR reductions in response to
behavioral messaging. Example programs exist in
CA and other states. Requires AMI technology. 80
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The description of options below includes the key assumptions used for potential and levelized cost calculations. The development of these assumptions is based on findings from research and review of available information on the topic, including national program survey databases, evaluation studies, program reports, regulatory filings. The key parameters required to estimate potential for a DSM program are participation rate, per participant load reduction and program costs. We have described below our assumptions of these parameters.
Table 6-9 below shows the steady-state participation rate assumptions for each DSM option as well as the basis for the assumptions. As previously mentioned, the participation for space cooling is split between DLC Central AC and Smart Thermostat options.
Table 6-9 DSM Steady-State Participation Rates (% of eligible customers)
DSM Option Residential
Service
General
Service
Large
General
Service
Extra Large General
Service Basis for Assumption
Direct Load
Control (DLC) of
central air
conditioners
10% 10% - - NWPC DLC Switch cooling
assumption
DLC of domestic
hot water
heaters (DHW) 15% 5% - - Industry Experience- Brattle
Study
Smart
Thermostats
DLC Heating 5% 3% - - Agreed Upon Estimate with
Avista
CTA-2045 hot
water heaters 50% 50% - - NWPC Grid Interactive
Water Heater Assumptions
Smart
Thermostats
DLC Cooling
20% 20% - -
NWPC Smart Thermostat
cooling assumption (See
DLC Central AC)
Smart
Appliances DLC 5% 5% - -
2017 ISACA IT Risk Reward
Barometer – US Consumer
Results, October 2017
Third Party
Contracts - 15% 22% 21% Industry Experience
Electric Vehicle
DLC Smart
Chargers
25% - - -
NWPC Electric Resistance
Grid-Ready Summer/Winter
Participation
Time-of-Use
Pricing Opt-in 13% 13% 13% 13% Best estimate based on
industry experience; Winter
impacts ½ of summer
impacts Time-of-Use
Pricing Opt-out 74% 74% 74% 74%
Variable Peak
Pricing 25% 25% 25% 25% OG&E 2019 Smart Hours
Study
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Thermal Energy
Storage - 0.5% 1.5% 1.5% Industry Experience
Battery Energy
Storage 0.5% 0.5% 0.5% 0.5% Industry Experience
Behavioral 20% - - - PG&E rollout with six waves
(2017)

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Table 6-10 presents the per participant load reductions for each DSM option and explains the basis for these assumptions. The load reductions are shown on a kW basis for technology-based options and a percent load reduction otherwise.
Table 6-10 DSM Per Participant Impact Assumptions
DSM Option Residential General
Service
Large
General
Service
Extra
Large
General
Service
Basis for Assumption
Direct Load
Control (DLC)
of central air
conditioners
0.5 kW 1.25 kW - -
NWPC DLC Switch cooling assumption was close
to 1.0 kW reduced to adjust for Avista proposed
cycling strategy,
DLC of
domestic hot
water heating
(DHW)
0.50 kW 1.26 kW - -
NWPC Electric Resistance Switch Summer Impact,
General Service is 2.52x that of Residential based
on DLC Central AC Residential to C&I ratio

CTA-2045
Water Heating 0.50 kW 1.26 kW - -
NWPC Electric Resistance Grid-Ready
Summer/Winter Impact, General Service is 2.52x
that of Residential based on DLC Central AC
Residential to C&I ratio
Smart
Thermostats
DLC Heating
1.09 kW 1.35 kW - - NWPC Smart thermostat heating assumption
(east)
Smart
Thermostats
DLC Cooling
0.50 kW 1.25 kW - -
NWPC DLC Switch cooling assumption was close
to 1.0 kW reduced to adjust for Avista proposed
cycling strategy
Smart
Appliances DLC 0.14 kW 0.14 kW - -
Ghatikar, Rish. Demand Response Automation in
Appliance and Equipment. Lawrence Berkley
National Laboratory, 2017.
Third Party
Contracts - 10% 21% 21%
Impact Estimates from Aggregator Programs in
California (Source: 2012 Statewide Load Impact
Evaluation of California Aggregator Demand Response Programs Volume 1: Ex post and Ex
ante Load Impacts; Christensen Associates Energy
Consulting; April 1, 2013).
Electric Vehicle
DLC Smart
Chargers
0.50 kW - - - Avista EVSE DR Pilot Program and other Avista
research
Time-of-Use
Pricing Opt-in 5.7% 0.2% 2.6% 3.1% Best estimate based on industry experience;
Winter impacts ½ of summer impacts Time-of-Use
Pricing Opt-out 3.4% 0.2% 2.6% 3.1%
Variable Peak
Pricing 10% 4% 4% 4% OG&E 2019 Smart Hours Study; Summer Impacts
Shown (Winter impacts ¾ summer)
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DSM Option Residential General
Service
Large
General
Service
Extra
Large
General
Service
Basis for Assumption
Thermal Energy
Storage 1.68 kW 8.4 kW 8.4 kW
Ice Bear Tech Specifications, https://www.ice-
energy.com/wp-content/uploads/2016/03/ICE-
BEAR-30-Product-Sheet.pdf
Battery Energy
Storage 2 kW 2 kW 15 kW 15 kW Typical Battery size per segment
Behavioral 2% - - - Opower documentation for BDR with Consumers
and Detroit Energy
Program Costs
Table 6-11 shows the annual marketing, recruitment, incentives, and program development costs associated with each DSM option.
Table 6-12 presents itemized cost assumptions for the DSM Options and the basis for the assumptions for the state of Washington. Table 6-11 shows the annual O&M costs per participant and per MW (Third Party Contracts only) and the Cost of Equipment and installation per participant and per kW (Thermal Energy Storage only).
Table 6-11 DSM Program Operations Maintenance, and Equipment Costs (Washington)
DSM Option Annual O&M Cost Per Participant Annual O&M
Cost per MW
Cost of Equip
+ Install Per
Participant
Cost of Equip
+ Install per
kW
DLC Central AC $13.00 $260.00 $0.00

CTA-2045 Water Heating $0.00 $170.00 $0.00
DLC Smart Thermostats – Heating $44.00 $0.00 $0.00
DLC Smart Thermostats - Cooling $44.00 $0.00 $0.00
DLC Smart Appliances $0.00 $300.00 $0.00
Third Party Contracts $0.00 $80,000.00 $0.00 $0.00

Time-of-Use Opt-in $0.00 $0.00 $0.00
Time-of-Use Opt-out $0.00 $0.00 $0.00
Variable Peak Pricing Rates $0.00 $0.00 $0.00
Thermal Energy Storage $308.00 $0.00 $6,160.00
Battery Energy Storage $0.00 $27,897.60 $0.00
Behavioral $3.25 $0.00 $0.00
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Table 6-12 shows the annual marketing, recruitment, incentives, and program development costs associated with each DSM option.
Table 6-12 Marketing, Recruitment, Incentive, and Development Costs (Washington)
DSM Option Annual Marketing/Recruitment
Cost Per Participant
Annual
Incentive Per
Participant
Program
Development
Cost

CTA-2045 Water Heating $67.50 $24.00 $75,000.00
DLC Smart Thermostats - Heating $67.50 $20.00 $23,963.15
DLC Smart Thermostats - Cooling $67.50 $20.00 $23,863.32
DLC Smart Appliances $50.00 $0.00 $24,084.70
Third Party Contracts $0.00 $0.00 $0.00

Time-of-Use Opt-in $57.50 $0.00 $12,315.14
Time-of-Use Opt-out $57.50 $0.00 $12,281.26
Variable Peak Pricing Rates $175.00 $0.00 $12,222.26
Thermal Energy Storage $100.00 $0.00 $14,994.78
Battery Energy Storage $25.00 $0.00 $8,017.36
Table 6-13 and Table 6-14 present the equivalent cost tables for the state of Idaho.
Table 6-13 DSM Program Operations Maintenance, and Equipment Costs (Idaho)
DSM Option Annual O&M Cost Per Participant Annual O&M
Cost per MW
Cost of Equip
+ Install Per
Participant
Cost of Equip
+ Install per
kW
DLC Central AC $13.00 $260.00 $0.00
DLC Water Heating $23.63 $472.50 $0.00
DLC Smart Thermostats – Heating $44.00 $0.00 $0.00
DLC Smart Thermostats - Cooling $44.00 $0.00 $0.00
DLC Smart Appliances $0.00 $300.00 $0.00
Third Party Contracts $0.00 $80,000.00 $0.00 $0.00

Time-of-Use Opt-in $0.00 $0.00 $0.00
Time-of-Use Opt-out $0.00 $0.00 $0.00
Variable Peak Pricing Rates $0.00 $0.00 $0.00
Thermal Energy Storage $308.00 $0.00 $6,160.00
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Battery Energy Storage $0.00 $27,897.60 $0.00
Behavioral $3.25 $0.00 $0.00

Table 6-14 Marketing, Recruitment, Incentive, and Development Costs (Idaho)
DSM Option
Annual
Marketing/Recruitmen
t Cost Per Participant
Annual Incentive Per
Participant
Program Development
Cost
DLC Central AC $67.50 $29.00 $13,636.68

DLC Smart
Thermostats - Heating $67.50 $20.00 $13,536.85
DLC Smart
Thermostats - Cooling $67.50 $20.00 $13,636.68

Third Party Contracts $0.00 $0.00 $0.00
DLC Electric Vehicle
Charging $50.00 $24.00 $25,864.40
Time-of-Use Opt-in $69.00 $0.00 $6,434.86
Time-of-Use Opt-out $69.00 $0.00 $6,468.74
Variable Peak Pricing
Rates $175.00 $0.00 $6,527.74
Thermal Energy
Storage $100.00 $0.00 $10,005.22
Battery Energy Storage $25.00 $0.00 $4,482.64
Behavioral $0.00 $0.00 $33,944.32

Other Cross-cutting Assumptions
In addition to the above program-specific assumptions, there are three that affect all programs:
• Discount rate. We used a nominal discount rate of 5.21% to calculate the net present value (NPV) of costs over the useful life of each DR program. All cost results are shown in nominal dollars.
• Line losses. Avista provided a line loss factor of 6.16% to convert estimated demand savings at the customer meter level to demand savings at the generator level. In the next section, we report our analysis results at the generator level.
• S hifting 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. However, shifting and savings assumptions were provided to Avista for each program to inform the IRP results.
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DR Potential and Cost Estimates
This section presents analysis results on demand savings and cost estimates for DR programs. We developed savings estimates in two ways:
• First, we present the integrated results. If Avista offers more than one program, then the potential for double counting exists. To address this possibility, we created a participation hierarchy to define the order in which the programs are taken by customers. Then we computed the savings and costs under this scenario. For this study, we assumed a customer would not be on both a Central AC program and a Smart Thermostat program and would only be on a thermal energy storage program or battery energy storage program. The hierarchy of pricing rates is as follows: Time-of-Use, Variable Peak Pricing, and Real Time Pricing.
• At the very end of this section, we present high-level standalone results in 2045 without considering the integrated effects that occur if more than one DR option is offered to Avista customers. Standalone results represent an upper bound for each program individually and should not be added together as that would overstate the overall system level potential.
All potential results presented in this section represent capacity savings in terms of equivalent generation capacity.
Integrated Potential Results
The following sections separate out the integrated potential results for winter and summer for the Time-of-Use Opt-in and Time-of-Use Opt-out scenarios.
Winter TOU Opt-in Scenario
Figure 6-3 and Table 6-15 show the total winter demand savings from individual DR options for selected years of the analysis. These savings represent integrated savings from all available DR options in Avista’s Washington and Idaho service territories.
Key findings include:
• The highest potential option is CTA-2045 WH which is expected to reach a savings potential of 48.9 MW by 2045.
• The next three biggest potential options in winter include DLC Electric Vehicle Charging (30.2 MW in 2045), Third Part Contracts (21.9 MW), and Variable Peak Pricing Rates (12.0 MW)
• Since most of the participants are likely to be on the VPP pricing rate in the TOU Opt-in scenario, the TOU potential (4.1 MW in 2045) is significantly lower than in the Opt-out case (17.8 MW).
• The total potential savings in the winter TOU Opt-in scenario are expected to increase from 9.3 MW in 2022 to 144.3 MW by 2045. The respective increase in the percentage of system peak goes from 0.7% in 2022 to 10.0% by 2045.
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Figure 6-3 Summary of Potential Analysis for Avista (TOU Opt-In Winter Peak MW @Generator)

Table 6-15 Achievable DR Potential by Option (TOU Opt-In Winter MW @Generator)
2022 2023 2025 2035 2045
Total System Peak (MW) 1,331 1,337 1,349 1,403 1,444
Market Potential (MW) 9.3 24.6 63.9 98.8 144.3
Market Potential (% of baseline) 0.7% 1.8% 4.7% 7.0% 10.0%
Achievable Potential (MW)
Battery Energy Storage 0.1 0.2 0.7 5.0 5.6
Behavioral 0.6 1.2 2.5 2.0 1.6
CTA-2045 WH 0.1 0.3 1.7 26.3 48.9
DLC Central AC - - - - -
DLC Smart Appliances 0.3 0.9 2.7 3.3 3.7
DLC Smart Thermostats - Cooling - - - - -
DLC Smart Thermostats - Heating 0.9 2.6 8.0 9.8 10.9
DLC Water Heating 0.5 1.6 4.9 5.5 5.5
Thermal Energy Storage - - - - -
Third Party Contracts 4.6 10.0 21.9 21.8 21.9
Time-of-Use Opt-in 0.5 1.8 5.3 4.9 4.1
-
20
40
60
80
100
120
140
160
2022 2023 2025 2035 2045
Ac
h
i
e
v
a
b
l
e

P
o
t
e
n
t
i
a
l

(
M
W
)
Variable Peak Pricing
RatesTime-of-Use Opt-out
Time-of-Use Opt-in
Third Party Contracts
Thermal Energy Storage
DLC Water Heating
DLC Smart Thermostats -
HeatingDLC Smart Thermostats -
CoolingDLC Smart Appliances
DLC Electric Vehicle
ChargingDLC Central AC
CTA-2045 WH
Behavioral
Battery Energy Storage
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Time-of-Use Opt-out - - - - -
Variable Peak Pricing Rates 1.8 5.9 15.9 14.5 12.0
Achievable Potential (% of Baseline)
Battery Energy Storage 0.01% 0.02% 0.05% 0.36% 0.38%
Behavioral 0.04% 0.09% 0.18% 0.14% 0.11%
CTA-2045 WH 0.00% 0.02% 0.12% 1.88% 3.38%
DLC Central AC
DLC Electric Vehicle Charging 0.02% 0.40% 2.09%
DLC Smart Appliances 0.02% 0.07% 0.20% 0.24% 0.26%
DLC Smart Thermostats - Cooling
DLC Water Heating 0.04% 0.12% 0.37% 0.39% 0.38%
Thermal Energy Storage
Time-of-Use Opt-in 0.04% 0.13% 0.39% 0.35% 0.28%
Time-of-Use Opt-out
Variable Peak Pricing Rates 0.14% 0.44% 1.18% 1.03% 0.83%
Table 6-16 and Table 6-17 show demand savings by individual DR option for the states of Washington and Idaho separately. Using the available DSM options, Washington is projected to save 105.27 MW (7.2% of winter system peak demand) by 2045 while Idaho is projected to save 39.03 MW (2.67% of winter system peak demand) by 2045.
Table 6-16 Achievable DR Potential by Option for Washington (TOU Opt-In Winter MW @Generator)
2022 2023 2025 2035 2045
Total System Peak (MW) 1,331 1,337 1,349 1,403 1,463
Market Potential (MW) 6.91 16.53 39.46 69.22 105.27
Market Potential (% of System Peak) 0.5% 1.2% 2.9% 4.9% 7.2%
Battery Energy Storage 0.06 0.18 0.48 3.25 3.54
Behavioral 0.49 0.94 1.69 1.21 0.82
CTA-2045 WH 0.05 0.33 1.67 26.33 48.86
DLC Central AC - - - - -
DLC Smart Appliances 0.19 0.58 1.77 2.15 2.35
DLC Smart Thermostats - Cooling - - - - -
DLC Smart Thermostats - Heating 0.57 1.71 5.23 6.37 6.97
DLC Water Heating - - - - -
Thermal Energy Storage - - - - -
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Third Party Contracts 3.55 7.10 14.20 14.23 14.31
Time-of-Use Opt-in 0.46 1.34 3.57 3.07 2.32
Time-of-Use Opt-out - - - - -
Variable Peak Pricing Rates 1.54 4.36 10.66 8.96 6.63

Table 6-17 Achievable DR Potential by Option for Idaho (TOU Opt-In Winter MW @Generator)
2022 2023 2025 2035 2045
Total System Peak (MW) 1,331 1,337 1,349 1,403 1,463
Market Potential (MW) 2.43 8.09 24.43 29.63 39.03
Market Potential (% of System Peak) 0.18% 0.61% 1.81% 2.11% 2.67%
Achievable Potential (MW)
Battery Energy Storage 0.01 0.06 0.26 1.80 2.02
Behavioral 0.08 0.30 0.79 0.76 0.74
CTA-2045 WH - - - - -
DLC Electric Vehicle Charging - - 0.11 1.95 10.75
DLC Smart Appliances 0.10 0.31 0.95 1.19 1.35
DLC Smart Thermostats - Cooling - - - - -
DLC Smart Thermostats - Heating 0.29 0.89 2.74 3.44 3.89
DLC Water Heating 0.55 1.64 4.93 5.49 5.52
Third Party Contracts 1.02 2.93 7.69 7.60 7.58
Time-of-Use Opt-in 0.09 0.45 1.72 1.84 1.79
Time-of-Use Opt-out - - - - -
Variable Peak Pricing Rates 0.29 1.50 5.25 5.55 5.39
Cost Results
Table 6-18 presents the levelized costs per kW of equivalent generation capacity over 2022-2031 for both Washington and Idaho as well as the system weighted average levelized costs across both states. In addition, we show the 2031 savings potential from DR options for reference purposes.
Key findings include:
• The Third Party Contracts option delivers the highest savings in 2031 at approximately $75.26/kW-year cost. 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.
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• The Variable Peak Pricing option has lowest levelized cost among all the DR options. It delivers 16.14 MW of savings in 2031 at $39.34/kW-year system wide. Enabling technology purchase and installation costs for enhancing customer response is a large part of CPP deployment costs.

Table 6-18 DR Program Costs and Potential (TOU Opt-In Winter)
DR Option WA ID System Wtd Avg Levelized
$/kW (2022-2031)
System Winter Potential
MW in Year 2031
Battery Energy Storage $833.17 $849.86 $839.87 2.81
Behavioral $158.42 $172.77 $161.07 2.26
CTA-2045 WH $174.13 $174.13 17.36
DLC Central AC -
DLC Electric Vehicle Charging $449.91 $452.04 $450.67 2.85
DLC Smart Appliances $398.04 $401.96 $399.70 3.21
DLC Smart Thermostats - Cooling -
DLC Smart Thermostats - Heating $76.79 $77.74 $77.19 9.42
DLC Water Heating $239.74 $239.74 5.48
Thermal Energy Storage -
Time-of-Use Opt-in $78.12 $97.73 $84.82 5.46
Time-of-Use Opt-out -
Variable Peak Pricing Rates $38.26 $40.90 $39.34 16.14

Winter TOU Opt-out Scenario
Figure 6-4 and Table 6-19 show the total winter demand savings from individual DR options for selected years of the analysis. These savings represent integrated savings from all available DR options in Avista’s Washington and Idaho service territories.
Key findings include:
• Once again the largest potential is in CTA-2045 WH, at 48.9 MW by 2045.
• After CTA-2045 WH, the next three biggest potential options in winter include DLC Electric Vehicle Charging (30.2 MW in 2045), Third Party Contracts (21.9 MW), and TOU (17.8 MW).
• In the TOU opt-out scenario, customers are placed on the Time-of-Use rate by default and will need to go through an added step to switch rates. Therefore, the majority of savings among the rates are concentrated in TOU which is expected to reach 17.8 MW by 2045.
• In the Opt-out scenario, most of the participants are likely to be on the TOU pricing rate and we see a much lower savings potential for the VPP rate (4.0 MW by 2045).
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• The total potential savings in the winter TOU Opt-out scenario are expected to increase from 36.4 MW in 2022 to 150.1 MW by 2045. The respective increase in the percentage of system peak increases from 2.7% in 2022 to 10.4% by 2045.
Figure 6-4 Summary of Winter Potential Analysis for Avista (TOU Opt-Out MW @Generator)

Table 6-19 Achievable DR Potential by Option – TOU Opt-Out (Winter MW @Generator)
2022 2023 2025 2035 2045
Total System Peak (MW) 1,331 1,337 1,349 1,403 1,444
Market Potential (MW) 36.4 45.3 71.1 104.5 150.1
Market Potential (% of baseline) 2.7% 3.4% 5.3% 7.4% 10.4%
Potential Forecast 1,294 1,291 1,278 1,299 1,294

Behavioral 0.6 1.3 2.5 2.1 1.7
CTA-2045 WH 0.1 0.3 1.7 26.3 48.9
DLC Central AC - - - - -
DLC Electric Vehicle Charging - - 0.3 5.6 30.2
DLC Smart Appliances 0.3 0.9 2.7 3.3 3.7
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Variable Peak Pricing Rates
Time-of-Use Opt-out
Time-of-Use Opt-in
Third Party Contracts
Thermal Energy Storage
DLC Water Heating
DLC Smart Thermostats -
HeatingDLC Smart Thermostats -
CoolingDLC Smart Appliances
DLC Electric Vehicle Charging
DLC Central AC
CTA-2045 WH
Behavioral
Battery Energy Storage
Avista Corp.2021 Electric IRP Appendices 946
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DLC Smart Thermostats - Cooling - - - - -
DLC Smart Thermostats - Heating 0.9 2.6 8.0 9.8 10.9
DLC Water Heating 0.5 1.6 4.9 5.5 5.5
Thermal Energy Storage - - - - -
Third Party Contracts 4.6 10.0 21.9 21.8 21.9
Time-of-Use Opt-in - - - - -
Time-of-Use Opt-out 29.3 27.0 23.7 20.3 17.8
Variable Peak Pricing Rates 0.2 1.3 4.6 4.7 4.0
Achievable Potential (% of Baseline)
Battery Energy Storage 0.01% 0.02% 0.05% 0.36% 0.38%
CTA-2045 WH 0.00% 0.02% 0.12% 1.88% 3.38%
DLC Central AC
DLC Electric Vehicle Charging 0.02% 0.40% 2.09%
DLC Smart Appliances 0.02% 0.07% 0.20% 0.24% 0.26%
DLC Smart Thermostats - Heating 0.06% 0.19% 0.59% 0.70% 0.75%
DLC Water Heating 0.04% 0.12% 0.37% 0.39% 0.38%
Thermal Energy Storage
Third Party Contracts 0.34% 0.75% 1.62% 1.56% 1.52%
Time-of-Use Opt-in
Variable Peak Pricing Rates 0.01% 0.10% 0.34% 0.33% 0.28%

Table 6-20 and Table 6-21 show demand savings by individual DR option for the states of Washington and Idaho separately.
Table 6-20 Achievable DR Potential by Option for Washington - TOU Opt-Out (MW @Generator)
2022 2023 2025 2035 2045
Total System Peak (MW) 1,331 1,337 1,349 1,403 1,463
Market Potential (MW) 29.20 31.62 44.49 73.31 109.61
Market Potential (% of System Peak) 2.2% 2.4% 3.3% 5.2% 7.5%
Achievable Potential (MW)
Battery Energy Storage 0.06 0.18 0.48 3.25 3.54
Avista Corp.2021 Electric IRP Appendices 947
Avista Conservation Potential Assessment for 2022-2045| Market Profiles

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Applied Energy Group • www.appliedenergygroup .c om

CTA-2045 WH 0.05 0.33 1.67 26.33 48.86
DLC Central AC - - - - -
DLC Electric Vehicle Charging - - 0.20 3.65 19.47
DLC Smart Appliances 0.19 0.58 1.77 2.15 2.35
DLC Smart Thermostats - Cooling - - - - -
DLC Smart Thermostats - Heating 0.57 1.71 5.23 6.37 6.97
DLC Water Heating - - - - -
Thermal Energy Storage - - - - -
Time-of-Use Opt-out 24.29 20.07 16.07 13.05 10.79
Variable Peak Pricing Rates 0.02 0.71 3.13 2.95 2.32

Table 6-21 Achievable DR Potential by Option for Idaho – TOU Opt-Out (MW @Generator)
2022 2023 2025 2035 2045
Market Potential (% of System Peak) 0.54% 1.03% 1.97% 2.22% 2.77%
Achievable Potential (MW)
Battery Energy Storage 0.01 0.06 0.26 1.80 2.02
Behavioral 0.08 0.30 0.79 0.76 0.74
CTA-2045 WH - - - - -
DLC Electric Vehicle Charging - - 0.11 1.95 10.75
DLC Smart Appliances 0.10 0.31 0.95 1.19 1.35
DLC Smart Thermostats - Cooling - - - - -
DLC Smart Thermostats - Heating 0.29 0.89 2.74 3.44 3.89
DLC Water Heating 0.55 1.64 4.93 5.49 5.52
Thermal Energy Storage - - - - -
Time-of-Use Opt-out 5.00 6.93 7.62 7.20 6.99
Variable Peak Pricing Rates 0.16 0.64 1.49 1.70 1.66
Cost Results
Table 6-22 presents the levelized costs per kW of equivalent generation capacity over 2022-2031 for both Washington and Idaho as well as the system weighted average levelized costs across both states. In addition, we show the 2031 savings potential from DR options for reference purposes.
Key findings include:
Avista Corp.2021 Electric IRP Appendices 948
Avista Conservation Potential Assessment for 2022-2045| Market Profiles

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Applied Energy Group • www.appliedenergygroup .c om

• The Third Party Contracts option delivers the highest savings potential of 21.83 MW in 2031 at approximately $75.26/kW-year cost. 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 TOU Opt-out option has the second highest potential to contribute 21.34 MW of savings in 2031 at approximately $99.84/kW-year
• The Variable Peak Pricing option has lowest levelized cost among all the DR options. It delivers 4.95 MW of savings in 2031 at $59.11/kW-year system wide. Enabling technology purchase and installation costs for enhancing customer response is a large part of VPP deployment costs.

Table 6-22 DR Program Costs and Potential – TOU Opt Out Winter
DR Option WA ID System Wtd Avg Levelized
$/kW (2022-2031)
System Winter Potential
MW in Year 2031
Battery Energy Storage $833.17 $849.86 $839.87 2.81
Behavioral $154.99 $172.77 $172.77 2.26
CTA-2045 WH $174.13 $174.13 17.36
DLC Central AC -
DLC Electric Vehicle Charging $449.91 $452.04 $450.67 2.85
DLC Smart Appliances $398.04 $401.96 $399.70 3.21
DLC Smart Thermostats - Cooling -
DLC Smart Thermostats - Heating $76.79 $77.74 $77.19 9.42
DLC Water Heating $239.74 $239.74 5.48
Thermal Energy Storage -
Third Party Contracts $75.36 $75.07 $75.26 21.83
Time-of-Use Opt-in -
Time-of-Use Opt-out $97.99 $103.41 $99.84 21.34
Variable Peak Pricing Rates $58.72 $59.77 $59.11 4.95

Summer TOU Opt-in Scenario
Figure 6-5 and Table 6-23 show the total summer demand savings from individual DR options for selected years of the analysis. These savings represent integrated savings from all available DR options in Avista’s Washington and Idaho service territories.
Key findings include:
• The highest potential option is DLC Smart Thermostats, which is expected to reach savings potential of 61 MW by 2045.
Avista Corp.2021 Electric IRP Appendices 949
Avista Conservation Potential Assessment for 2022-2045| Market Profiles

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Applied Energy Group • www.appliedenergygroup .c om

• The next two biggest potential options in summer include CTA-2045 WH (48.9 MW in 2045), DLC Electric Vehicle Charging (30.2 MW), and DLC Central AC (24.5 MW).
• Two Space cooling options- DLC Smart Thermostat and DLC Central AC – are expected to contribute a combined 85.5 MW by 2045.
• Total potential savings in the summer TOU Opt-in scenario are expected to increase from 11.3 MW in 2022 to 232 MW by 2045. The respective increase in the percentage of system peak increases from 0.8% in 2022 to 15.4% by 2045.
Figure 6-5 Summary of Summer Potential by Option (TOU Opt-In MW @Generator)

Table 6-23 Achievable DR Potential by Option TOU Opt-In (Summer MW @Generator)
2022 2023 2025 2035 2045
Total System Peak (MW) 1,369 1,376 1,389 1,446 1,508
Market Potential (MW) 11.3 31.3 86.8 151.9 232.0
Market Potential (% of baseline) 0.8% 2.3% 6.3% 10.5% 15.4%
Potential Forecast 1,358 1,344 1,302 1,294 1,276
Achievable Potential (MW)
Battery Energy Storage 0.1 0.2 0.7 5.0 5.6
Behavioral 0.6 1.3 2.6 2.1 1.7
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Time-of-Use Opt-in
Third Party Contracts
Thermal Energy
StorageDLC Water Heating
DLC Smart
Thermostats - HeatingDLC Smart
Thermostats - CoolingDLC Smart Appliances
DLC Electric Vehicle
ChargingDLC Central AC
CTA-2045 WH
Behavioral
Battery Energy Storage
Avista Corp.2021 Electric IRP Appendices 950
Avista Conservation Potential Assessment for 2022-2045| Market Profiles

| A-29
Applied Energy Group • www.appliedenergygroup .c om

CTA-2045 WH 0.1 0.3 1.7 26.3 48.9
DLC Central AC 0.8 2.5 8.1 16.2 24.5
DLC Electric Vehicle Charging - - 0.3 5.6 30.2
DLC Smart Appliances 0.3 0.9 2.7 3.3 3.7
DLC Smart Thermostats - Cooling 1.6 5.1 17.4 37.4 61.0
DLC Smart Thermostats - Heating - - - - -
DLC Water Heating 1.0 2.9 9.1 13.7 17.8
Thermal Energy Storage 0.1 0.2 0.6 0.7 0.6
Third Party Contracts 4.5 9.8 21.4 21.3 21.4
Time-of-Use Opt-in 0.6 1.9 5.5 5.1 4.3
Variable Peak Pricing Rates 1.9 6.1 16.7 15.1 12.5
Achievable Potential (% of Baseline)
Battery Energy Storage 0.01% 0.02% 0.05% 0.36% 0.38%
Behavioral 0.04% 0.09% 0.18% 0.14% 0.11%
DLC Central AC 0.06% 0.18% 0.58% 1.12% 1.62%
DLC Electric Vehicle Charging 0.02% 0.39% 2.00%
DLC Smart Appliances 0.02% 0.06% 0.20% 0.23% 0.25%
DLC Smart Thermostats - Cooling 0.12% 0.37% 1.25% 2.58% 4.04%
DLC Smart Thermostats - Heating
Thermal Energy Storage 0.00% 0.01% 0.05% 0.05% 0.04%
Third Party Contracts 0.33% 0.71% 1.54% 1.48% 1.42%
Time-of-Use Opt-in 0.04% 0.14% 0.40% 0.35% 0.28%
Time-of-Use Opt-out
Variable Peak Pricing Rates 0.14% 0.45% 1.20% 1.05% 0.83%

Table 6-24 and Table 6-25 show demand savings by individual DR option for the states of Washington and Idaho separately.
Table 6-24 Achievable DR Potential by Option for Washington TOU Opt-In (Summer MW @Generator)
2022 2023 2025 2035 2045
Total System Peak (MW) 1,369 1,376 1,389 1,446 1,508
Avista Corp.2021 Electric IRP Appendices 951
Avista Conservation Potential Assessment for 2022-2045| Market Profiles

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Applied Energy Group • www.appliedenergygroup .c om

Market Potential (MW) 8.37 21.28 55.63 105.72 164.59
Market Potential (% of System Peak) 0.6% 1.5% 4.0% 7.3% 10.9%
Achievable Potential (MW)
Battery Energy Storage 0.06 0.18 0.48 3.25 3.54
Behavioral 0.52 1.02 1.81 1.31 0.88
CTA-2045 WH 0.05 0.33 1.67 26.33 48.86
DLC Central AC 0.50 1.59 5.18 10.25 15.34
DLC Electric Vehicle Charging - - 0.20 3.65 19.47
DLC Smart Appliances 0.19 0.58 1.77 2.15 2.35
DLC Smart Thermostats - Cooling 1.02 3.25 11.12 23.68 38.26
DLC Water Heating 0.40 1.28 4.15 8.20 12.26
Thermal Energy Storage 0.05 0.13 0.39 0.40 0.36
Third Party Contracts 3.46 6.92 13.84 13.88 13.96
Time-of-Use Opt-in 0.49 1.41 3.76 3.22 2.41
Variable Peak Pricing Rates 1.63 4.60 11.26 9.41 6.91

Table 6-25 Achievable DR Potential by Option for Idaho TOU Opt-In (Summer MW @Generator)
2022 2023 2025 2035 2045
Total System Peak (MW) 1,369 1,376 1,389 1,446 1,508
Market Potential (% of System Peak) 0.22% 0.72% 2.25% 3.20% 4.47%
Battery Energy Storage 0.01 0.06 0.26 1.80 2.02
Behavioral 0.08 0.31 0.83 0.80 0.78
CTA-2045 WH - - - - -
DLC Central AC 0.28 0.89 2.90 5.92 9.11
DLC Electric Vehicle Charging - - 0.11 1.95 10.75
DLC Smart Appliances 0.10 0.31 0.95 1.19 1.35
DLC Smart Thermostats - Cooling 0.56 1.81 6.24 13.67 22.72
DLC Smart Thermostats - Heating - - - - -
DLC Water Heating 0.55 1.64 4.93 5.49 5.52
Thermal Energy Storage 0.01 0.06 0.24 0.27 0.27
Avista Corp.2021 Electric IRP Appendices 952
Avista Conservation Potential Assessment for 2022-2045| Market Profiles

| A-31
Applied Energy Group • www.appliedenergygroup .c om

Third Party Contracts 1.00 2.88 7.55 7.47 7.46
Time-of-Use Opt-in 0.09 0.46 1.77 1.90 1.85
Time-of-Use Opt-out - - - - -
Variable Peak Pricing Rates 0.30 1.55 5.42 5.73 5.57
Cost Results
Table 6-26 presents the levelized costs per kW of equivalent generation capacity over 2022-2031 for both Washington and Idaho as well as the system weighted average levelized costs across both states. In addition, we show the 2031 savings potential from DR options for reference purposes.
Key findings include:
• DLC Smart Thermostats deliver the highest savings in 2031 (28.68 MW) at approximately $127.27/kW-year cost. 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 16.89 MW of savings in 2031 at $37.51/kW-year system wide. Enabling technology purchase and installation costs for enhancing customer response is a large part of CPP deployment costs.
Table 6-26 DR Program Costs and Potential – Summer TOU Opt-In
DR Option WA ID System Wtd Avg Levelized
$/kW (2022-2031)
System Summer Potential
MW in Year 2031
Behavioral $143.96 $164.86 $151.82 2.41
CTA-2045 WH $174.13 $174.13 17.36
DLC Central AC $161.09 $156.97 $159.34 12.80
DLC Electric Vehicle Charging $449.91 $452.04 $450.67 2.85
DLC Smart Appliances $398.04 $401.96 $399.70 3.21
DLC Smart Thermostats - Heating -
DLC Water Heating $239.74 $239.74 5.48
Thermal Energy Storage $1,000.92 $957.45 $983.76 0.68
Third Party Contracts $77.29 $76.39 $76.97 21.35
Time-of-Use Opt-in $74.13 $94.63 $81.21 5.71
Variable Peak Pricing Rates $36.25 $39.64 $37.51 16.89

Avista Corp.2021 Electric IRP Appendices 953
Avista Conservation Potential Assessment for 2022-2045| Market Profiles

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Applied Energy Group • www.appliedenergygroup .c om

Summer TOU Opt-out Scenario
Figure 6-6 and Table 6-27 show the total summer demand savings from individual DR options for selected years of the analysis. These savings represent integrated savings from all available DR options in Avista’s Washington and Idaho service territories.
Key findings include:
• Once again the highest savings potential resides in DLC Smart Thermostats, increasing from 1.6 MW in 2022 to 61.0 MW in 2045.
• The next two biggest potential options in Summer include CTA-2045 WH (48.9 MW by 2045), DLC Electric Vehicle Charging (30.2 MW), and DLC Central AC (24.5 MW). DLC Smart Thermostat and DLC Central AC options together contribute 85.5 MW of potential by 2045.
• In the TOU opt-out scenario, customers are placed on the Time-of-Use rate by default and will need to go through an added step to switch rates. Therefore, the majority of savings among the rates are concentrated in TOU which is expected to reach 18.3 MW by 2045.
• In the Opt-out scenario, most of the participants are likely to be on the TOU pricing rate and we see a much lower savings potential for the VPP rate (4.1 MW by 2045).
• The total potential savings in the summer TOU Opt-in scenario are expected to increase from 39.0 MW in 2022 to 225.6 MW by 2045. The respective increase in the percentage of system peak goes from 2.8% in 2022 to 15.0% by 2045.

Figure 6-6 Summary of Summer Potential – TOU Opt-Out (MW @Generator)

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Thermostats - HeatingDLC Smart
Thermostats - CoolingDLC Smart Appliances
DLC Electric Vehicle
ChargingDLC Central AC
Avista Corp.2021 Electric IRP Appendices 954
Avista Conservation Potential Assessment for 2022-2045| Market Profiles

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Avista Corp.2021 Electric IRP Appendices 955
Avista Conservation Potential Assessment for 2022-2045| Market Profiles

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Applied Energy Group • www.appliedenergygroup .c om

Table 6-27 Achievable DR Potential by Option – TOU Opt-Out (Summer MW @Generator)
2022 2023 2025 2035 2045
Total System Peak (MW) 1,369 1,376 1,389 1,446 1,508
Market Potential (% of baseline) 2.8% 3.7% 6.5% 10.3% 15.0%
Potential Forecast 1,330 1,324 1,299 1,296 1,282
Achievable Potential (MW)
Battery Energy Storage 0.1 0.2 0.7 5.0 5.6
CTA-2045 WH 0.1 0.3 1.7 26.3 48.9
DLC Central AC 0.8 2.5 8.1 16.2 24.5
DLC Electric Vehicle Charging - - 0.3 5.6 30.2
DLC Smart Appliances 0.3 0.9 2.7 3.3 3.7
DLC Smart Thermostats - Cooling 1.6 5.1 17.4 37.4 61.0
DLC Water Heating 0.5 1.6 4.9 5.5 5.5
Thermal Energy Storage 0.1 0.2 0.6 0.7 0.6
Third Party Contracts 4.5 9.8 21.4 21.3 21.4
Time-of-Use Opt-in - - - - -
Time-of-Use Opt-out 30.4 28.0 24.6 20.9 18.3
Variable Peak Pricing Rates 0.2 1.4 4.8 4.9 4.1
Achievable Potential (% of Baseline)
Behavioral 0.04% 0.09% 0.19% 0.15% 0.12%
CTA-2045 WH 0.00% 0.02% 0.12% 1.82% 3.24%
DLC Central AC 0.06% 0.18% 0.58% 1.12% 1.62%
DLC Electric Vehicle Charging 0.02% 0.39% 2.00%
DLC Smart Appliances 0.02% 0.06% 0.20% 0.23% 0.25%
DLC Smart Thermostats - Heating
DLC Water Heating 0.04% 0.12% 0.35% 0.38% 0.37%
Thermal Energy Storage 0.00% 0.01% 0.05% 0.05% 0.04%
Third Party Contracts 0.33% 0.71% 1.54% 1.48% 1.42%
Time-of-Use Opt-in
Time-of-Use Opt-out 2.22% 2.04% 1.77% 1.45% 1.21%
Variable Peak Pricing Rates 0.01% 0.10% 0.35% 0.34% 0.27%

Table 6-28 and Table 6-29 show demand savings by individual DR option for the states of Washington and Idaho separately.
Avista Corp.2021 Electric IRP Appendices 956
Avista Conservation Potential Assessment for 2022-2045| Market Profiles

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Applied Energy Group • www.appliedenergygroup .c om

Table 6-28 Achievable DR Potential by Option for Washington – TOU Opt-Out (Summer MW @Generator)
2022 2023 2025 2035 2045
Total System Peak (MW) 1,369 1,376 1,389 1,446 1,508
Market Potential (MW) 31.19 35.70 56.62 101.68 156.75
Battery Energy Storage 0.06 0.18 0.48 3.25 3.54
Behavioral 0.53 1.03 1.88 1.44 1.06
CTA-2045 WH 0.05 0.33 1.67 26.33 48.86
DLC Central AC 0.50 1.59 5.18 10.25 15.34
DLC Electric Vehicle Charging - - 0.20 3.65 19.47
DLC Smart Appliances 0.19 0.58 1.77 2.15 2.35
DLC Smart Thermostats - Cooling 1.02 3.25 11.12 23.68 38.26
DLC Smart Thermostats - Heating - - - - -
DLC Water Heating - - - - -
Thermal Energy Storage 0.05 0.13 0.39 0.40 0.36
Third Party Contracts 3.46 6.92 13.84 13.88 13.96
Time-of-Use Opt-in - - - - -
Time-of-Use Opt-out 25.32 20.94 16.79 13.55 11.12
Variable Peak Pricing Rates 0.02 0.75 3.30 3.11 2.43

Table 6-29 Achievable DR Potential by Option for Idaho – TOU Opt-Out (Summer MW @Generator)
2022 2023 2025 2035 2045
Market Potential (% of System Peak) 0.57% 1.14% 2.40% 3.30% 4.57%
Achievable Potential (MW)
Battery Energy Storage 0.01 0.06 0.26 1.80 2.02
Behavioral 0.08 0.31 0.83 0.80 0.78
DLC Central AC 0.28 0.89 2.90 5.92 9.11
DLC Electric Vehicle Charging - - 0.11 1.95 10.75
DLC Smart Appliances 0.10 0.31 0.95 1.19 1.35
Avista Corp.2021 Electric IRP Appendices 957
Avista Conservation Potential Assessment for 2022-2045| Market Profiles

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Applied Energy Group • www.appliedenergygroup .c om

DLC Smart Thermostats - Cooling 0.56 1.81 6.24 13.67 22.72
DLC Smart Thermostats - Heating - - - - -
DLC Water Heating 0.55 1.64 4.93 5.49 5.52
Thermal Energy Storage 0.01 0.06 0.24 0.27 0.27
Third Party Contracts 1.00 2.88 7.55 7.47 7.46
Time-of-Use Opt-in - - - - -
Time-of-Use Opt-out 5.07 7.08 7.82 7.39 7.18
Variable Peak Pricing Rates 0.17 0.67 1.54 1.76 1.71
Cost Results
Table 6-30 presents the levelized costs per kW of equivalent generation capacity over 2022-2031 for both Washington and Idaho as well as the system weighted average levelized costs across both states. In addition, we show the 2031 savings potential from DR options for reference purposes.
Key findings include:
• DLC Smart Thermosts delivers the highest savings potential in 2031 (28.68 MW) at approximately $127.27/kW-year cost. 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 5.18 MW of savings in 2031 at $56.48/kW-year system wide. Enabling technology purchase and installation costs for enhancing customer response is a large part of CPP deployment costs.

Table 6-30 DR Program Costs and Potential – Summer TOU Opt-Out
DR Option WA ID System Wtd Avg Levelized
$/kW (2022-2031)
System Summer Potential
MW in Year 2031
Battery Energy Storage $833.17 $849.86 $839.87 2.81
Behavioral $143.96 $164.86 $151.02 2.41
CTA-2045 WH $174.13 $174.13 17.36
DLC Central AC $161.09 $156.97 $159.34 12.80
DLC Electric Vehicle Charging $449.91 $452.04 $450.67 2.85
DLC Smart Appliances $398.04 $401.96 $399.70 3.21
DLC Smart Thermostats - Cooling $129.24 $124.60 $127.27 28.68
DLC Smart Thermostats - Heating -
Thermal Energy Storage $1,000.92 $957.45 $983.76 0.68
Third Party Contracts $77.29 $76.39 $76.97 21.35
Avista Corp.2021 Electric IRP Appendices 958
Avista Conservation Potential Assessment for 2022-2045| Market Profiles

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Applied Energy Group • www.appliedenergygroup .c om

Time-of-Use Opt-in
Time-of-Use Opt-out $93.94 $100.94 $96.35 22.10
Variable Peak Pricing Rates $55.64 $57.91 $56.48 5.18

Stand-alone Potential Results
The above results assume that the programs are offered on an integrated basis where participation across similar options do not overlap. However, it is also important to see the potential by option where each program is unaffected by participation in other options. This way, Avista can gauge the impact from implementing an individual program. For this scenario we do not combine the potential savings and only show individual potential contributions by program for each scenario.
Winter Results
Figure 6-7 and Table 6-31 show the winter demand savings from individual DR options for selected years of the analysis. These savings represent stand-alone savings from all available DR options in Avista’s Washington and Idaho service territories.
Key findings include:
• The largest savings potential resides in CTA-2045 WH, contributing 0.1 MW of potential in 2022 and increasing to 48.9 MW by 2045.
• The next biggest option is DLC Electric Vehicle Charging, at 30.2 MW of potential by 2045.
• When each TOU option is examined as an individual program, the Time-of-Use Opt-out option has a much larger potential savings then if participants could opt-in to the rate. The TOU Opt-out option is expected to reach 29.9 MW by 2045 in the stand-alone case.
• Since the different rate options do not influence other rates in the stand-alone scenario, each rate has a larger potential savings than in the Opt-out/Opt-in scenarios.
Avista Corp.2021 Electric IRP Appendices 959
Avista Conservation Potential Assessment for 2022-2045| Market Profiles

| A-38
Applied Energy Group • www.appliedenergygroup .c om

Figure 6-8 Summary of Potential Analysis for Avista (Winter Peak MW @Generator)

Table 6-32 Achievable DR Potential by Option (Winter MW @Generator)
2022 2023 2025 2035 2045
Total System Peak (MW) 1,331 1,337 1,349 1,403 1,444
Market Potential (MW) 39.5 54.2 100.2 142.6
194.5
Market Potential (% of baseline) 3.0% 4.1% 7.4% 10.2% 13.5%
Potential Forecast 1,291 1,282 1,249 1,261 1,250
Achievable Potential (MW)
Battery Energy Storage 0.1 0.2 0.7 5.0 5.6
Behavioral 0.6 1.3 3.0 3.1 3.3
CTA-2045 WH 0.1 0.3 1.7 26.3 48.9
DLC Central AC - - - - -
DLC Electric Vehicle Charging - - 0.3 5.6 30.2
DLC Smart Appliances 0.3 0.9 2.7 3.3 3.7
DLC Smart Thermostats - Cooling - - - - -
DLC Smart Thermostats - Heating 0.9 2.6 8.0 9.8 10.9
DLC Water Heating 0.5 1.6 4.9 5.5 5.5
Thermal Energy Storage - - - - -
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Variable Peak Pricing
RatesTime-of-Use Opt-out
Time-of-Use Opt-in
Third Party Contracts
Thermal Energy Storage
DLC Water Heating
DLC Smart Thermostats -
HeatingDLC Smart Thermostats -
CoolingDLC Smart Appliances
DLC Electric Vehicle
ChargingDLC Central AC
Avista Corp.2021 Electric IRP Appendices 960
Avista Conservation Potential Assessment for 2022-2045| Market Profiles

| A-39
Applied Energy Group • www.appliedenergygroup .c om

Third Party Contracts 4.6 10.0 21.9 21.8 21.9
Time-of-Use Opt-in 0.6 1.9 6.4 7.5 7.8
Variable Peak Pricing Rates 1.9 6.5 22.0 25.7 26.9
Achievable Potential (% of Baseline)
Battery Energy Storage 0.01% 0.02% 0.05% 0.36% 0.39%
Behavioral 0.04% 0.10% 0.22% 0.22% 0.23%
CTA-2045 WH 0.00% 0.02% 0.12% 1.88% 3.38%
DLC Central AC
DLC Electric Vehicle Charging 0.02% 0.40% 2.09%
DLC Smart Thermostats - Cooling
DLC Smart Thermostats - Heating 0.06% 0.19% 0.59% 0.70% 0.75%
Thermal Energy Storage
Third Party Contracts 0.34% 0.75% 1.62% 1.56% 1.52%
Time-of-Use Opt-in 0.04% 0.14% 0.48% 0.53% 0.54%
Time-of-Use Opt-out 2.26% 2.16% 2.11% 2.06% 2.07%
Variable Peak Pricing Rates 0.14% 0.49% 1.63% 1.83% 1.86%

Table 6-33 and Table 6-34 show demand savings by individual DR option for the states of Washington and Idaho separately.
Table 6-33 Achievable DR Potential by Option for Washington (Winter MW @Generator)
2022 2023 2025 2035 2045
Total System Peak (MW) 1,331 1,337 1,349 1,403 1,463
Market Potential (MW)
31.90 38.50
63.59

99.07

140.00
Market Potential (% of System Peak) 2.4% 2.9% 4.7% 7.1% 9.6%
Achievable Potential (MW)
Battery Energy Storage 0.06 0.18 0.48 3.25 3.54
Behavioral 0.49 0.99 2.01 2.10 2.18
CTA-2045 WH 0.05 0.33 1.67 26.33 48.86
DLC Electric Vehicle Charging - - 0.20 3.65 19.47
DLC Smart Appliances 0.19 0.58 1.77 2.15 2.35
DLC Smart Thermostats - Cooling - - - - -
DLC Smart Thermostats - Heating 0.57 1.71 5.23 6.37 6.97
Avista Corp.2021 Electric IRP Appendices 961
Avista Conservation Potential Assessment for 2022-2045| Market Profiles

| A-40
Applied Energy Group • www.appliedenergygroup .c om

DLC Water Heating - - - - -
Thermal Energy Storage - - - - -
Third Party Contracts 3.55 7.10 4.20 14.23 14.31
Time-of-Use Opt-in 0.47 1.43 4.32 4.95 5.11
Time-of-Use Opt-out 24.92 21.36 19.07 19.18 19.71
Variable Peak Pricing Rates 1.60 4.83 14.65 16.88 17.49

Table 6-34 Achievable DR Potential by Option for Idaho (Winter MW @Generator)
2022 2023 2025 2035 2045
Total System Peak (MW) 1,331 1,337 1,349 1,403 1,463
Market Potential (MW) 7.59 15.74
36.63
43.52 54.53
Market Potential (% of System Peak) 0.57% 1.18% 2.71% 3.10% 3.73%
Battery Energy Storage 0.01 0.06 0.26 1.80 2.02
Behavioral 0.08 0.31 0.97 1.05 1.14
CTA-2045 WH - - - - -
DLC Central AC - - - - -
DLC Electric Vehicle Charging - - 0.11 1.95 10.75
DLC Smart Appliances 0.10 0.31 0.95 1.19 1.35
DLC Smart Thermostats - Cooling - - - - -
DLC Smart Thermostats - Heating 0.29 0.89 2.74 3.44 3.89
DLC Water Heating 0.55 1.64 4.93 5.49 5.52
Thermal Energy Storage - - - - -
Third Party Contracts 1.02 2.93 7.69 7.60 7.58
Time-of-Use Opt-in 0.09 0.48 2.12 2.50 2.66
Time-of-Use Opt-out 5.15 7.45 9.46 9.70 10.22
Summer Results
Figure 6-9 and Table 6-36 show the summer demand savings from individual DR options for selected years of the analysis. These savings represent the individual stand-alone savings from all available DR options in Avista’s Washington and Idaho service territories.
Key findings include:
• The largest potential option is DLC Smart thermostats, at 61.0 MW by 2045.
Avista Corp.2021 Electric IRP Appendices 962
Avista Conservation Potential Assessment for 2022-2045| Market Profiles

| A-41
Applied Energy Group • www.appliedenergygroup .c om

• The next two biggest potential options in summer include CTA-2045 WH and TOU Opt-out, each of which are projected to contribute over 30 MW by 2045. DLC Central AC and DLC Electric Vehicle Charging also have high savings potential by 2045.
• When each TOU option is examined as an individual program, the Time-of-Use Opt-out option has a much larger potential savings then if participants could opt-in to the rate. The TOU Opt-out option makes up the second-largest savings potential in the stand-alone case and is expected to reach 31.1 MW by 2045.
• Since the different rate options do not influence other rates in the stand-alone scenario, each rate has a larger potential savings than in the Opt-out/Opt-in scenarios.
Figure 6-9 Summary of Summer Potential by Option (MW @Generator)

Table 6-35 Achievable DR Potential by Option (Summer MW @Generator)
2022 2023 2025 2035 2045
Total System Peak (MW) 1,369 1,376 1,389 1,446 1,508
Market Potential (% of baseline) 3.1% 4.5% 9.0% 13.9% 19.5%
Potential Forecast 1,327 1,314 1,264 1,244 1,214
Battery Energy Storage 0.1 0.2 0.7 5.0 5.6
Behavioral 0.6 1.4 3.2 3.4 3.5
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RatesTime-of-Use Opt-out
Time-of-Use Opt-in
Third Party Contracts
Thermal Energy Storage
DLC Water Heating
DLC Smart Thermostats
- HeatingDLC Smart Thermostats
- CoolingDLC Smart Appliances
DLC Electric Vehicle
ChargingDLC Central AC
CTA-2045 WH
Avista Corp.2021 Electric IRP Appendices 963
Avista Conservation Potential Assessment for 2022-2045| Market Profiles

| A-42
Applied Energy Group • www.appliedenergygroup .c om

DLC Central AC 0.8 2.5 8.7 18.7 30.5
DLC Electric Vehicle Charging - - 0.3 5.6 30.2
DLC Smart Thermostats - Cooling 1.6 5.1 17.4 37.4 61.0
DLC Smart Thermostats - Heating - - - - -
DLC Water Heating 1.0 2.9 9.4 15.0 20.8
Thermal Energy Storage 0.1 0.2 0.7 0.8 0.8
Third Party Contracts 4.5 9.8 21.4 21.3 21.4
Time-of-Use Opt-in 0.6 2.0 6.7 7.8 8.1
Time-of-Use Opt-out 31.2 29.9 29.6 30.0 31.1
Achievable Potential (% of Baseline)
Battery Energy Storage 0.01% 0.02% 0.05% 0.36% 0.39%
CTA-2045 WH 0.00% 0.02% 0.12% 1.82% 3.24%
DLC Central AC 0.06% 0.18% 0.62% 1.29% 2.02%
DLC Electric Vehicle Charging 0.02% 0.39% 2.00%
DLC Smart Appliances 0.02% 0.06% 0.20% 0.23% 0.25%
DLC Smart Thermostats - Cooling 0.12% 0.37% 1.25% 2.58% 4.04%
DLC Smart Thermostats - Heating
DLC Water Heating 0.07% 0.21% 0.68% 1.04% 1.38%
Thermal Energy Storage 0.00% 0.01% 0.05% 0.05% 0.06%
Third Party Contracts 0.33% 0.71% 1.54% 1.48% 1.42%
Time-of-Use Opt-in 0.04% 0.15% 0.49% 0.54% 0.54%
Time-of-Use Opt-out 2.28% 2.17% 2.13% 2.07% 2.06%
Variable Peak Pricing Rates 0.15% 0.49% 1.66% 1.86% 1.87%

Table 6-37 and Table 6-38 show summer demand savings by individual DR option for the states of Washington and Idaho separately. The programs with the largest potential savings are CTA-2045 WH, DLC Smart Thermostat, and TOU rates.
Table 6-36 Achievable DR Potential by Option for Washington (Summer MW @Generator)
2022 2023 2025 2035 2045
Total System Peak (MW) 1,369 1,376 1,389 1,446 1,508
Market Potential (MW) 34.41 44.24 81.54 140.01 208.12
Market Potential (% of System Peak) 2.5% 3.2% 5.9% 9.7% 13.8%
Achievable Potential (MW)
Battery Energy Storage 0.06 0.18 0.48 3.25 3.54
Behavioral 0.53 1.07 2.17 2.26 2.35
Avista Corp.2021 Electric IRP Appendices 964
Avista Conservation Potential Assessment for 2022-2045| Market Profiles

| A-43
Applied Energy Group • www.appliedenergygroup .c om

CTA-2045 WH 0.05 0.33 1.67 26.33 48.86
DLC Central AC 0.51 1.63 5.56 11.84 19.13
DLC Electric Vehicle Charging - - 0.20 3.65 19.47
DLC Smart Appliances 0.19 0.58 1.77 2.15 2.35
DLC Smart Thermostats - Cooling 1.02 3.25 11.12 23.68 38.26
DLC Smart Thermostats - Heating - - - - -
DLC Water Heating 0.41 1.30 4.45 9.47 15.28
Thermal Energy Storage 0.05 0.14 0.41 0.48 0.50
Third Party Contracts 3.46 6.92 13.84 13.88 13.96
Time-of-Use Opt-in 0.50 1.50 4.55 5.22 5.39
Variable Peak Pricing Rates 1.69 5.09 15.45 17.80 18.46

Table 6-37 Achievable DR Potential by Option for Idaho (Summer MW @Generator)
2022 2023 2025 2035 2045
Total System Peak (MW) 1,369 1,376 1,389 1,446 1,508
Market Potential (MW) 8.21 17.81
43.96 61.44 85.68
Market Potential (% of System Peak) 0.60% 1.29% 3.17% 4.25% 5.68%
Achievable Potential (MW)
Battery Energy Storage 0.01 0.06 0.26 1.80 2.02
Behavioral 0.08 0.33 1.02 1.10 1.20
CTA-2045 WH - - - - -
DLC Central AC 0.28 0.91 3.12 6.84 11.36
DLC Electric Vehicle Charging - - 0.11 1.95 10.75
DLC Smart Appliances 0.10 0.31 0.95 1.19 1.35
DLC Smart Thermostats - Cooling 0.56 1.81 6.24 13.67 22.72
DLC Water Heating 0.55 1.64 4.93 5.49 5.52
Thermal Energy Storage 0.01 0.06 0.26 0.31 0.33
Third Party Contracts 1.00 2.88 7.55 7.47 7.46
Time-of-Use Opt-in 0.09 0.50 2.19 2.59 2.75
Time-of-Use Opt-out 5.22 7.61 9.71 9.97 10.51
Variable Peak Pricing Rates 0.31 1.71 7.63 9.07 9.72
Avista Corp.2021 Electric IRP Appendices 965
Avista Conservation Potential Assessment for 2022-2045| Market Profiles

| A-44
Applied Energy Group • www.appliedenergygroup .c om

Ancillary Services
Traditionally, ancillary services have been defined broadly as an option for Avista to use that stem from other DR programs at their disposal. This year, AEG wanted to provide Avista with feasible ancillary programs that are subsets of several programs defined above. AEG chose seven parent programs off of which to base ancillary options: Smart Thermostats Cooling, Smart Thermostats Heating, DLC Water Heating, CTA-2045 Water Heating, Electric Vehicle Charging, Third Party Contracts, and Battery Energy Storage. The results in this section are considered to be separate from the achievable potential discussed earlier in this chapter.
The ancillary programs were replicas of their parent programs with several exceptions. For participation, AEG assumed the same participation as the parent program for Battery Energy Storage, Electric Vehicle Charging, DLC Water Heating, and CTA-2045 Water Heating projecting that the same customers would also be eligible for an ancillary program. Participation in Third Party Contracts were based on the saturations of EMS systems for commercial customers in the PacifiCorp territory and the participation in Smart Thermostats Programs were assumed to be half of their respective parent programs.
For Impact assumptions, AEG assumed the same impacts for ancillary Battery Energy Storage, DLC Water Heating, and CTA-2045 Water Heating programs as their parent programs. For Ancillary Third Party Contracts, AEG assumed a 75% realization rate of the parent impact since there is more of a change a C&I customer will contribute less on an ancillary option. For ancillary Smart Thermostat and Electric Vehichle Charging options AEG assumed half the impacts of their respective parent programs.
Since the ancillary programs are subsets of the main programs, AEG assumed the ancillary programs would take half of the administrative and development costs of the parent programs to implement. In addition, to avoid double counting, equipment costs and O&M costs are assumed to be zero for the ancillary programs. The ancillary programs assume the same annual marketing and recruitment costs and incentive costs as the parent programs.
Winter Results
Table 6-40 and Figure 6-11 show the winter demand savings from individual DR options for selected years of the analysis. These savings represent stand-alone savings from all available DR options in Avista’s Washington and Idaho service territories.
Table 6-38 Achievable DR Potential by Ancillary Option (Winter MW @Generator)
2022 2023 2025 2035 2045
Ancillary Battery Storage 0.1 0.2 0.7 5.0 5.6
Ancillary Cooling - - - - -
Ancillary EV - - 0.2 2.8 15.1
Ancillary Heating 0.2 0.7 2.0 2.5 2.7
Ancillary Third Party 0.7 1.5 3.3 3.3 3.3
Ancillary DLC WH 0.5 1.6 4.9 5.5 5.5
Avista Corp.2021 Electric IRP Appendices 966
Avista Conservation Potential Assessment for 2022-2045| Market Profiles

| A-45
Applied Energy Group • www.appliedenergygroup .c om

Figure 6-10 Achievable DR Potential by Ancillary Option (Winter MW @Generator)

For winter ancillary potential, the Ancillary CTA-2045 Water Heater Program is expected to have the highest potential by 2031 (13.91 MW), reaching 48.9 MW by 2045. This is due to the fact that full participation and impacts are assumed for this ancillary program. Ancillary EV has the second most potential and is expected to reach 1.43 MW by 2031 and 15.1 MW by 2045.
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Ancillary Heating
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Ancillary Cooling
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Avista Corp.2021 Electric IRP Appendices 967
Avista Conservation Potential Assessment for 2022-2045| Market Profiles

| A-46
Applied Energy Group • www.appliedenergygroup .c om

Table 6-39 Winter Levelized Costs for Ancillary Options
Class DR Option WA ID
(2022-2031)
System Winter
Year 2031
Residential
Ancillary Battery Storage $91.29 $94.85
Ancillary Cooling
Ancillary EV $275.23 $275.76
Ancillary Heating $75.10 $75.98
Ancillary Third Party
Ancillary CTA-2045 WH $101.25
Ancillary DLC WH $87.27 $
C&I
Ancillary Battery Storage $89.74 $94.46
Ancillary Cooling
Ancillary EV
Ancillary Heating $198.09 $197.74
Ancillary Third Party $37.68 $37.54
Ancillary CTA-2045 WH $43.51
Ancillary DLC WH $42.99 $
The levelized costs are calculated using a ten year horizon between 2022 and 2031. Table 6-39 splits these out by residential and C&I sectors. On average, Ancillary Third Party Contracts are the cheapest option at a cost of $37.63 per kW while Ancillary Electric Vehicle Charging is the most expensive option at a cost of $275.41 per kW.
Table 6-40 Achievable DR Potential by Ancillary Option (Summer MW @Generator)
2022 2023 2025 2035 2045
Ancillary Battery Storage 0.1 0.2 0.7 5.0 5.6
Ancillary Cooling 0.4 1.3 4.3 9.3 15.2
Ancillary EV - - 0.2 2.8 15.1
Ancillary Heating - - - - -
Ancillary CTA-2045 WH 0.1 0.3 1.7 26.3 48.9
Ancillary DLC WH 0.5 1.6 4.9 5.5 5.5
Avista Corp.2021 Electric IRP Appendices 968
Avista Conservation Potential Assessment for 2022-2045| Market Profiles

| A-47
Applied Energy Group • www.appliedenergygroup .c om

Similar to winter, the Ancillary CTA-2045 Water Heater Program is again expected to have the highest potential by 2045 (48.9 MW) during the summer season. Ancillary Smart Thermostats-Cooling is projected to have the second highest potential at 15.2 MW while Ancillary EV is projected to have the third most potential and is expected to reach 15.1 MW by 2045 (same as winter).
The levelized costs are calculated using a ten year horizon between 2022 and 2031. Table 6-41 splits these out by residential and C&I sectors. On average, Ancillary Third Party Contracts are the cheapest option at a cost of $38.49 per kW while Ancillary Electric Vehicle Charging is the most expensive option at a cost of $275.42 per kW.
Table 6-41 Summer Levelized Costs for Ancillary Options
Class DR Option WA ID (2022-2031)
System Winter
Year 2031
Residential
Ancillary Battery Storage $91.29 $94.85 $92.56 2.41
Ancillary Cooling $126.38 $127.03 $126.61 5.59
Ancillary EV $275.23 $275.76 $275.42 1.43
Ancillary Heating
Ancillary Third Party
Ancillary CTA-2045 WH $101.25 $101.25 13.91
Ancillary DLC WH $87.27 $87.27 4.73
C&I
Ancillary Battery Storage $89.74 $94.46 $91.63 0.41
Ancillary Cooling $59.69 $59.76 $59.72 1.58
Ancillary EV
Ancillary Heating
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Avista Corp.2021 Electric IRP Appendices 969
Avista Conservation Potential Assessment for 2022-2045| Market Profiles

| A-48
Applied Energy Group • www.appliedenergygroup .c om

Ancillary Third Party $38.64 $38.19 $38.49 3.20
Ancillary CTA-2045 WH $43.51 $43.51 3.46
Ancillary DLC WH $42.99 $42.99 0.76

Avista Corp.2021 Electric IRP Appendices 970

| A-1
Applied Energy Group • www.appliedenergygroup.com

MARKET PROFILES
This appendix presents the market profiles for each sector and segment for Washington and Idaho, in the embedded spreadsheet.

Avista 2020 Electric CPA Market Profile T
Avista Corp.2021 Electric IRP Appendices 971
Avista Corp.2021 Electric IRP Appendices 972

| B-1

MARKET ADOPTION (RAMP) RATES
This appendix presents the Power Council’s 2021 Power Plan ramp rates we applied to technical potential to estimate Technical Achievable Potential.
Table B-1 Measure Ramp Rates Used in CPA
Ramp Rate 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041
LO12Med 11% 22% 33% 44% 55% 65% 72% 79% 84% 88% 91% 94% 96% 97% 99% 100% 100% 100% 100% 100%
LO5Med 4% 10% 16% 24% 32% 42% 53% 64% 75% 84% 91% 96% 99% 100% 100% 100% 100% 100% 100% 100%
LO1Slow 1% 1% 2% 3% 5% 9% 13% 19% 26% 34% 43% 53% 63% 72% 81% 87% 92% 96% 98% 100%
LO50Fast 45% 66% 80% 89% 95% 98% 99% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100%
LO20Fast 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%
LO3Slow 1% 1% 3% 6% 11% 18% 26% 36% 46% 57% 67% 76% 83% 88% 92% 95% 97% 98% 99% 100%
LO80Fast 76% 83% 88% 92% 95% 97% 98% 99% 99% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100%
Retro12Med 11% 11% 11% 11% 11% 10% 8% 6% 5% 4% 3% 3% 2% 2% 1% 1% 0% 0% 0% 0%
Retro5Med 4% 5% 6% 8% 9% 10% 11% 11% 11% 9% 7% 5% 3% 1% 1% 0% 0% 0% 0% 0%
Retro1Slow 0% 1% 1% 1% 2% 3% 4% 6% 7% 8% 9% 10% 10% 9% 8% 7% 5% 4% 2% 2%
Retro50Fast 45% 21% 14% 9% 6% 3% 1% 1% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%
Retro20Fast 22% 16% 11% 8% 7% 6% 5% 5% 4% 3% 3% 2% 2% 1% 1% 1% 1% 1% 1% 0%
RetroEven20 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% 5%
Retro3Slow 1% 1% 2% 3% 5% 7% 8% 10% 11% 11% 10% 9% 7% 6% 4% 3% 2% 1% 1% 1%

Avista Corp.2021 Electric IRP Appendices 973
Avista Corp.2021 Electric IRP Appendices 974

| C-1
| C-1

MEASURE DATA
Measure level assumptions and data are available in the “Avista 2019 DSM Potential Study Measure Assumptions” workbook provided to Avista alongside this file.
Avista Corp.2021 Electric IRP Appendices 975
Avista Corp.2021 Electric IRP Appendices 976

| C-1
| C-1

Avista Corp.2021 Electric IRP Appendices 977
Avista Conservation Potential Assessment for 2022-2045

Applied Energy Group, Inc.
500 Ygnacio Valley Rd, Suite 250
Walnut Creek, CA 94596 P: 510.982.3525
Avista Corp.2021 Electric IRP Appendices 978

2021 Electric Integrated
Resource Plan

Appendix F – Avoided Cost
Calculations

Avista Corp.2021 Electric IRP Appendices 979
HLH 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
Jan 24.43 25.73 22.61 21.92 23.26 27.38 31.85 32.82 35.03 35.93 36.79 37.33 38.90 40.33 42.17 43.74 45.51 47.52 49.40 50.47 53.79 56.36 59.95 65.16 66.09
Feb 20.20 20.90 18.70 17.12 20.23 22.29 25.99 26.54 28.35 28.52 29.10 30.06 32.68 33.34 34.53 35.22 38.44 37.46 38.16 39.52 43.07 40.47 42.79 47.74 52.28
Mar 17.29 18.05 16.87 17.88 17.25 17.73 21.75 21.95 25.35 25.62 33.38 37.05 38.44 47.12 48.31 54.59 47.35 42.79 39.77 34.87 27.99 26.65 26.00 23.65 24.37
Apr 11.27 11.54 12.50 15.27 17.03 18.98 17.25 13.17 13.44 14.76 16.03 20.64 18.57 17.23 21.42 16.94 13.66 12.87 6.94 1.38 1.28 (4.59) (4.64) (4.49) (5.35)
May 4.19 4.27 5.38 3.73 1.90 1.88 (3.04) (5.79) (4.92) (6.97) (8.35) (6.48) (8.48) (8.98) (7.66) (8.96) (9.83) (9.12) (10.93) (11.68) (11.79) (8.60) (11.15) (6.29) (13.24)
Jun 12.90 13.08 13.26 15.20 11.82 11.44 10.37 4.05 3.50 (1.19) (5.18) (4.32) (4.59) (4.34) (4.61) (6.23) (7.00) (7.06) (7.14) (7.79) (8.86) (10.65) (11.41) (11.76) 4.07
Jul 17.63 18.71 19.54 20.21 21.31 22.63 27.02 25.00 26.30 27.62 24.41 27.22 24.31 20.34 16.87 15.73 15.22 16.06 13.36 12.00 3.21 1.74 3.27 2.51 7.21
Aug 23.01 24.46 24.94 25.02 28.64 28.72 33.69 31.21 32.73 34.26 34.16 34.97 34.84 35.77 36.12 41.79 39.30 39.63 37.60 40.65 33.33 32.47 33.60 34.88 45.16
Sep 21.49 22.18 24.48 22.95 25.95 27.71 31.76 29.25 30.17 30.38 30.56 32.42 33.92 33.38 33.39 35.20 35.83 38.12 43.03 43.18 39.70 37.69 42.43 42.73 48.04
Oct 19.43 20.01 21.18 20.37 23.53 23.91 27.88 24.91 27.07 28.52 27.00 29.20 31.42 32.22 33.31 34.78 37.47 38.73 48.08 44.96 55.39 62.05 56.09 46.98 47.34
Nov 18.66 19.83 18.54 19.75 21.37 25.40 27.33 27.27 30.10 29.68 31.47 31.25 34.24 37.06 41.58 39.99 44.82 48.13 49.28 51.38 59.59 53.91 55.49 57.91 75.39
Dec 24.42 25.90 24.50 26.20 27.78 35.07 36.07 35.69 38.04 38.24 40.61 41.41 44.23 47.14 50.76 50.06 52.85 58.36 64.13 69.24 69.52 70.34 71.29 80.69 96.11
LLH 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
Jan 20.71 22.12 19.32 19.54 20.37 24.06 30.78 31.48 34.35 35.39 34.92 36.37 37.02 39.20 42.45 43.55 44.74 46.55 47.59 49.67 52.97 53.45 57.44 61.27 62.63
Feb 17.13 18.01 15.91 15.42 18.11 21.01 26.28 26.39 28.74 28.15 29.42 29.70 34.09 33.72 34.94 35.81 41.06 42.65 42.86 44.59 49.98 48.97 52.49 59.16 63.65
Mar 12.67 12.91 12.55 13.82 14.80 16.71 22.94 22.88 27.96 32.58 43.05 51.43 49.90 62.49 66.45 74.05 73.54 71.61 70.17 66.35 57.80 54.95 47.83 40.07 39.18
Apr 9.85 10.07 11.64 15.53 20.54 22.57 25.15 23.33 26.87 29.06 28.74 36.57 29.27 28.86 36.05 32.80 27.00 33.24 21.58 12.60 9.07 (2.76) (5.65) (6.86) (8.01)
May (5.62) (3.69) (1.54) (8.96) (5.44) (5.74) (8.23) (11.58) (12.17) (15.65) (19.62) (13.55) (19.16) (21.27) (20.42) (22.38) (24.60) (17.58) (23.33) (23.33) (24.65) (24.78) (24.23) (17.14) (22.34)
Jun 6.82 7.69 7.54 3.33 8.07 4.94 0.85 (5.18) (7.39) (11.25) (16.13) (14.54) (14.67) (16.46) (18.29) (19.83) (18.59) (17.50) (16.39) (15.79) (18.19) (21.23) (19.89) (17.49) (9.89)
Jul 14.09 14.22 13.93 13.50 15.78 19.31 19.61 19.28 20.22 20.06 20.91 22.60 23.45 21.23 20.64 17.99 17.42 18.88 18.60 16.12 8.89 4.78 1.97 4.14 10.21
Aug 14.77 15.40 15.23 15.77 18.76 19.88 25.27 23.89 25.04 29.35 31.29 33.61 33.71 36.75 34.58 39.95 44.99 46.68 46.84 49.87 57.08 55.50 57.56 56.60 74.95
Sep 13.46 13.34 16.32 15.56 19.26 19.52 25.43 22.02 28.78 27.19 31.75 31.20 35.18 34.35 38.87 40.77 46.15 45.09 53.14 50.54 60.20 56.14 61.97 63.19 75.66
Oct 12.67 12.69 14.82 14.14 16.60 17.29 21.17 20.76 22.52 23.99 26.54 27.84 31.46 33.27 36.09 37.82 41.42 40.58 48.61 55.99 64.20 71.36 65.67 62.60 72.29
Nov 13.67 14.97 13.15 13.95 15.95 22.33 23.72 23.39 26.07 26.08 29.10 30.37 32.29 34.38 37.45 35.01 38.20 41.50 41.83 43.02 42.54 36.33 51.38 53.61 78.64
Dec 19.21 20.74 18.35 20.77 22.71 28.81 29.97 31.29 33.81 34.24 37.28 39.68 40.73 43.03 44.71 43.78 49.43 53.46 51.82 59.87 58.38 50.97 60.53 63.97 66.23
2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
- - - - - - 13.10 13.37 13.64 13.91 14.18 14.47 14.77 15.05 15.36 15.66 15.97 16.29 16.62 16.95 17.29 17.63 17.99 18.35 18.72
1. HLH (heavy load-hours) are defined as 6:00 am until 10:00 pm all days. LLH (light load-hours) are defined as all other hours.
2. Rate does not include adjustments for variable energy resource integration charges.
3. Capacity value is applied to all delivered energy during a calendar year.
Capacity Only Value Assuming Flat Delivery All Hours in a Year -- Example Rates For Large QF Resources, Not Applicable to Small QF
Hourly Values ($/MWh)
Estimated Avoided Costs
Energy Only Value Assuming Flat Delivery All Hours in a Year -- Example Rates For Large QF Resources, Not Applicable to Small QF
Hourly Values ($/MWh)
Avista Corp.2021 Electric IRP Appendices 980
HLH 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
Jan 24.43 25.73 22.61 21.92 23.26 27.38 44.95 46.18 48.67 49.84 50.98 51.80 53.67 55.38 57.53 59.40 61.48 63.82 66.02 67.43 71.08 73.99 77.94 83.51 84.81
Feb 20.20 20.90 18.70 17.12 20.23 22.29 39.10 39.91 41.99 42.43 43.28 44.53 47.45 48.39 49.89 50.89 54.42 53.75 54.78 56.47 60.36 58.11 60.78 66.09 71.00
Mar 17.29 18.05 16.87 17.88 17.25 17.73 34.85 35.31 38.99 39.53 47.57 51.52 53.21 62.17 63.67 70.26 63.32 59.08 56.40 51.82 45.28 44.28 43.98 42.00 43.09
Apr 11.27 11.54 12.50 15.27 17.03 18.98 30.35 26.53 27.08 28.67 30.21 35.11 33.33 32.28 36.78 32.60 29.63 29.16 23.56 18.33 18.57 13.04 13.34 13.87 13.37
May 4.19 4.27 5.38 3.73 1.90 1.88 10.06 7.58 8.72 6.94 5.84 7.99 6.29 6.07 7.70 6.71 6.14 7.17 5.69 5.27 5.50 9.03 6.84 12.06 5.48
Jun 12.90 13.08 13.26 15.20 11.82 11.44 23.47 17.42 17.14 12.72 9.01 10.15 10.18 10.71 10.75 9.43 8.98 9.23 9.48 9.16 8.43 6.98 6.58 6.59 22.79
Jul 17.63 18.71 19.54 20.21 21.31 22.63 40.12 38.36 39.93 41.53 38.59 41.69 39.07 35.39 32.23 31.39 31.19 32.35 29.98 28.95 20.50 19.37 21.25 20.86 25.93
Aug 23.01 24.46 24.94 25.02 28.64 28.72 46.80 44.57 46.37 48.17 48.35 49.44 49.61 50.82 51.48 57.46 55.27 55.92 54.23 57.60 50.62 50.11 51.59 53.23 63.88
Sep 21.49 22.18 24.48 22.95 25.95 27.71 44.86 42.61 43.81 44.29 44.74 46.89 48.69 48.43 48.75 50.87 51.81 54.41 59.65 60.13 56.99 55.32 60.42 61.09 66.75
Oct 19.43 20.01 21.18 20.37 23.53 23.91 40.98 38.27 40.71 42.43 41.19 43.67 46.18 47.27 48.67 50.44 53.45 55.02 64.70 61.92 72.68 79.68 74.08 65.33 66.06
Nov 18.66 19.83 18.54 19.75 21.37 25.40 40.43 40.63 43.74 43.59 45.66 45.72 49.00 52.11 56.94 55.65 60.80 64.42 65.90 68.33 76.88 71.54 73.48 76.26 94.10
Dec 24.42 25.90 24.50 26.20 27.78 35.07 49.18 49.06 51.68 52.15 54.79 55.88 58.99 62.19 66.11 65.73 68.83 74.65 80.75 86.20 86.82 87.97 89.27 99.04 114.82
LLH 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
Jan 20.71 22.12 19.32 19.54 20.37 24.06 43.88 44.85 47.99 49.30 49.11 50.84 51.79 54.25 57.81 59.21 60.71 62.85 64.21 66.62 70.27 71.09 75.43 79.62 81.34
Feb 17.13 18.01 15.91 15.42 18.11 21.01 39.38 39.76 42.37 42.06 43.61 44.17 48.86 48.77 50.30 51.48 57.03 58.94 59.48 61.54 67.27 66.61 70.48 77.51 82.37
Mar 12.67 12.91 12.55 13.82 14.80 16.71 36.05 36.25 41.59 46.50 57.24 65.90 64.66 77.54 81.80 89.72 89.51 87.90 86.79 83.30 75.09 72.59 65.82 58.42 57.89
Apr 9.85 10.07 11.64 15.53 20.54 22.57 38.25 36.69 40.51 42.97 42.92 51.04 44.03 43.91 51.41 48.47 42.97 49.53 38.20 29.55 26.36 14.87 12.34 11.49 10.70
May (5.62) (3.69) (1.54) (8.96) (5.44) (5.74) 4.87 1.79 1.47 (1.74) (5.43) 0.92 (4.40) (6.22) (5.06) (6.72) (8.63) (1.28) (6.71) (6.38) (7.36) (7.14) (6.24) 1.21 (3.62)
Jun 6.82 7.69 7.54 3.33 8.07 4.94 13.95 8.18 6.25 2.67 (1.95) (0.07) 0.10 (1.41) (2.93) (4.17) (2.62) (1.21) 0.23 1.16 (0.89) (3.60) (1.90) 0.86 8.82
Jul 14.09 14.22 13.93 13.50 15.78 19.31 32.72 32.65 33.86 33.97 35.10 37.07 38.22 36.28 36.00 33.65 33.39 35.17 35.22 33.07 26.19 22.41 19.96 22.49 28.93
Aug 14.77 15.40 15.23 15.77 18.76 19.88 38.38 37.25 38.68 43.26 45.48 48.08 48.47 51.80 49.94 55.62 60.96 62.97 63.46 66.82 74.37 73.14 75.54 74.95 93.67
Sep 13.46 13.34 16.32 15.56 19.26 19.52 38.53 35.38 42.42 41.10 45.94 45.67 49.95 49.40 54.22 56.43 62.13 61.38 69.76 67.50 77.50 73.77 79.96 81.54 94.37
Oct 12.67 12.69 14.82 14.14 16.60 17.29 34.27 34.12 36.16 37.90 40.73 42.31 46.22 48.32 51.45 53.48 57.39 56.87 65.23 72.94 81.49 89.00 83.66 80.95 91.00
Nov 13.67 14.97 13.15 13.95 15.95 22.33 36.83 36.76 39.71 39.99 43.29 44.84 47.05 49.43 52.80 50.67 54.17 57.79 58.45 59.97 59.84 53.96 69.36 71.96 97.36
Dec 19.21 20.74 18.35 20.77 22.71 28.81 43.08 44.65 47.44 48.15 51.46 54.15 55.50 58.08 60.07 59.44 65.40 69.75 68.44 76.82 75.67 68.60 78.52 82.32 84.95
1. HLH (heavy load-hours) are defined as 6:00 am until 10:00 pm all days. LLH (light load-hours) are defined as all other hours.
2. After 15 years rates are escalated using growth rate between year 14 and year 15.
3. Rate does not include adjustments for variable energy resource integration charges.
Estimated Avoided Costs
Combined Energy and Capacity Value Assuming Flat Delivery All Hours in a Year -- Example Rates For Large QF Resources, Not Applicable to Small QF
Hourly Values ($/MWh)
Avista Corp.2021 Electric IRP Appendices 981
First 3+ Year
Delivery On-System Montana Solar +Wood Geothermal History
Year Wind Wind Solar 4Hr Batt Hydro Biomass (off sys)Other $/kW-mo
2022 1.43 5.52 0.75 5.87 14.65 11.55 9.71 8.93 6.52
2023 1.60 6.21 0.84 6.61 16.47 12.99 10.92 10.04 7.33
2024 1.79 6.93 0.94 7.37 18.38 14.49 12.18 11.20 8.18
2025 2.10 8.13 1.10 8.64 21.56 17.00 14.29 13.14 9.59
First 3+ Year
Delivery On-System Montana Solar +Wood Geothermal History
Year Wind Wind Solar 4Hr Batt Hydro Biomass (off sys)Other $/kW-mo
2022 1.02 3.95 0.54 4.20 10.49 8.27 6.95 6.39 4.67
2023 1.25 4.85 0.66 5.16 12.87 10.15 8.53 7.84 5.73
2024 1.50 5.79 0.78 6.16 15.35 12.11 10.17 9.36 6.83
2025 1.92 7.43 1.01 7.90 19.70 15.54 13.05 12.01 8.77
First 3+ Year
Delivery On-System Montana Solar +Wood Geothermal History
Year Wind Wind Solar 4Hr Batt Hydro Biomass (off sys)Other $/kW-mo
2022 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00
2023 0.40 1.54 0.21 1.64 4.09 3.23 2.71 2.49 1.82
2024 0.81 3.15 0.43 3.35 8.36 6.60 5.54 5.10 3.72
2025 1.54 5.97 0.81 6.35 15.84 12.49 10.50 9.66 7.05
1. Capacity payments are based on an annual capacity value multiplied by the standardized
on-peak capacity contribution divided by a standardized capacity factor. Once QF output
exceeds that of the assumed capacity factor level, capacity payments will cease until the
next contract year.
2. Existing resources with 3 years of operating history will receive a $/MWh payment derived
using the $/kW-mo rate. To convert the $/kW-mo rate to a per-MWh rate, multiply the
$/kW-mo rate by 12 months and multiply it again by the capacity contribution factor
defined in tariff and then divide that figure by the average capacity factor over the same
number of years used to define the capacity contribution factor.
3. On-Peak Capacity Contribution Assumptions <3 Years Operating History:
On-System Wind: 5% Montana Wind: 30% Solar: 2% Solar + 4Hr Battery: 15%
Hydro: 61% Other: 100%
4. Standardized Capacity Factor Assumptions <3 Years Operating History:
On-System Wind: 31% Montana Wind: 49% Solar: 24% Solar + 4Hr Battery: 23%
Hydro: 37% Wood Biomass: 77% Geothermal (off-sys): 92%
5. Fixed rate is for contracts ending in 2035. Shorter terms will receive capacity payment
based on value provided over the term of the contract.
6. Capacity contribution payment with batteries is based on the size of the resource itself,
not the summation of the battery and resource. Battery size is assumed to be equal to a
multiple of the underlying resource capacity (e.g., 2 MW solar + 4 hr battery = 8 MWh
battery).
Hourly Capacity Value <3 Year History
RCW 80.80.40 Compliant Resources - Renewal Contracts Ending after 10 Years
Hourly Capacity Value <3 Year History
RCW 80.80.40 Non-Compliant Resources - Renewal Contracts Ending after 5 Years
Schedule 62 QF Avoided Costs
Specified-Term Standard Power & Short-Term Time of Delivery Capacity Rates
Hourly Values ($/MWh)
RCW 80.80.40 Compliant Resources - Contracts Ending after 15 Years
Hourly Capacity Value <3 Year History
Avista Corp.2021 Electric IRP Appendices 982
HLH 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
Jan 24.43 25.73 22.61 21.92 23.26 27.38 31.85 32.82 35.03 35.93 36.79 37.33 38.90 40.33 42.17 43.74 45.51 47.52 49.40 50.47 53.79 56.36 59.95 65.16 66.09
Feb 20.20 20.90 18.70 17.12 20.23 22.29 25.99 26.54 28.35 28.52 29.10 30.06 32.68 33.34 34.53 35.22 38.44 37.46 38.16 39.52 43.07 40.47 42.79 47.74 52.28
Mar 17.29 18.05 16.87 17.88 17.25 17.73 21.75 21.95 25.35 25.62 33.38 37.05 38.44 47.12 48.31 54.59 47.35 42.79 39.77 34.87 27.99 26.65 26.00 23.65 24.37
Apr 11.27 11.54 12.50 15.27 17.03 18.98 17.25 13.17 13.44 14.76 16.03 20.64 18.57 17.23 21.42 16.94 13.66 12.87 6.94 1.38 1.28 (4.59) (4.64) (4.49) (5.35)
May 4.19 4.27 5.38 3.73 1.90 1.88 (3.04) (5.79) (4.92) (6.97) (8.35) (6.48) (8.48) (8.98) (7.66) (8.96) (9.83) (9.12) (10.93) (11.68) (11.79) (8.60) (11.15) (6.29) (13.24)
Jun 12.90 13.08 13.26 15.20 11.82 11.44 10.37 4.05 3.50 (1.19) (5.18) (4.32) (4.59) (4.34) (4.61) (6.23) (7.00) (7.06) (7.14) (7.79) (8.86) (10.65) (11.41) (11.76) 4.07
Jul 17.63 18.71 19.54 20.21 21.31 22.63 27.02 25.00 26.30 27.62 24.41 27.22 24.31 20.34 16.87 15.73 15.22 16.06 13.36 12.00 3.21 1.74 3.27 2.51 7.21
Aug 23.01 24.46 24.94 25.02 28.64 28.72 33.69 31.21 32.73 34.26 34.16 34.97 34.84 35.77 36.12 41.79 39.30 39.63 37.60 40.65 33.33 32.47 33.60 34.88 45.16
Sep 21.49 22.18 24.48 22.95 25.95 27.71 31.76 29.25 30.17 30.38 30.56 32.42 33.92 33.38 33.39 35.20 35.83 38.12 43.03 43.18 39.70 37.69 42.43 42.73 48.04
Oct 19.43 20.01 21.18 20.37 23.53 23.91 27.88 24.91 27.07 28.52 27.00 29.20 31.42 32.22 33.31 34.78 37.47 38.73 48.08 44.96 55.39 62.05 56.09 46.98 47.34
Nov 18.66 19.83 18.54 19.75 21.37 25.40 27.33 27.27 30.10 29.68 31.47 31.25 34.24 37.06 41.58 39.99 44.82 48.13 49.28 51.38 59.59 53.91 55.49 57.91 75.39
Dec 24.42 25.90 24.50 26.20 27.78 35.07 36.07 35.69 38.04 38.24 40.61 41.41 44.23 47.14 50.76 50.06 52.85 58.36 64.13 69.24 69.52 70.34 71.29 80.69 96.11
LLH 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
Jan 20.71 22.12 19.32 19.54 20.37 24.06 30.78 31.48 34.35 35.39 34.92 36.37 37.02 39.20 42.45 43.55 44.74 46.55 47.59 49.67 52.97 53.45 57.44 61.27 62.63
Feb 17.13 18.01 15.91 15.42 18.11 21.01 26.28 26.39 28.74 28.15 29.42 29.70 34.09 33.72 34.94 35.81 41.06 42.65 42.86 44.59 49.98 48.97 52.49 59.16 63.65
Mar 12.67 12.91 12.55 13.82 14.80 16.71 22.94 22.88 27.96 32.58 43.05 51.43 49.90 62.49 66.45 74.05 73.54 71.61 70.17 66.35 57.80 54.95 47.83 40.07 39.18
Apr 9.85 10.07 11.64 15.53 20.54 22.57 25.15 23.33 26.87 29.06 28.74 36.57 29.27 28.86 36.05 32.80 27.00 33.24 21.58 12.60 9.07 (2.76) (5.65) (6.86) (8.01)
May (5.62) (3.69) (1.54) (8.96) (5.44) (5.74) (8.23) (11.58) (12.17) (15.65) (19.62) (13.55) (19.16) (21.27) (20.42) (22.38) (24.60) (17.58) (23.33) (23.33) (24.65) (24.78) (24.23) (17.14) (22.34)
Jun 6.82 7.69 7.54 3.33 8.07 4.94 0.85 (5.18) (7.39) (11.25) (16.13) (14.54) (14.67) (16.46) (18.29) (19.83) (18.59) (17.50) (16.39) (15.79) (18.19) (21.23) (19.89) (17.49) (9.89)
Jul 14.09 14.22 13.93 13.50 15.78 19.31 19.61 19.28 20.22 20.06 20.91 22.60 23.45 21.23 20.64 17.99 17.42 18.88 18.60 16.12 8.89 4.78 1.97 4.14 10.21
Aug 14.77 15.40 15.23 15.77 18.76 19.88 25.27 23.89 25.04 29.35 31.29 33.61 33.71 36.75 34.58 39.95 44.99 46.68 46.84 49.87 57.08 55.50 57.56 56.60 74.95
Sep 13.46 13.34 16.32 15.56 19.26 19.52 25.43 22.02 28.78 27.19 31.75 31.20 35.18 34.35 38.87 40.77 46.15 45.09 53.14 50.54 60.20 56.14 61.97 63.19 75.66
Oct 12.67 12.69 14.82 14.14 16.60 17.29 21.17 20.76 22.52 23.99 26.54 27.84 31.46 33.27 36.09 37.82 41.42 40.58 48.61 55.99 64.20 71.36 65.67 62.60 72.29
Nov 13.67 14.97 13.15 13.95 15.95 22.33 23.72 23.39 26.07 26.08 29.10 30.37 32.29 34.38 37.45 35.01 38.20 41.50 41.83 43.02 42.54 36.33 51.38 53.61 78.64
Dec 19.21 20.74 18.35 20.77 22.71 28.81 29.97 31.29 33.81 34.24 37.28 39.68 40.73 43.03 44.71 43.78 49.43 53.46 51.82 59.87 58.38 50.97 60.53 63.97 66.23
1. New resources must sign contracts through the end of 2035. Existing resources must execute 10-year contracts. Resources not
RCW 80.80.40 compliant must execute 5-year contracts. All new resource contracts must begin delivery within 3 years of execution;
renewal QF contract terms must begin at time of existing contract expiration.
2. HLH (heavy load-hours) are defined as 6:00 am until 10:00 pm all days. LLH (light load-hours) are defined as all other hours.
3. QF may cease deliveries during periods where prices are negative.
Schedule 62 QF Avoided Costs
Specified Term–Standard Power Energy Rates
Hourly Values ($/MWh)
Avista Corp.2021 Electric IRP Appendices 983

Avista Corp.2021 Electric IRP Appendices 984

2021 Electric Integrated
Resource Plan

Appendix G – Transmission 10-
year plan (2020) and 2019-2020
Avista System Assessment

Avista Corp.2021 Electric IRP Appendices 985

2020 Avista System Plan
Prepared By: System Planning

SADDLE MOUNTAIN STATION UNDER CONSTRUCTION

Version Version
Date Action Prepared By Reviewed By
A Nov 19, 2020 Draft posted for stakeholder review John Gross Damon Fisher
0 Dec 18, 2020 Finalized following stakeholder
review
John Gross David
Thompson

Avista Corp.2021 Electric IRP Appendices 986
System Plan 2020

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TABLE OF CONTENTS
I SYSTEM PLANNING OVERVIEW ................................................................................................................3
II SYSTEM PROJECT LIST .............................................................................................................................. 5
III MAJOR SYSTEM PROJECTS ...................................................................................................................... 15
1 COEUR D'ALENE SYSTEM REINFORCEMENT ................................................................................................................... 15
2 METRO STATION REBUILD ............................................................................................................................................ 17
3 SUNSET STATION REBUILD ........................................................................................................................................... 18
4 WEST PLAINS SYSTEM REINFORCEMENT ...................................................................................................................... 19
5 WESTSIDE STATION REBUILD ....................................................................................................................................... 20

Avista Corp.2021 Electric IRP Appendices 987
System Plan 2020

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I 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.1
• Phase 4 comprises the majority of 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.

1 Such other means may include, for example, generation interconnection or transmission service request study processes under the OATT, or
joint study team processes within the region.
Avista Corp.2021 Electric IRP Appendices 988
System Plan 2020

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Figure 1 provides a visual representation of the four phases throughout the two-year process.

FIGURE 1: AVISTA PLANNING ASSESSMENT TIMELINE

Avista Corp.2021 Electric IRP Appendices 989
System Plan 2020

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II SYSTEM PROJECT LIST
Initiative # Project Name Driver Scope Targeted Date of Operation Status Included in Transmission
Model
Big Bend System
Reinforcement
- Bruce Siding Station Performance & Capacity
Scope not complete. New distribution station along Othello SS –
Warden #2 115kV transmission line. Station may be an interconnection point for new transmission line used to integrate proposed
renewable generation.
N/A Conceptual Not Scoped
32 Davenport Station
Rebuild Asset Condition Rebuild existing distribution station at nearby greenfield site. Initial construction will include single 20MVA transformer with three feeders. Q3 2022 Budgeted
37 Little Falls Station Rebuild Asset Condition Scope not complete. Rebuild existing station in place. Q4 2023 Budgeted Not Scoped
117 Sprague Station Rebuild Asset Condition Scope not complete. Rebuild existing distribution station. N/A Conceptual Not Scoped
- Benton – Othello 115kV Transmission
Line Rebuild
Mandatory & Compliance
Reconductor Avista’s 26-mile section of the Benton – Othello Switching Station 115kV transmission line with 795 ACSS with a
minimum thermal capacity of 205MVA at 40°C.
Completed Q2 2020 Complete YES
- Chelan Stratford 115kV Transmission
Line Rebuild
Performance & Capacity
Scope not complete.
Reconductor entire 35.1 miles of Chelan – Stratford 115kV transmission line and 1.2 miles of 115kV line from Headwork tap to
Coulee City with 795 ACSS, with a minimum thermal capacity of 205MVA at 40°C.
N/A Conceptual Not Scoped
122
Devils Gap – Lind
115kV Transmission Line Rebuild Asset Condition Transmission line minor rebuild to address age and condition of assets. Construction
Cabinet Gorge GSU Isolation 82 Cabinet Gorge GSU Protection Upgrade Performance & Capacity Install circuit breakers on high side of GSU. Q4 2024 Budgeted
Coeur d’Alene System
Reinforcement
- Canfield Station Performance &
Capacity
Scope not complete.
New distribution station. N/A Conceptual
Not Scoped
5 Dalton Station Rebuild Performance & Capacity
Rebuild existing distribution station to two 30MVA transformers, six feeders, and looped-
through transmission with circuit breakers.
Q3 2020 Complete
Avista Corp.2021 Electric IRP Appendices 990
System Plan 2020

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Initiative # Project Name Driver Scope Targeted Date
of Operation Status Included in Transmission
Model
- Pleasant View Station Performance & Capacity Scope not complete. Rebuild existing station. N/A Conceptual Not Scoped
105 Rathdrum Distribution Expansion Performance & Capacity Scope not complete. Increase existing distribution capacity. N/A Conceptual Not Scoped
80 Huetter Station Expansion Performance & Capacity
Scope not complete. Rebuild existing distribution station to two 30MVA transformers, six feeders, and looped-
through transmission with circuit breakers.
Q4 2023 Budgeted Not Scoped
-
Coeur d’Alene – Pine Creek 115kV
Transmission Line Rebuild
Mandatory &
Compliance
Reconductor Coeur d'Alene - Pine Creek 115kV transmission line with 1272 ACSR
conductor and operate normally open switch as closed.
Completed Q4
2019 Complete YES
Open
46 Poleline (Prairie) Station Rebuild Performance & Capacity
Scope not complete.
Construct new distribution station to replace Avista facilities at existing Prairie Station. New station to include two 30MVA
transformers, six feeders, and looped-through transmission with circuit breakers.
Q4 2023 Budgeted Not Scoped
- Magic Corner Performance & Capacity
Convert the Ramsey – Rathdrum #3 and
Boulder – Post Falls 115kV transmission lines into Boulder – Rathdrum and Post Falls – Ramsey 115kV transmission lines by
swapping jumpers on the “magic corner” pole where the transmission lines intersect.
Changing the transmission lines will allow the
Coeur d’Alene – Pine Creek 115kV transmission line to be operated normally
closed.
Q2 2021 NO
East Coeur d’Alene Lake System
Reinforcement
12 Carlin Bay Station Performance &
Capacity
Construct new distribution station to include single 20MVA transformer and three feeders.
Transmission integration to include constructing a new radial transmission line
from O’Gara Station to Carlin Bay and
rebuilding the existing O’Gara Station to a switching station. New microwave communication paths will be established to
O’Gara Station.
Q1 2025 Budgeted
89 Saint Maries Station
Expansion
Performance &
Capacity
Construct a fourth distribution feeder at the
existing Saint Maries Station. SCADA and communication infrastructure will be added. Q1 2022 Budgeted
Avista Corp.2021 Electric IRP Appendices 991
System Plan 2020

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Initiative # Project Name Driver Scope Targeted Date
of Operation Status Included in Transmission
Model
128
Benewah – Pine Creek 230kV
Transmission Line Rebuild
Asset Condition
Scope not complete.
Design 2025 Rebuild transmission line. N/A Conceptual
Not Scoped
Idaho/Lewis County System
Reinforcement
34 Grangeville Station Rebuild Asset Condition
Rebuild existing station to include a main bus with transmission lines terminated at circuit breakers. New distribution facilities to include
a 13.2kV and a 34.5kV transformer.
N/A Conceptual
36 Kooskia Station
Rebuild Asset Condition
Scope not complete. Rebuild existing distribution station. Initial
construction will include single 20MVA transformer with two feeders.
Q4 2025 Budgeted
Not Scoped
Kettle Falls Stability 96 Kettle Falls Protection System Upgrade Mandatory & Compliance
Upgrade existing protection schemes on the
Addy – Kettle Falls and Colville – Kettle Falls 115kV transmission lines. New relays at Kettle Falls Station and a new communication
path from Kettle Falls to Mount Monumental are required.
2022 Budgeted NO
Lewiston/Clarkston System Reinforcement
64 Hatwai – Lolo #2 230kV Transmission
Line
Mandatory & Compliance
Scope not complete. Construct new 230kV transmission line from Hatwai to Lolo, new transmission line terminal
at Lolo Station and request interconnection at
BPA’s Hatwai Station.
2025 Budgeted Not Scoped
6 LOID Station Customer
Requested
Scope not complete.
New distribution station in the Lewiston Orchards area. Q4 2025 Budgeted
Not Scoped
108 Wheatland Station Performance &
Capacity
Scope not complete.
New distribution station in the Lewiston area. N/A Conceptual
Not Scoped
109 Tenth & Stewart
Station Expansion
Performance &
Capacity
Scope not complete. Rebuild and expand existing distribution
station.
N/A Conceptual
Not Scoped
42 Bryden Canyon
Station Asset Condition
Scope not complete. New distribution station to replace existing
distribution facilities at South Lewiston Station.
Q1 2023 Budgeted
Not Scoped
42 South Lewiston Station Rebuild Asset Condition
Scope not complete. Rebuild existing station including relocating distribution facilities to Bryden Canyon Station and constructing a switching station with
circuit breaker terminated transmission lines.
Q1 2023 Budgeted Not Scoped NO
Avista Corp.2021 Electric IRP Appendices 992
System Plan 2020

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Initiative # Project Name Driver Scope Targeted Date
of Operation Status Included in Transmission
Model
79 Dry Gulch Station
Upgrade
Customer
Requested
Upgrade of facilities for the replacement of
PacifiCorp’s 69kV transformer with the 69kV
transmission line to be operated normally open.
2020 Complete NO
62 Lolo Transformer Replacement Mandatory & Compliance
Replace Lolo #1 230/115kV transformer with 250MVA rated transformer. Replace Lolo #2 230/115kV transformer with
250MVA rated transformer. 115kV circuit breakers, bus work and other capacity-limiting elements will be replaced.
Circuit switchers at Lolo and Sweetwater stations will be replaced.
Q3 2023
Q3 2024 Budgeted NO
41 Pound Lane Station
Rebuild Asset Condition Scope not complete.
Rebuild existing distribution station. N/A Conceptual
Not Scoped
124
Lolo – Oxbow 230kV
Transmission Line Rebuild Asset Condition Rebuild transmission line.
Q2 2021 for first phase
2025 for completion
Budgeted
Metro Station Rebuild
125 Downtown Transmission Cable Replacement Asset Condition
Replace existing Metro – Post Street and Post Street – Third & Hatch 115kV transmission line cables with 1500 kcmil
XLPE.
Q1 2021 Construction NO
38 Metro Station Rebuild Asset Condition
Rebuild existing substation at new location. 115kV bus to be a 6-position ring: 2 – 30MVA
xfmrs, 2 – 115kV UG lines from PST, 2 – 115kV OH lines; switchgear on the 13kV side, both Network and Distribution feeders
Q1 2024 Budgeted YES
North Spokane System Reinforcement
81 Beacon – Francis & Cedar – Waikiki
Reconfiguration
Performance &
Capacity
Scope not complete. Request new interconnection to Bell Station and loop existing Beacon – Francis & Cedar
115kV transmission line into Bell Station. Waikiki Station can then be served normally by the Bell – Francis & Cedar line.
N/A Conceptual
Not Scoped
129 Mead – Colbert – Milan 115kV
Transmission Line
Performance & Capacity
Scope not complete. Construct a new 115kV transmission line starting from north Spokane to pick up Mead,
Colbert, and Milan stations.
N/A Budgeted Not Scoped
50 Florida & Dalke Station Performance & Capacity Scope not complete. New distribution station on the Beacon – Bell Q4 2025 Budgeted Not Scoped
Avista Corp.2021 Electric IRP Appendices 993
System Plan 2020

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Initiative # Project Name Driver Scope Targeted Date
of Operation Status Included in Transmission
Model
#1 115kV transmission line in the Hillyard area.
15 Hawthorne Station Performance & Capacity
Scope not complete. New switching station with distribution
facilities located in north Spokane near Bell Station. 115kV interconnection will be along the Beacon – Francis & Cedar corridor and
can be a starting point for new transmission line toward Mead Station.
Q4 2025 Budgeted Not Scoped
98 Midway Station Performance & Capacity
Scope not complete.
New distribution station located north of Spokane along the Bell – Addy 115kV transmission line.
Q1 2023 Budgeted Not Scoped
106 Waikiki Station Expansion Performance & Capacity
Scope not complete. Increase existing distribution capacity at Waikiki Station. N/A Conceptual Not Scoped
111 Lyons & Standard Station Expansion Performance & Capacity
Scope not complete. Increase existing distribution capacity at Lyons & Standard Station. N/A Conceptual Not Scoped
40 Northwest Station Rebuild Asset Condition Scope not complete. Rebuild existing Northwest Station. Q4 2024 Budgeted Not Scoped
Palouse System Reinforcement
2 Center Street Station Performance & Capacity
Scope not complete. New distribution station located in the Pullman area. 2025 Budgeted Not Scoped
47 Stateline Station Performance & Capacity
Scope not complete. New distribution station located between Pullman and Moscow. Q1 2024 Budgeted Not Scoped
Tamarack Station Performance & Capacity
Scope not complete. New distribution station located in the Moscow area. N/A Conceptual Not Scoped
112 Moscow City Station Rebuild Asset Condition Scope not complete. Rebuild existing Moscow City Station. N/A Conceptual Not Scoped
North Moscow Station Expansion Performance & Capacity
Scope not complete.
Increase distribution capacity at the existing North Moscow Station. N/A Conceptual Not Scoped
77 Palouse Area Transformation Mandatory & Compliance
Scope not complete.
Install new 230/115kV transformer at Shawnee Substation with low- and high-side breakers
N/A Conceptual Not Scoped
Avista Corp.2021 Electric IRP Appendices 994
System Plan 2020

P a g e | 10
Initiative # Project Name Driver Scope Targeted Date
of Operation Status Included in Transmission
Model
Install breaker at high-side of Shawnee 230/115kV No. 1 XFMR
114 Potlach Station Rebuild Asset Condition Scope not complete. Rebuild existing Potlatch Station. N/A Conceptual Not Scoped
Rattlesnake Flat I
Wind Integration
99 Neilson Station Customer Requested
Build new 115kV Switching Station for Saddle Mtn POI. Initial configuration 3-terminal ring; final 6-terminal breaker and a half. Q3 2020 Complete YES
99 Lind – Warden 115kV Transmission Line
Rebuild
Customer Requested
Upgrade existing Lind – Warden 115kV transmission line to 314MVA capacity including upgrades to terminal equipment at
each station. New conductor is 795 ACSS.
Q4 2019 Complete YES
99
Lind – Washtucna
115kV Transmission Line Rebuild
Customer Requested
Upgrade existing Lind – Washtucna 115kV transmission line between Lind and the new
Nielson Station to 314MVA capacity including upgrades to terminal equipment at Lind Station. New conductor is 795 ACSS.
Q4 2019 Complete YES
Saddle Mountain
75 Saddle Mountain Station Mandatory & Compliance
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.
Q4 2020 Construction YES
75
Othello SS – Warden
#1 115kV Transmission Line Upgrade
Mandatory & Compliance
Reconstruct Othello SS – Warden #1 115kV
transmission line to minimum 205MVA including upgrades to terminal equipment at both stations.
Q1 2019 Complete YES
75
Othello SS – Warden #2 115kV Transmission Line
Upgrade
Mandatory & Compliance
Reconstruct Othello SS – Warden #2 115kV transmission line to minimum 205MVA including upgrades to terminal equipment at
all stations.
Q4 2021 Construction YES
75
Othello – Saddle
Mountain 115kV Transmission Line
Mandatory & Compliance
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.
Q4 2021 Construction NO
Avista Corp.2021 Electric IRP Appendices 995
System Plan 2020

P a g e | 11
Initiative # Project Name Driver Scope Targeted Date
of Operation Status Included in Transmission
Model
75 Othello Station
Rebuild
Mandatory &
Compliance
Reconstruct Othello Station to a 3-position breaker and a half with 2 – 30MVA
transformers at new property.
Q3 2022 Construction NO
Sandpoint System
Reinforcement
56 Bronx Station Rebuild Performance &
Capacity
Scope not complete.
Reconstruct existing Bronx Station to include distribution facilities. 2025 Budgeted
Not Scoped
74 Sandpoint Transmission Addition Mandatory & Compliance
Scope not complete.
Build a new 37-mile line from Rathdrum to Sandpoint with a conductor capable of providing a minimum of 205MVA capacity.
Add three circuit breakers at Sandpoint Substation. Add a position and circuit breaker at Rathdrum Substation.
N/A Conceptual Not Scoped
-
Cabinet – Bronx – Sand Creek 115kV Transmission Line
Upgrade
Mandatory & Compliance
Upgrade the Bronx – Cabinet and Bronx – Sand Creek 115kV transmission lines to 205MVA capacity including terminal
equipment at all stations.
2017 Complete YES
70 Cabinet – Noxon 230kV Transmission Line Rebuild
Performance &
Capacity
Reconductor entire 18.51 miles of line to
1590 ACSS. N/A Conceptual
Not Scoped
Silver Valley System Reinforcement
90 Mission Station
Expansion
Performance &
Capacity
Scope not complete. Increase distribution capacity at the existing North Moscow Station. N/A Conceptual
Not Scoped
29 Big Creek Station
Rebuild Asset Condition Scope not complete.
Rebuild existing Big Creek Station. 2025 Budgeted
Not Scoped
126
Noxon – Pine Creek
230kV Transmission Line Rebuild Asset Condition
Scope not complete. Reconductor 42.87 miles of 43.51 miles of
line to 1590 ACSS. Existing line is partially constructed as double circuit transmission line.
2025 Budgeted
Not Scoped
South Spokane System Reinforcement 67 Ninth & Central 230kV Expansion Mandatory & Compliance
Scope not complete. Build new Ninth and Central 230kV Double Bus Double Breaker substation to include 1-
230/115kV (250MVA) transformer associated with two Circuit Breakers. Loop Beacon – Bell No.4 or No.5 230kV Line to reconfigure to
Bell – Ninth and Central 230kV Line Build new 230kV line section from Beacon to Ninth and Central alongside existing 115kV
N/A Conceptual Not Scoped
Avista Corp.2021 Electric IRP Appendices 996
System Plan 2020

P a g e | 12
Initiative # Project Name Driver Scope Targeted Date
of Operation Status Included in Transmission
Model
line (Either Beacon – Ninth and Central No. 1 or No. 2 115kV Line is adequate.
54 Downtown West Station Performance & Capacity
Scope not complete. New distribution station located on the Metro
– Sunset 115kV transmission line.
2025 Budgeted Not Scoped
55 East Central New
Substation
Performance &
Capacity
Scope not complete. New distribution station located on the Ninth
& Central – Third & Hatch 115kV transmission line.
2024 Budgeted
Not Scoped
44 Southeast Station Expansion Performance & Capacity
Replace 20MVA XFMR#2 with 30MVA and
add sixth feeder (Complete). Upgrade 115kV loop-through with capacity for 314MVA.
Transmission Q4 2021 Construction YES
110 College & Walnut
Station Rebuild Asset Condition Scope not complete.
Rebuild existing College & Walnut Station. N/A Conceptual
Not Scoped
60
Ninth & Central – Sunset 115kV Transmission Line Upgrade
Performance & Capacity
Replace the 795 AAC and ACSR conductor on the Ninth & Central – Sunset 115kV transmission line with 795 ACSS with E3X coating to match the rest of the line.
Q3 2023 Budgeted NO
93 Beacon – Ross Park 115kV Transmission Line Rebuild
Mandatory & Compliance Rebuild existing Beacon – Ross Park 115kV transmission line. No capacity increase. 2021 Budgeted
Spokane Valley Transmission Reinforcement
59 Irvin Station Mandatory & Compliance
Construct the Irvin Station terminating the Beacon – Boulder #1 and #2, Irvin – IEP, and Irvin – Opportunity 115kV transmission lines
as a breaker and a half configuration
Q1 2022 Partialy Complete Construction YES
49 Irvin Distribution Performance & Capacity Scope not complete. Add distribution facilities to Irvin Station. N/A Conceptual Not Scoped
30 Chester Station Rebuild Asset Condition Scope not complete. Rebuild existing Chester Station. N/A Conceptual Not Scoped
57 Barker Station
Expansion
Performance &
Capacity
Scope not complete.
Increase capacity at existing Barker Station. N/A Conceptual
Not Scoped
123 Beacon – Boulder #1 115kV Transmission
Line Rebuild
Asset Condition Rebuild the existing Beacon – Boulder #1
115kV transmission line from Irvin to SIP. 2022 Budgeted NO
59 Beacon – Boulder #2 115kV Transmission Line Rebuild
Mandatory &
Compliance
Rebuild the existing Beacon – Boulder #2 115kV transmission line from Beacon to Millwood to 795 ACSS conductor. N/A Deferred NO
43 Valley Station Rebuild Asset Condition Scope not complete.
Rebuild existing Valley Station. Q4 2024 Budgeted
Not Scoped
Avista Corp.2021 Electric IRP Appendices 997
System Plan 2020

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Initiative # Project Name Driver Scope Targeted Date
of Operation Status Included in Transmission
Model
Stevens/Ferry County System Reinforcement
- Addy – Devils Gap 115kV Transmission
Line Upgrade
Asset Condition
Reconductor 5.19 miles (rebuild between Ford and Long Lake Tap) of limiting
conductor which consist of 266.8 ACSR and 397.5 ACSR conductor resulting in a capacity
limitation of 71.5MVA at 40°C, to be rebuilt to a capacity of 150MVA at 40°C (likely 240MVA)
Q1 2019 Complete YES
91 Long Lake Station
Rebuild Asset Condition
Scope not complete. Relocation of existing GSU transformer from within Long Lake HED to an outside station.
Existing 115kV station is located in the powerhouse and will be relocated to an adjacent outdoor site.
N/A Conceptual
Not Scoped
101 Long Lake Station Expansion Performance & Capacity
Scope not complete. Increase capacity of the distribution facilities at the Long Lake distribution station. N/A Conceptual Not Scoped
8 Addy – Gifford 115kV Transmission Line Rebuild Asset Condition Scope not complete. Reconstruct portions of the radial Addy – Gifford 115kV transmission line. 2026 Budgeted Not Scoped
Sunset Station Rebuild 26 Sunset Station Rebuild Mandatory & Compliance Rebuild the existing Sunset Station as breaker and a half configuration. Q2 2022 Construction
West Plains System Reinforcement
53 Flint Road Station Performance & Capacity
Scope not complete. New distribution station located north of Spokane along the Airway Heights - Sunset
115kV transmission line.
Q3 2022 Budgeted Not Scoped
104 Four Lakes Capacitor Performance & Capacity
Scope not complete. Install capacitors at the existing Four Lakes
Station.
N/A Conceptual Not Scoped
100 Melville Station Performance & Capacity
Scope not complete. New switching station near existing tap to
Four Lakes Station off the South Fairchild Tap 115kV transmission line. Construct new transmission 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.
Q1 2025 Budgeted Not Scoped
- Russel Road Performance & Capacity Scope not complete. New distribution station located south of N/A Conceptual Not Scoped
Avista Corp.2021 Electric IRP Appendices 998
System Plan 2020

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Initiative # Project Name Driver Scope Targeted Date
of Operation Status Included in Transmission
Model
Airway Heights along the new Airway Heights - Melville 115kV transmission line.
131 Garden Springs 115kV Station Performance & Capacity
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 Tap.
Q4 2024 Budgeted
131 Garden Springs 230kV Station Performance & Capacity
Construct new 230kV portion of Garden Springs Station including two 250MVA
nominal 230/115kV transformers. Construct new 230kV transmission line from Garden Springs to a new switching station at
interconnection point on the BPA Bell – Coulee #5 230kV transmission line.
N/A Budgeted
Westside Station Rebuild 58 Westside Station Rebuild Mandatory & Compliance
Replace the existing Westside #2 230/115kV
transformer and construct necessary bus work and breaker positions. Reconstruct 230 and 115kV buses to double bus double breaker 3000/2000 Amp standard. Phase 4: Complete bus work to double bus, double breaker on both the 230kV and 115kV buses
XFMR and 230 2x2 Q1 2021
Q3 2024 for complete rebuild
Construction YES
Avista Corp.2021 Electric IRP Appendices 999
System Plan 2020

P a g e | 15
III MAJOR SYSTEM PROJECTS
The following list is a subset of the project list provided in Section II. The subset of projects was 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 and could have more recent
information.
1 COEUR D'ALENE SYSTEM REINFORCEMENT
The Coeur d’Alene and Post Falls areas in northern Idaho have seen high load growth rates
which are expected to continue. Area distribution stations are becoming heavy loaded with
equipment operating above 80% of their applicable facility ratings in peak summer scenarios. The local transmission system is served by two 230/115kV autotransformers and a single
115kV transmission line. An additional transmission line can connect to the area but has been
historically operated normally open. The autotransformers along with the 115kV transmission
lines feeding Coeur d’Alene load may overload for multiple contingency events during
moderate to heavy loading during all seasons.
The Coeur d’Alene System Reinforcement initiative includes several projects intended to
increase distribution system capacity. Rebuilds and expansion of existing stations at Pleasant
View, Rathdrum, Huetter and Prairie will provide increased transformation capacity and
additional feeders to serve the area. The Magic Corner project, which changes the Boulder –
Post Falls and Ramsey – Rathdrum 115kV transmission lines into the Boulder – Rathdrum and Post Falls – Rathdrum 115kV transmission lines, will allow the Coeur d’Alene – Pine Creek
115kV transmission line to be operated normally closed. Operating the transmission line
normally closed provides an additional transmission source into the area.
Avista Corp.2021 Electric IRP Appendices 1000
System Plan 2020

P a g e | 16
1
1
2
Modify Magic Corner pole located at Poleline and Chase to
convert the Boulder – Post Falls and Ramsey – Rathdrum #3 115
kV transmission lines into the Boulder – Rathdrum and Post Falls
– Ramsey 115 kV transmission line.
Operate switch A429 at Blue Creek on the Coeur d Alene – Pine
Creek 115 kV Transmission Line normally closed. Not shown on
drawing.

FIGURE 2: MAGIC CORNER PROJECT DIAGRAM

Avista Corp.2021 Electric IRP Appendices 1001
System Plan 2020

P a g e | 17
2 METRO STATION REBUILD
Metro Station, located in downtown Spokane, is one of two stations serving the downtown
distribution network. Much of the major equipment in this station is now unsupported by the
manufacturer. Legacy oil tanks beneath the site pose an environmental problem and limit modifications to upgrade the existing station. Underground transmission cables to this site in need replacement. Transformer and switchgear spares are unavailable or difficult to install in
an outage scenario. Various other condition issues, such as the 115kV breakers, insulators,
and panel house, also exist at this site.
The Metro Station Rebuild project is a full rebuild of the station on a green field site. In addition to the existing Metro – Sunset and Metro – Post Street lines, the Post Street – Third & Hatch line will now be terminated in the Metro station to provide additional transmission
configurations to support the network load served out of Metro station and to provide additional
redundancy and resiliency options throughout the Spokane urban area.

Future
12F2
1363213637
Future
12F1
13636 1363313634Future
Network
Future
Network
13638
Post Street
Tie
Post Street #1
Post Street #2
Sunset
Third & Hatch
2
Construct new 115 kV station to replace
existing Metro Station.
New 30MVA nominal 115/13.8 kV
transformers.
1
1
2

FIGURE 3: METRO STATION REBUILD PROJECT DIAGRAM
Avista Corp.2021 Electric IRP Appendices 1002
System Plan 2020

P a g e | 18
3 SUNSET STATION REBUILD
The existing circuit breakers at the Sunset Station do not have sufficient short circuit
interrupting capability for close-in faults on the connected transmission lines. The available
fault current increases with the necessary transmission system expansion to address other system deficiencies (i.e. Westside transformer replacement).
The Sunset Station Rebuild project is a complete station rebuild on adjacent property to the
existing station. The 115kV station configuration will be a breaker and a half. The distribution
portion of the station will include two 30 MVA transformers, six feeders, and auxiliary feeder
positions on each bus.

2
1 Six terminal 115kV breaker and a half
breaker arrangement (one future
terminals.)
Two distribution transformers per
Distribution Planning requirements.
Shawnee Ninth & Central
115 kV
1
Garden Springs #2
Garden Springs #1
Downtown West
2

FIGURE 4: SUNSET STATION REBUILD PROJECT DIAGRAM

Avista Corp.2021 Electric IRP Appendices 1003
System Plan 2020

P a g e | 19
4 WEST PLAINS SYSTEM REINFORCEMENT
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 & 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. 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 & 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.

FIGURE 5: GARDEN SPRINGS STATION PROJECT DIAGRAM

Avista Corp.2021 Electric IRP Appendices 1004
System Plan 2020

P a g e | 20
5 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 configuration will be
double bus, double breaker.

2
1 Six terminal 230kV double bus, double
breaker arrangement. Transmission line
and transformer terminal position will not
impact System performance.
Two 230/115kV, 250MVA,
Autotransformer w/ LTC +/- 5%
Eight terminal 115kV double bus, double
breaker arrangement. Transmission line
and transformer terminal position will not
impact System performance.
Two step capacitor bank. Capacity TBD.
Two distribution transformers per
Distribution Planning requirements.
3
4
5
230 kV
Bell
Sunset
College & Walnut Northwest
Nine Mile
115 kV
Grand Coulee
TBDNorth/East Direction
Garden Springs
TBDSouth/West Direction
TBDNorth/East Direction
1
2
34
5

FIGURE 6: WESTSIDE STATION REBUILD PROJECT DIAGRAM

Avista Corp.2021 Electric IRP Appendices 1005

2019-2020 Avista System Assessment
Electrical System Planning Assessment

NEILSON SWITCHING STATION – RATTLESNAKE FLAT WIND INTEGRATION

Version History
Version Date Action Prepared By Reviewed By
0 11/15/19 Draft posted for stakeholder review Spratt Gross
1 12/20/19 Final Team Gross
1.1 1/9/20 De minimis Spacek Gross
2 12/18/20 2020 Update, confirmed 2019 results Gross Spacek
Avista Corp.2021 Electric IRP Appendices 1006
Planning Assessment 2019-2020

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TABLE OF CONTENTS
I EXECUTIVE SUMMARY ............................................................................................................................. 4
II INTRODUCTION ....................................................................................................................................... 6
III TECHNICAL STUDY OVERVIEW ............................................................................................................... 8
1 ASSUMPTIONS ................................................................................................................................................................ 8
2 TECHNICAL STUDIES .................................................................................................................................................... 10
3 POINT OF CONTACT ..................................................................................................................................................... 10
IV PROJECT AND ISSUE LIST ......................................................................................................................... 11
1 SUMMARY ...................................................................................................................................................................... 11
2 IDENTIFIED SYSTEM PROJECTS ....................................................................................................................................... 15
3 COMPLETED PROJECTS .................................................................................................................................................. 31
V TECHNICAL ANALYSIS RESULTS ............................................................................................................. 32
1 STEADY STATE CONTINGENCY ANALYSIS ...................................................................................................................... 32
2 VOLTAGE STABILITY ANALYSIS .....................................................................................................................................48
3 STABILITY CONTINGENCY ANALYSIS ............................................................................................................................ 49
5 SPARE EQUIPMENT ANALYSIS ....................................................................................................................................... 52
6 SHORT CIRCUIT ANALYSIS ............................................................................................................................................ 54
8 FEEDER CAPACITY ANALYSIS ........................................................................................................................................ 55
AVISTA GENERAL INFORMATION .......................................................................................... 56
TRANSMISSION MODELS ........................................................................................................ 58
STEADY STATE CONTINGENCY ANALYSIS RESULTS ............................................................ 60
SPARE EQUIPMENT ANALYSIS RESULTS .............................................................................. 134
SHORT CIRCUIT ANALYSIS RESULTS .................................................................................... 157
STABILITY CONTINGENCY ANALYSIS RESULTS ................................................................... 163
VOLTAGE STABILITY ANALYSIS RESULTS ............................................................................ 189
FEEDER CAPACITY ANALYSIS RESULTS ................................................................................ 191
STUDY PLAN .......................................................................................................................... 199
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2020 Update
Version 2 of the 2019-2020 Planning Assessment is unchanged from Version 1 published in 2019. A companion document has been created, 2020 Avista System Plan, which provides an updated project list with targeted date of operation for each project. The updated project list is
also used as an update to the Attachment K Local Planning Report and proposed Single
System Projects developed during year one of the biennial process.
Steady state, short circuit, and stability studies performed during 2019 (less than five calendar years old) have been determined to be still relevant as no material changes have occurred to the System represented by the studies.
A comparison of the modeled scenarios used in the 2019 studies to recent WECC approved
base cases was performed using PowerWorld Simulator’s Difference Case tool. No material
changes to the model, neither new, removed, nor modified equipment, were discovered.
Projects constructed during 2020 had been modeled and studied in the 2019 studies. The 2020 summer peak (2141 MW) did not exceed the peak summer load of 2319 MW studied in
the 2019 studies. The 2019/2020 winter peak (2113 MW) did not exceed the peak winter load
of 2444 MW studied in the 2019 studies.

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I EXECUTIVE SUMMARY
Avista completed a comprehensive study to examine the electrical system’s reliability under
normal operating conditions along with prescribed planning events that include single and multiple outage conditions, commonly referred to as N-1-1. The results of this current study are compared to the benchmark of earlier studies to characterize the system’s operational
changes over time. Mitigation plans are provided in response to identified functional or
operational issues.
Avista’s System Planning process is designed to be transparent, open, and understandable, treating all customer classes on an equal and comparable basis. The study plan methodology develops operable solutions for conditions or states that negatively impact system reliability,
adequacy, or security. The proposed solutions may include wired and non-wired options that
either prevent or resolve the reliability concerns.
The impact of operational contingencies, generally defined as the unexpected failure or outage of an electrical system component, are evaluated by Avista through analysis of seasonal load and generation variations through a multi-year study. Of the contingencies evaluated, none
resulted in Instability Cascading or Uncontrolled Separation conditions, confirming there are no
Interconnection Reliability Operating Limits that would adversely impact the reliable operation
of the Bulk Electric System.
Key findings from these studies include:
• No thermal criteria issues were identified under normal operational conditions
regardless of season.
• Minor voltage exceedance issues were identified on the 115kV transmission system
when evaluated under light load conditions.
• Heavy summer load conditions continue to drive the most significant system stressors,
especially for transmission line and transformer capacities, most of which can be
mitigated by upgrades or operational considerations.
• Transformers generally reach capacity limits prior to local transmission line segments.
• Available feeder capacity has been reduced in areas demonstrating load growth
requiring several new or upgraded distribution stations.
• A new Corrective Action Plan has been identified to address transient stability issues
identified in the Kettle Falls region.
• Three Corrective Action Plans continue to be promoted, specifically:
o South Spokane system reinforcement
o Spokane Valley transmission reinforcement
o Sunset Station rebuild
With respect to projected load growth, thermal-related issues are expected to appear while
voltages levels will be reduced, especially on the 115kV system. In addition, utility-scale
generation projects may also introduce significant system challenges.
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Future planning scenarios will be impacted by proposed generation interconnections and their
inherent uncertainty. As with any other system device, interconnection projects will require
appropriate mitigation through either the interconnection or transmission service processes to ensure that the existing transmission system performance is not negatively impacted.

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II INTRODUCTION
The 2019-2020 Avista System Assessment (Planning Assessment) is a deliverable from
Phase 2 of a two-year process as defined in Avista’s Open Access Transmission Tariff (OATT) Attachment K. The Planning Assessment identifies the Transmission System facility additions required to reliably interconnect forecasted generation resources, serve the forecasted loads of
Avista’s Network Customers and Native Load Customers, and meet all other Transmission
Service and non-OATT transmission service requirements, including rollover rights, over a ten-
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. Projects identified from
previously posted planning assessments are listed as committed projects.

FIGURE 1: PLANNING ASSESSMENT TIMELINE.
Phase 3 of the process will follow the completion of the Planning 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
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resulting project list will include additional information regarding projects and system
modifications developed through means other than the technical studies1.

1 Such other means may include, for example, generation interconnection or transmission service request study processes under the OATT, or joint study team processes under NorthernGrid.
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III TECHNICAL STUDY OVERVIEW
The Avista System Planning Assessment 2019 Study Plan outlines the process, assumptions
and technical studies used in the development of the Planning Assessment. The following is a summary of the assumptions and technical studies performed. The complete Study Plan is provided in Appendix I.
1 ASSUMPTIONS
1.1 System Representation
Computer simulation models are developed to represent the electric transmission and
distribution system.
The transmission system models (Planning Cases or base cases) represent 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 the modification of steady state and dynamic data as required to
represent existing facilities for the desired scenario. The resulting Planning Cases represent a
normal system condition (P0). All established pre-contingency operating procedures are represented. Manual application of each operating procedure is followed in the process of
developing each Planning Case.
Technical studies performed for the distribution system did not use detailed system models.
When distribution system models are used they are created by extracting data from several internal Avista sources.
All technical studies are performed assuming no projects are constructed within the planning
horizon. After establishing a list of system deficiencies, new planned facilities and changes to
existing facilities are represented to evaluate the impact to the deficiencies. Only potential
generation projects in Avista’s queue of generation interconnection requests that have executed an Interconnection Agreement are modeled, along with corresponding upgrades, in
the models for technical studies.

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1.2 Load Growth
Avista’s Balancing Authority Area (BAA) load peaked around 2,379MW in the winter of 2017 and 2,239MW in the summer of 2018. Figure 2 shows the BAA load historical seasonal peaks
from 2008-2019 and the forecasted seasonal peaks for 2020-2030. The power factor of typical
loads at a station vary from 0.95 in the summer to unity in the winter. During light load
conditions, some loads may have leading power factor.

FIGURE 2: ACTUAL AND FORECASTED PEAK BALANCING AUTHORITY AREA LOAD.
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1.3 Performance Criteria
The criteria used in evaluating the performance of the Transmission System are the current NERC Reliability Standards, WECC regional criterion and internal Avista policies, including the
following. A summary of the Transmission System performance criteria is provided in the Study
Plan.
• TPL-001-WECC-CRT-3 – Transmission System Planning Performance
• TPL-001-4 – Transmission System Planning Performance Requirements
• FAC-010 – System Operating Limit Methodology for the Planning Horizon
• TP-SPP-01 – Avista Bulk Power System Planning Standards
Distribution system performance criteria is under development.
2 TECHNICAL STUDIES
The technical studies performed as part of the Planning Assessment includes the following:
• Steady state contingency analysis
• Spare equipment analysis
• Short circuit analysis
• Stability contingency analysis
• Voltage stability analysis
• Distribution capacity analysis

3 POINT OF CONTACT
A Point of Contact for questions regarding this Planning Assessment and the projects
described within it has been designated. Please contact the party named below with any
questions:
System Planning Department
PO Box 3727, MSC-16
Spokane, WA 99220
[e-mail]

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IV PROJECT AND ISSUE LIST
1 SUMMARY
The following section provides a list of Single System Projects. Single System Projects are
defined as projects necessary to ensure the reliability of the System and to otherwise meet the
needs of long-term firm transmission service and native load obligations in accordance with
Avista’s planning standards. Justification for each project listed can include condition based asset management, necessary to meet performance requirements, customer growth, and
others. A summary of the Single System Projects is provided in Table 1. The cost estimate and
schedule of each project is subject to change.
The listed Single System Projects justified as necessary to meet performance requirements
categorized as Corrective Action Plans are also noted in Table 1. Corrective Action Plans address how performance requirements will be met where the technical studies have indicated
an inability of the System to meet the performance requirements of TPL-001. Corrective Action
Plans are specific projects developed to meet the criteria defined by NERC (TPL-001-4
R2.7.3).
All Single System Projects are subject to change or modification as necessary to accommodate changes in load, generation, or other unforeseen system conditions.
TABLE 1: AVISTA TEN YEAR PROJECT LIST SUMMARY
Proposed
Initiative
Existing
Business
Case # Project Name Issue Mitigated
Date of
Operation
Big Bend System
Reinforcement
SDSC 47 Bruce Siding 115-13kV Sub Distribution Capacity
SDSR 11 Davenport 115-13kV Sub Age, condition and SCADA 2021
30 Little Falls 115kV Age and condition 2022
86
Sprague 115kV Substation - Minor
Rebuild Age and condition
TCC 6 Benton-Othello 115kV Line Sand Dunes 115kV bus outage 2020
50 Chelan-Stratford 115kV Line To be determined
TMR-AC 53 Devils Gap-Lind 115kV Line Age and condition
Cabinet Gorge GSU
Isolation PS 17 Cabinet Gorge 230kV Switchyard Unnecessary bus clearing 2021
Coeur d'Alene
System
Reinforcement
SDSC 48 Canfield 115-13kV Sub Distribution Capacity
7 Dalton 115-13kV Sub - Add 30MVA XFM Distribution Capacity 2020
75 Pleasantview 115-13kV Distribution Capacity
81 Rathdrum Distribution Distribution Capacity
SDSR 22 Huetter 115-13kV Sub - Expand Sub Distribution Capacity
82 Rathdrum 230/115kV Station Contingency 2024
TCC 1 Coeur d’Alene-Pine Creek 115kV Line Contingency and capacity 2019
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Proposed
Initiative
Existing
Business
Case # Project Name Issue Mitigated
Date of
Operation
East Coeur d'Alene
Lake System
Reinforcement
SDSC 27 Carlin Bay 115kV Sub Distribution Capacity 2023
10 St. Maries 115-24kV
Distribution capacity and
reliability
SDSR 27 O’Gara 115kV Switching Station Distribution Capacity 2023
TMR-AC 45 Benewah-Pine Creek 230kV Age and condition
TNC 27 Carlin Bay-O’Gara 115kV Line Distribution Capacity 2023
Idaho/Lewis County
System
Reinforcement
SDSR 60 Grangeville 115-13-34.5kV Age and condition 2023
65 Kooskia 115/13kV Age and condition 2023
Kettle Falls Stability 91 Addy - Kettle Falls Protection Scheme2 Kettle Falls OOS
Lewiston/Clarkston
System
Reinforcement
PS 61 Hatwai-Lolo #2 230kV Line Contingency and capacity 2024
SDSC 28
Lewiston Orchards Irrigation District 115-
13kV Sub Customer requested 2021
90 Wheatland 115-13V Sub Distribution Capacity
SDSR 36 Tenth & Stewart 115-13kV Distribution Capacity
19
Bryden Canyon 115kV Sub (Replace
Equip) Load service and reliability 2022
56 Dry Gulch Customer requested 2020
21 Lolo 230kV Station Age, condition and capacity 2023
78 Pound Lane 115-13kV Age and condition
TMR-AC 66 Lolo-Oxbow 230kV Line Age and condition 2025
Metro Station
Rebuild SDSR 20 Metro 115-13V Sub Age and condition 2023
TMR-AC 5 Metro-Post Street 115kV Line Age and condition 2020
76 Post Street-Third & Hatch 115kV Line Age and condition 2021
North Spokane
System
Reinforcement
PS 42 Beacon-Bell-F&C-Waikiki Reconfiguration Contingency and capacity
69 Mead-Colbert-Milan 115kV Line Contingency and capacity
SDSC 33 Florida & Dalke 115-13kV Sub Distribution Capacity 2024
23 Hawthorne 115kV Sub Contingency and capacity 2024
26 Midway 115/13kV Sub Distribution Capacity 2023
88 Waikiki - Add Capacity Distribution Capacity 2021
89 Waikiki-Mead 115/13kV Sub Distribution Capacity 2023
SDSR 67 Lyons & Standard 115-13kV Distribution Capacity
35 Northwest 115-13kV Sub Age and condition 2021
TNC 33 Transmission to Serve Hillyard Sub Distribution capacity
23 Transmission to Serve Hawthorne Sub Distribution capacity
62 Indian Trail-Waikiki 115kV Line Contingency and capacity
69 Mead-Colbert-Milan 115kV Line Contingency and capacity 2024

2 Corrective Action Plan
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Proposed
Initiative
Existing
Business
Case # Project Name Issue Mitigated
Date of
Operation
Palouse System
Reinforcement
SDSC 49 Center Street 115-13V Sub Distribution Capacity 2023
29 M/P State Line 115-13V Sub Distribution Capacity
87 Tamarack 115/13kV Sub Distribution Capacity
SDSR 71 Moscow City 115kV Sub Age and condition
72
N. Moscow 115kV Station: Add
Transformer Distribution Capacity
74
Palouse Transformation: Add Auto at
Moscow or Shawnee Contingency
77 Potlatch 115/13kV Age and condition
Protection System
Upgrade for PRC-002 PS 79 PRC-002 Protection System Upgrade Compliance 2022
Rattlesnake Flat
Wind Farm PS 2
Rattlesnake Flat 115kV Wind Farm
Project Customer requested 2020
Saddle Mountain
Integration PS 9
Saddle Mountain 230/115kV Sub (Phase
1) Contingency and capacity 2020
13
Saddle Mountain 230/115kV Sub (Phase
2) Contingency and capacity 2021
Sandpoint System
Reinforcement
SDSR 32 Bronx 115/21kV Substation Distribution Capacity 2024
TCC 83 RAT-SPI or ALB-SPI 115kV Line Contingency 2024
Silver Valley System
Reinforcement
SDSC 70 Mission 115kV Sub Age and condition
SDSR 46 Big Creek 115kV Sub Age and condition
TMR-AC 73 Noxon-Pine Creek 230kV Age and condition 2022
South Spokane
System
Reinforcement
PS 42 Beacon 230kV Sub Contingency and capacity
85
Spokane West of Beacon - New 230kV
Transformation3 Contingency and capacity 2025
SDSC 54 Downtown East 115-13kV Sub Distribution Capacity
55 Downtown West 115-13kV Sub Distribution Capacity 2023
4 Southeast 115-13kV Distribution Capacity 2019
SDSR 52 College & Walnut 115kV Sub Age and condition
84 Ross Park 115kV Sub Age and condition
TCC 39 9CE-Sunset 115kV Line Contingency and capacity 2023
44 Beacon-Ross Park 115kV Line Age and condition 2020
Spokane Valley
Transmission
Reinforcement
SDSC 63 Irvin 115/13kV Sub Distribution Capacity 2021
SDSR 41 Barker 115/13kV Substation Distribution Capacity
51 Chester 115-13kV Sub Age and condition
SVTR 14
BEA-BLD #2 115 - Upgrade 314MVA
(TLD4)
Line section outage issues,
motor starting support at IEP
and reliability 2021

3 Corrective Action Plan
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Proposed
Initiative
Existing
Business
Case # Project Name Issue Mitigated
Date of
Operation
12 Irvin 115kV Switching Station4 Contingency and capacity 2021
TCC 43 Beacon-Boulder #1 115kV Line Contingency and capacity 2021
Stevens/Ferry
County System
Reinforcement
SDSC 37 49 Degrees North 115kV Sub Distribution Capacity
34 Valley 115kV Sub Age and condition 2022
TCC 40 Addy-Devils Gap 115kV Line Contingency and capacity 2020
Sunset Station
Rebuild SDSR 15 Sunset 115kV Sub5 Age, condition and reliability 2021
West Plains System
Reinforcement
PS 58 Garden Springs 115/13kV Substation Contingency and capacity 2023
59 Garden Springs 230kV Substation Contingency and capacity
SDSC 16 Flint Road 115/13kV Sub Distribution Capacity 2022
18 Four Lakes - Add Cap Bank P6 low voltage
68 McFarlane 115/13kV Sub Distribution Capacity
TBD 31 Melville Switching Station
Customer requested,
contingency
Westside Station
Rebuild PS 8 Westside 230/115kV Sub (Phase 1-4) Contingency and capacity 2022

4 Corrective Action Plan
5 Corrective Action Plan
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2 IDENTIFIED SYSTEM PROJECTS
Following is a summary of identified system issues, mitigations considered and
recommendations.
2.1 Big Bend System Reinforcement
The Davenport, Little Falls and Sprague stations in the Big Bend area have been identified as a concern due to age and condition. Additionally, the age and condition of the Devil’s Gap –
Lind 115kV Transmission Line has been identified as a concern due to age and condition.
The Chelan – Stratford 115kV Transmission Line has demonstrated overload conditions due to
local hydro generation during contingencies scenarios. The transmission line segments
overloaded are 0.38 miles of 19#8 CW and 33.89 miles of 250 CU conductor with a rating of 78.3 MVA at 40°C.
Mitigation considered
The condition of identified stations and transmission lines due to age and condition should be
analyzed to determine the scope of rebuilding the assets or target specific equipment
replacement.
Recommendations
• Rebuild Davenport, Little Falls, and Sprague stations.
• Minor rebuild of Devils Gap – Lind 115kV Transmission Line.
• Utilize operating procedure to reduce local hydro generation for contingencies impacting
Chelan – Stratford 115kV Transmission Line.
2.2 Cabinet Gorge GSU Isolation
The design to integrate the Cabinet Gorge hydro facility into the 230kV Western Montana Hydro transmission system did not include 230kV breakers to isolate the generation from the
transmission system. This resulted in one zone of protection encapsulating both the Generator
Step-Up (GSU) transformers and the 230kV bus. The deficiency with this design is that it is not
selective enough and drops all 230kV lines, the Cabinet 230/115kV autotransformer and all Cabinet Gorge generation for issues with the either GSU.
Studies have identified the following contingency issue:
• Loss of a single Cabinet Gorge GSU (P1.3) results in the loss of up to 240MW of
generation, two 230kV lines, and a 230/115kV autotransformer.
Mitigation considered
• Full rebuild of Cabinet Substation.
• Modify the existing Cabinet Substation with the addition of high-side GSU circuit
breakers.
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• Building a new switching station west of the existing Cabinet Substation to incorporate
breakers and loop in the Lancaster – Noxon 230kV Transmission Line.
Recommendations
• A reliability upgrade to Cabinet substation consisting of a new 230kV breaker for each
GSU, relocating two termination towers and adding new 230kV bus. Upgrades will
require updates to GSU and bus relay protection.
2.3 Coeur d'Alene System Reinforcement
The Coeur d’Alene area is served by two 230/115kV autotransformers and a single 115kV
transmission line. The Coeur d’Alene area is connected by one additional 115kV transmission
line that has historically been operated normally open. The autotransformers along with the 115kV transmission lines feeding Coeur d’Alene load may overload for multiple contingency events during moderate to heavy loading during all seasons.
Studies have identified the following contingency issues:
• Loss of the Rathdrum 115kV east bus (P2.2) or a breaker failure on the Rathdrum
115kV east bus (P2.3) may result in an overload of a 115kV transmission line.
• Loss of the Pine Street – Rathdrum 115kV Transmission Line followed by the loss of a
230/115kV autotransformer (P6) may result in an overloaded 230/115kV
autotransformer.
• Loss of a Rathdrum 230/115kV autotransformer followed by the loss of a 230/115kV
autotransformer (P6) may result in voltage collapse in the Coeur d’Alene area. This
results in the loss of up to 140MW of generation and 275MW of load.
• A Rathdrum 115kV bus tie breaker failure during any season results in the loss of up to 140MW of generation and 275MW of load in the Coeur d’Alene area.
Load growth in the Coeur d’Alene area has contributed to heavy loaded distribution facilities.
The following stations have feeders which have exceeded 80% of their applicable facility
ratings: Appleway, Dalton, Huetter, Post Falls, Prairie and Idaho Road. Anticipated load growth
will increase the feeder loading and reduce necessary operational capacity.
The Prairie Station in the Coeur d’Alene area has been identified as a concern due to age and
condition.
Mitigation considered
Transmission system contingency issue mitigation alternatives include the following:
• Operate the Coeur d’Alene – Pine Creek 115kV Transmission Line normally closed and
revert back to the original 115kV transmission line configuration between Coeur d’Alene
and Spokane Valley.
o Requires upgrading the transmission lines connecting Coeur d’Alene and
Spokane Valley.
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• Operate the Coeur d’Alene – Pine Creek 115kV Transmission Line normally closed and
build a new switching station near the crossing of Chase Road and Poleline Avenue.
• Build a new 230/115kV substation between Boulder Substation and Rathdrum
Substation and integrate the existing 115kV transmission lines into this new substation.
• Build a new 230/115kV substation southeast of Coeur d’Alene with a 230kV tie to Pine Creek and integrate the existing 115kV transmission lines into the new substation.
Upgrade existing distribution stations with additional feeder capacity including: Dalton,
Pleasantview, Rathdrum, Huetter, and Prairie.
The condition of identified stations due to age and condition should be analyzed to determine
the scope of rebuilding the assets or target specific equipment replacement.
Recommendations
• The transmission system contingency mitigation project’s specific scope and impact will
be evaluated by the responsible parties within Avista to assist in the development of a
coordinated business and implementation plan that will be presented to the Engineering Roundtable (ERT) for approval, prioritization, and deployment.
• Rebuild Pleasantview and Prairie stations.
2.4 East Coeur d'Alene Lake System Reinforcement
Forecasted load growth along the east side of Coeur d’Alene Lake is expected to cause the total load to exceed the capability of the existing 13.2 kV distribution system in the area.
Feeder protection coordination and voltage regulation are not able to meet necessary
performance requirements. Cold load pickup will cause protection devices to function during
moderate to heavy loading levels.
Feeder loading from the St. Maries Station are near capacity. Recent growth in the area including a large industrial customer with 2300 horsepower of motor load will further increase
equipment loading and reduce operational flexibility to maintain and back up feeders. The lack
of Supervisory Control and Data Acquisition (SCADA) at St. Maries Station creates safety
concerns and does not allow necessary situational awareness of the equipment status.
The Benewah – Pine Creek 230kV Transmission Line has been identified as a concern due to age and condition.
Mitigation considered
• Construct new Carlin Bay Station with a 13 mile radial 115kV transmission line to a
rebuilt O’Gara Station.
• Convert area distribution system to 25kV.
• Upgrade St. Maries Station with fourth feeder and addition of SCADA.
• Rebuild the Benewah – Pine Creek 230kV Transmission Line
Recommendations
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• Construct new Carlin Bay Station with a 13 mile radial 115kV transmission line to a
rebuilt O’Gara Station.
• Upgrade St. Maries Station with fourth feeder and addition of SCADA.
2.5 Idaho/Lewis County System Reinforcement
The Grangeville and Kooskia stations in the Idaho/Lewis county area have been identified as a concern due to age and condition.
Mitigation considered
The condition of identified stations due to age and condition should be analyzed to determine
the scope of rebuilding the assets or target specific equipment replacement.
Recommendations
• Rebuild Grangeville and Kooskia stations
2.6 Kettle Falls Stability
Implementation of a high speed, communication aided tripping scheme on the Addy – Kettle
Falls 115kV Transmission Line is necessary to improve stability performance of the Kettle Falls generation facility. Stability contingency analysis indicates an inability of the System to meet the performance requirements in requirement R4.1.1 of TPL-001-4.
Studies have identified the following contingency issue:
• The Kettle Falls generator can become unstable if a time delayed three phase fault occurs on the Addy – Kettle Falls 115kV Transmission Line near Addy.
Mitigation considered
• This is a vetted project. Refer to past studies for mitigation options.
Recommendations
• The identified contingency issues will require a Corrective Action Plan.
• Modification of the Addy – Kettle Falls 115kV Transmission Line Protection System to
include a communication aided protection scheme. A new communication path is required between Addy and Kettle Falls stations. Upgrades and setting changes to
relays at BPA’s Addy Substation and Avista’s Kettle Falls Substation are also required
to implement Avista’s standard communication aided protection schemes.
2.7 Lewiston/Clarkston System Reinforcement
The existing 230kV system and underlying 115kV lines in the Lewiston/Clarkston area may overload during summer loading and high transfers south on the Idaho – Northwest (Path 14)
cut plane for multiple contingency events. Planned or forced 230kV outages in the
Lewiston/Clarkston area require a radial configuration of the 115kV system, arming RAS
and/or reducing transfers on the Idaho – Northwest or West of Hatwai cut planes.
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Studies have identified the following contingency issues:
• Loss of Dry Creek – North Lewiston 230kV Transmission Line followed by the loss of a 230kV transmission line (P6) may result in an overload of multiple 115kV transmission
lines.
• Loss of Hatwai – Lolo 230kV Transmission Line followed by the loss of a 230/115kV
autotransformer or any of two 230kV transmission lines (P6) may result in an overload of multiple 115kV transmission lines.
• Loss of the North Lewiston 230/115 #1 Transformer followed by the loss of a 230kV
transmission line (P6) may result in an overloaded 115kV transmission line.
Load growth in the Lewiston/Clarkston area has contributed to heavy loaded distribution facilities. The following stations have feeders which have exceeded 80% of their applicable
facility ratings: Lolo, Critchfield, and Tenth & Stewart. Anticipated load growth will increase the
feeder loading and reduce necessary operational capacity.
The South Lewiston, Lolo and Pound Lane stations in the Lewiston/Clarkston area have been
identified as a concern due to age and condition. Additionally, the age and condition of the Lolo
– Oxbow 230kV Transmission Line has been identified as a concern due to age and condition.
Mitigation considered
Transmission system contingency issue mitigation alternatives include the following:
• Rebuild the overloaded 115kV transmission lines that were identified in the study.
• Rebuild South Lewiston substation into a switching station and close all three lines into
the new station.
o Reduces contingency overloads, but does not correct overload issues.
• Build a new second Hatwai – Lolo 230kV transmission line to either connect into Lolo
Substation or bypass the Lolo Substation and connect directly to Oxbow Substation.
This may require a new transmission line terminal at Lolo Station and a request for
interconnection at BPA’s Hatwai Station.
Rebuild existing distribution stations with additional feeder capacity.
The condition of identified stations due to age and condition should be analyzed to determine
the scope of rebuilding the assets or target specific equipment replacement.
Recommendations
• The transmission system contingency mitigation project’s specific scope and impact will be evaluated by the responsible parties within Avista to assist in the development of a coordinated business and implementation plan that will be presented to the Engineering
Roundtable (ERT) for approval, prioritization, and deployment.
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• Rebuild Tenth & Stewart and Pound Lane stations and targeted equipment replacement
at Lolo Station.
• Construct new Bryden Canyon and Wheatland stations.
• Rebuild portions of the Lolo – Oxbow 230kV Transmission Line and evaluate priorities
of other 230kV transmission line rebuilds.
2.8 Metro Station Rebuild
Metro Station dates to the mid-1970s. Switchgear is the worst condition on the system. Much
of the major equipment in this station is now unsupported by the manufacturer. Legacy oil
tanks beneath the site pose an environmental problem and limit modifications to upgrade the existing station. Underground transmission cables to this site are in need of replacement. Transformer/switchgear spares are unavailable/difficult to install in an outage scenario.
Various other condition issues, such as the 115kV breakers, insulators, and panel house, also
exist at this site.
Additionally, the age and condition of the Metro – Post Street and Post Street – Third & Hatch
115kV transmission lines has been identified as a concern due to age and condition.
Mitigation considered
• Rebuild Metro Station by replacing existing equipment with new.
• Rebuild Metro Station with new equipment in an improved configuration.
• Construct a new station on a new site to replace the existing Metro Station.
• Replace existing transmission cable on the Metro – Post Street and Post Street – Third
& Hatch 115kV transmission lines.
Recommendations
• Construct a new station on a new site to replace the existing Metro Station.
• Replace existing transmission cable on the Metro – Post Street and Post Street – Third & Hatch 115kV transmission lines.
2.9 North Spokane System Reinforcement
Avista’s Beacon and BPA’s Bell substations are connected by two 115kV lines, either of which
may overload for multiple contingency events during moderate to heavy loading during all seasons. Note that the additional autotransformer capacity, which is planned for the South Spokane area, will increase the overloads identified in these results.
Studies have identified the following contingency issues:
• A Beacon 115kV bus tie breaker fault (P2.4) may result in an overload of multiple 115kV
transmission lines.
• Loss of the Beacon – Bell 115kV Transmission Line followed by the loss a 230/115kV
autotransformer (P6) may result in an overload of multiple 115kV transmission lines.
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• Loss of the Beacon – Northeast 115kV Transmission Line followed by the loss a
230/115kV autotransformer (P6) may result in an overloaded 115kV transmission line.
• Loss of the Bell 230/115kV #6 Transformer followed by the loss of any of two 115kV
transmission lines (P6) may result in an overloaded 115kV transmission line.
• Loss of the Bell – Northeast 115kV Transmission Line followed by the loss a 230/115kV autotransformer (P6) may result in an overloaded 115kV transmission line.
• Loss of the Francis & Cedar – Ross Park 115kV Transmission Line followed by the loss
of a 115kV transmission line (P6) may result in an overloaded 115kV transmission line.
Load growth in the North Spokane area has contributed to heavy loaded distribution facilities. The following stations have feeders which have exceeded 80% of their applicable facility
ratings: Colbert, Francis & Cedar, Waikiki and Mead. Anticipated load growth will increase the
feeder loading and reduce necessary operational capacity.
The Northwest Station in the North Spokane area has been identified as a concern due to age
and condition.
Mitigation considered
Transmission system contingency issue mitigation alternatives include the following:
• Rebuild the overloaded 115kV transmission lines that were identified in the study.
o This requires the rebuild of the Beacon – Bell, Beacon – Northeast, Bell – Northeast, and Beacon – Francis & Cedar 115kV transmission lines.
• Add Remedial Action Scheme (RAS) to drop load in the BPA area.
o Solution only solves BPA related issues, but does not correct remaining Avista
related transmission line loading issues.
• Build a new 115kV transmission line from Indian Trail substation to Waikiki substation
and add breaker positions to both stations.
o Does not correct all identified 115kV transmission line overloads.
• Loop the Beacon – Francis & Cedar 115kV transmission line into Bell.
Rebuild existing distribution stations with additional feeder capacity and construct new
distribution stations.
The condition of identified stations due to age and condition should be analyzed to determine
the scope of rebuilding the assets or target specific equipment replacement.
Recommendations
• The transmission system contingency mitigation project’s specific scope and impact will
be evaluated by the responsible parties within Avista to assist in the development of a
coordinated business and implementation plan that will be presented to the Engineering Roundtable (ERT) for approval, prioritization, and deployment.
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• Rebuild Northwest Station.
• Construct new Florida & Dalke, Hawthorne and Midway stations.
• Construct new 115kV infrastructure to the north of Spokane to interconnect Avista
distribution stations into Avista’s transmission system.
2.10 Palouse System Reinforcement
The Palouse area is served by two 230/115kV autotransformers and a single 115kV line. The
Palouse is connected by four additional 115kV transmission lines that have historically been
operated normally open. These autotransformers along with the 115kV transmission lines
feeding Palouse load may overload for multiple contingency events during moderate to heavy loading (all seasons).
Studies have identified the following contingency issues:
• Loss of a Palouse area 230/115kV autotransformer followed by the loss of a 230/115kV
autotransformer (P6) may result in voltage collapse in the Palouse area. This results in
the loss of up to 186MW of load.
• Loss of the Moscow – South Pullman 115kV Transmission Line followed by the loss a
230/115kV autotransformer (P6) may result in an overloaded 115kV transmission line.
• Loss of the Moscow – Terre View 115kV Transmission Line followed by the loss a 230/115kV autotransformer (P6) may result in an overloaded 115kV transmission line.
Load growth in the Palouse area has contributed to heavy loaded distribution facilities. The
following stations have feeders which have exceeded 80% of their applicable facility ratings:
Turner. Anticipated load growth will increase the feeder loading and reduce necessary
operational capacity.
The Moscow City and Potlatch stations in the Palouse area have been identified as a concern
due to age and condition.
Mitigation considered
Transmission system contingency issue mitigation alternatives include the following:
• Add a new position at Moscow and extend the Moscow City – North Lewiston 115kV
Transmission Line into Moscow 230 Station. Operate with Moscow City normally fed
from this line, with the auto-throwover to the Moscow – South Pullman 115kV
Transmission Line.
• Add a second 230/115kV autotransformer at Moscow or Shawnee stations.
• Build a new 230/115kV station east of Pullman and integrate the existing 115kV
transmission lines into the new station.
Construct new and rebuild existing distribution stations with additional feeder capacity.
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The condition of identified stations due to age and condition should be analyzed to determine
the scope of rebuilding the assets or target specific equipment replacement.
Recommendations
• The transmission system contingency mitigation project’s specific scope and impact will
be evaluated by the responsible parties within Avista to assist in the development of a
coordinated business and implementation plan that will be presented to the Engineering
Roundtable (ERT) for approval, prioritization, and deployment.
• Construct new Center Street, State Line and Tamarack stations.
• Rebuild Moscow City and Potlatch stations.
2.11 Protection System Upgrade for PRC-002
NERC reliability standard PRC-002-2 defines the disturbance monitoring and reporting
requirements to have adequate data available to facilitate analysis of Bulk Electric System
(BES) Disturbances. The methodology of Attachment A of the NERC standard was performed
to identify the affected buses within the Avista BES. The Protection Systems must be capable
of recording electrical quantities for each BES Elements it owns connected to the BES buses identified.
The present Protection Systems are either electromechanical or first generation relays not
capable of meeting the NERC PRC-002-2 standard requirements of fault recording.
Implementation is a phased approach with 50% compliant within four years and fully compliant
within six years of the July 1, 2016 effective date. There is a total of 49 affected terminals.
Mitigation considered
Upgrade the existing Protection Systems on various 230kV and 115kV terminals to Fault
Recording (FR) capability per PRC-002 requirements at Beacon, Boulder, Rathdrum, Cabinet
Gorge, North Lewiston, Lolo, Pine Creek, Shawnee and Westside.
Recommendations
• Complete Protection System Upgrades for PRC-002 Business Case.
2.12 Rattlesnake Flat Wind Farm
An Interconnection Customer (Project #49) has requested interconnection of a new Wind Power Plant (WPP) generation facility located southeast of Lind, Washington. The customer
has chosen an interconnection to Avista’s Lind - Washtucna 115kV Transmission Line,
approximately 4.5 miles south of the Lind Station, requiring a new 115kV Neilson Station at the
Point of Interconnection (POI) with a 115kV line position dedicated for the Interconnection
Customer. Project #49 will have an aggregate nameplate capacity of 144MW and will consist of seventy-two (72), Vestas V110, 2.0MW Wind Turbine Generators (WTG).
Mitigation considered
• Rebuild Lind Station to accept the generator lead line with the POI at Lind Station.
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• Construct new Neilson Station as the POI and rebuild the transmission line from Neilson
to Lind.
Recommendations
• Construct network upgrades and direct assigned facilities according to Project #49
Facilities Study.
2.13 Saddle Mountain Integration
In the fall of 2013, Grant employees contacted Avista System Planning about performance
issues within Grant’s system that are exacerbated by Avista’s load in the Othello area. The
issue was escalated to ColumbiaGrid through the Regional Planning process. It was identified
through this process and Avista System Planning that the system performance analysis indeed indicates an inability of the System to meet the performance requirements P1, P2 and P6 categories in Table 1 of NERC TPL-001-4 in current heavy summer scenarios, and P6
categories in heavy winter scenarios.
Studies have identified the following contingency issues:
• Loss of the Benton – Othello SS 115kV line followed by the loss of the Sand Dunes – Warden 115kV line during summer loading may overload the Larson – Sand Dunes –
Warden 115kV line (up to 116%).
• Loss of the Larson – Sand Dunes – Warden 115kV line, followed by load restoration (Wheeler to Basset Jct. 115kV line section outage shows worst performance), followed by the loss of the Sand Dunes – Warden 115kV line during spring and summer loading
will overload the Benton – Othello SS 115kV line and result in voltage collapse in the
Othello area (drops up to 168MW).
Mitigation considered
• Construct Saddle Mountain Station, one new 115kV transmission line from Saddle
Mountain to Othello City, and a new Othello City Station.
• Build new 115kV transmission line into the area from the Stratford area.
• Close normally open points to the east of the area.
Recommendations
• Complete Saddle Mountain Project (Phase 1 and Phase 2).
2.14 Sandpoint System Reinforcement
Load growth around Sandpoint is expected to cause the total load to exceed the capability of
the existing 20.8 kV distribution system in the area. The existing Sandpoint Station distribution
transformers are unique to Avista’s system. Mobile transformers cannot be used to replace a
failed transformer at this site. Continued load growth increases the risk of reliability serving customers in the area with potential equipment failure.
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Previous transmission system studies have shown P6 contingency performance issues when
two of the three transmission lines into the Sandpoint area are out of service. The issues
observed were primarily low voltages during heavy winter loading. BPA has also documented in their 2019 System Assessment Summary Report observed performance issues in the area.
Mitigation considered
Rebuild the Bronx Station to provide distribution service to the area.
Construct new 115kV transmission line from Rathdrum or Albeni Falls towards Sandpoint.
Recommendations
• Rebuild the Bronx Station to provide distribution service to the area.
• Perform a detailed project analysis to determine risks and mitigations to low voltages in
the area.
2.15 Silver Valley System Reinforcement
The Mission and Big Creek stations in the Silver Valley area have been identified as a concern
due to age and condition. The feeder served by Mission Station has protection selectivity
concern due to the feeder trunk extending two distinctly different directions.
The age and condition of the Noxon – Pine Creek 230kV Transmission Line has been identified as a concern due to age and condition.
Mitigation considered
The condition of identified stations and transmission lines due to age and condition should be
analyzed to determine the scope of rebuilding the assets or target specific equipment replacement.
Recommendations
• Rebuild Big Creek station.
• Upgrade Mission Station with a second feeder position.
• Minor rebuild of Noxon – Pine Creek 230kV Transmission Line.
2.16 South Spokane System Reinforcement
The Spokane area is served by five 230/115kV autotransformers. These autotransformers along with the 115kV transmission lines feeding Spokane load may overload for multiple
contingency events during moderate to heavy loading (all seasons). Existing mitigation
projects (Ford – Devils Gap 115kV Transmission Line section rebuild, Irvin Switching Station,
capacity at Westside) help reduce the amount of overloading, but do not correct known
contingency issues. Steady state contingency analysis indicates an inability of the System to meet the performance requirements in requirement R3.1 of TPL-001-4 for the Beacon 115kV tie breaker failure.
Studies have identified the following contingency issues:
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• A Beacon 230kV or 115kV bus tie breaker fault (P2.4) may result in an overloaded
230/115kV autotransformer and multiple 115kV transmission lines.
• A Ninth & Central 115kV bus tie breaker fault (P2.4) may result in an overloaded 115kV
transmission line.
• Loss of an Addy – Bell 115kV Transmission Line section followed by the loss of any of three 230/115kV autotransformers (P6) may result in an overloaded 230/115
transformer and multiple 115kV transmission lines.
• Loss of any of three 230/115kV autotransformers followed by the loss of a remaining
230/115kV autotransformer (P6) may result in an overloaded 230/115kV autotransformer and multiple 115kV transmission lines.
• Loss of either Beacon – Ninth & Central 115kV transmission line followed by the loss of
any of three 115kV transmission lines (P6) may result in an overload of multiple 115kV
transmission lines.
• Loss of the Bell – Westside 230kV Transmission Line followed by the loss of any of
three 230/115kV autotransformers (P6) may result in an overloaded 230/115
transformer.
• Loss of the College & Walnut – Westside 115kV Transmission Line followed by the loss of any of two 115kV transmission lines (P6) may result in an overload of multiple 115kV
transmission lines.
The College & Walnut and Ross Park stations in the Spokane area have been identified as a
concern due to age and condition.
The Beacon – Ross Park 115kV Transmission Line has been identified as a concern due to age and condition.
Mitigation considered
Transmission system contingency issue mitigation alternatives include the following:
• Increase the capacity of the Bell #6 230/115kV Transformer.
o Does not correct remaining Spokane area 230/115kV transformer loading issues
or resolve 115kV line loading issues feeding the West Plains area.
• Rebuild Beacon to a more reliable breaker arrangement or add a series breaker to both the bus tie breakers.
o Does not correct remaining Spokane area 230/115kV autotransformer loading
issues or resolve 115kV transmission line loading issues feeding the West Plains
area.
• Rebuild the overloaded 115kV transmission lines
o Does not correct Spokane area 230/115kV autotransformer loading issues.
• Loop the Beacon – Francis & Cedar 115kV Transmission Line into Bell Station.
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o Does not correct Spokane area 230/115kV autotransformer loading issues.
• Build a new 115kV transmission line from Westside Station to the West Plains area or to the Spokane downtown area.
o Does not correct Spokane 230/115kV autotransformer loading issues.
• Add a new 230/115kV transformation at Ninth & Central Station and associated 230kV
transmission lines.
The condition of identified stations and transmission lines due to age and condition should be
analyzed to determine the scope of rebuilding the assets or target specific equipment
replacement.
Recommendations
• The identified contingency issues will require a Corrective Action Plan.
• The transmission system contingency mitigation project’s specific scope and impact will
be evaluated by the responsible parties within Avista to assist in the development of a
coordinated business and implementation plan that will be presented to the Engineering Roundtable (ERT) for approval, prioritization, and deployment.
• Construct new Downtown East and Downtown West stations.
• Rebuild College & Walnut and targeted equipment replacement at Ross Park stations.
• Rebuild the Beacon – Ross Park 115kV Transmission Line.
2.17 Spokane Valley Transmission Reinforcement
The Spokane Valley Transmission Reinforcement project improves transmission system
performance by networking the 115kV transmission lines in the area together at Irvin and Opportunity stations. This reinforcement was necessitated by area load growth along with
motor starting voltage issues resulting from the integration of two 25MW synchronous motors
at Inland Empire Paper in 2007. Steady state contingency analysis indicates an inability of the
System to meet the performance requirement in TPL-001-4 R3.1 for the Boulder 115kV tie
breaker failure.
Studies have identified the following contingency issues:
• Loss of a Liberty Lake – Otis Orchards 115kV Transmission Line section or a Nelson –
Ninth & Central 115kV Transmission Line section (P2.1) can load the remaining transmission line to its thermal limit. This has resulted in transferring all load growth to adjacent transmission facilities.
• A Boulder 115kV bus tie breaker fault (P2.4) may result in an overloaded 115kV
transmission line above 125% of rating.
• Loss of the Beacon – Ross Park 115kV Transmission Line followed by the loss of any of
two 115kV transmission lines (P6) may result in an overloaded 115kV transmission line.
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• Loss of the College & Walnut – Westside 115kV Transmission Line followed by the loss
of any of two 115kV transmission lines (P6) may result in an overload of multiple 115kV transmission lines.
• Loss of the Opportunity – Otis Orchards 115kV Transmission Line followed by the loss
of any of two 115kV transmission lines (P6) may result in an overloaded 115kV
transmission line.
Mitigation considered
• This is a vetted project. Refer to past studies for mitigation options.
Recommendations
• The identified contingency issues will require a Corrective Action Plan.
• Complete Spokane Valley Transmission Reinforcement Business Case including
installation of the Irvin Station.
• Increase distribution capacity at Barker Station and add distribution facilities to Irvin
Station.
• Rebuild Chester Station.
2.18 Stevens/Ferry County System Reinforcement
The Valley Station in the Stevens/Ferry county area has been identified as a concern due to
age and condition.
The 49 Degrees North Ski Resort has an expansion plan which will exceed the capacity of the
existing distribution system. The existing distribution is being reinforced to accommodate the
planned expansion, but there is limited additional capacity.
Mitigation considered
The condition of identified stations due to age and condition should be analyzed to determine
the scope of rebuilding the assets or target specific equipment replacement.
Construct a new 49 Degrees North distribution station to serve additional load growth.
Expand Chewelah Station with a new transformer and dedicated feeder.
Recommendations
• Rebuild Valley Station.
• Construct a new 49 Degrees North distribution station when customer request is received.
2.19 Sunset Station Rebuild
The existing circuit breakers at the station do not have sufficient short circuit interrupting
capability to interrupt close in faults on the connected transmission lines. The available fault current increases with the necessary transmission system expansion to address other system
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deficiencies (i.e. Westside transformer replacement). Short circuit analysis indicates an
inability of the System to meet the performance requirements in requirement R2.8 of TPL-001-
4.
Mitigation considered
Analysis of potential reconfiguration of the station concluded the station should be rebuilt with
five transmission line terminals to match the existing station. The analysis reviewed potential
reconfigurations with the objective of minimizing the station size. All configurations considered
did not provide desired transmission system performance or reliability.
Recommendations
• The identified issues will require a Corrective Action Plan.
• The Sunset Station has been identified for a complete rebuild.
2.20 West Plains System Reinforcement
The West Plains and Sunset area (up to 245MW) is served by (4) 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 & Central – Sunset 115kV Transmission Line rebuild) help reduce the amount of overloading, but do not correct known contingency issues.
Studies have identified the following contingency issues:
• Loss of the Ninth & Central – Sunset 115kV Transmission Line followed by the loss of
any of four 115kV transmission lines (P6) may result in an overload of multiple 115kV transmission lines.
• Loss of the Sunset – Westside 115kV Transmission Line followed by the loss of any of
six 115kV transmission lines (P6) may result in an overload of multiple 115kV transmission lines.
Load growth in the West Plains area has contributed to heavy loaded distribution facilities. The
following stations have feeders which have exceeded 80% of their applicable facility ratings:
Airway Heights. Anticipated load growth will increase the feeder loading and reduce necessary
operational capacity.
Mitigation considered
Transmission system contingency issue mitigation alternatives include the following:
• Rebuild the overloaded 115kV transmission lines that were identified in the study.
o This requires the rebuild of the College & Walnut – Westside, Francis & Cedar –
Northwest, Ninth & Central – Third & Hatch, Post Street – Third & Hatch, Ross Park – Third & Hatch and Sunset – Westside 115kV transmission lines.
• Build a new seven mile 115kV transmission line from Westside Station to the West
Plains area.
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• Add a new 230/115 transformation at Garden Springs and associated 230kV lines.
Construction of new distribution stations and related 115kV transmission line integration will support the anticipated load growth.
Recommendations
• The transmission system contingency mitigation project’s specific scope and impact
was evaluated by the responsible parties within Avista to assist in the development of a coordinated business and implementation plan that was presented to the Engineering
Roundtable (ERT), approved and prioritized for deployment.
• Construct new Flint Road, McFarlane, and Melville stations with transmission line
integration according to the West Plains Reinforcement Plan.
2.21 Westside Station Rebuild
Westside Substation was the last remaining Spokane area substation with 125 MVA rated
autotransformers. In past studies, the Westside autotransformers would overload for multiple
contingency events during moderate to heavy loading in all seasons. The Westside
autotransformers are being upgraded to two 250 MVA rated units. Planned reliability improvements to both the 115kV and 230kV bus arrangements are also in this scope, which
were required due to increased fault duty from the larger transformers.
Refer to previous studies for identified contingency issues that nucleated the Westside
autotransformer upgrade.
The Westside Station is currently being rebuilt, with completion planned for fall of 2022. The construction sequence has resulted in the following temporary contingency issues:
• Loss of the Westside 115kV southwest bus (P2.2) or a breaker failure on the Westside
115kV southwest bus (P2.3) may result in an overload of multiple 115kV transmission lines.
Mitigation considered
• This is a vetted project, refer to past studies for mitigation options.
Recommendations
• Complete the installation of the second 250 MVA autotransformer.
• Complete the 230kV Double Breaker Double Bus arrangement.
• Complete the 115kV Double Breaker Double Bus arrangement.

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3 COMPLETED PROJECTS
Project Name Project Scope Targeted Date of
Operation
Sandcreek-Bronx-Cabinet Rebuild Reconductor Bronx to Sand Creek with 795 ACSS Completed in 2017
Noxon Rapids 230kV Breaker
Replacement
Replace 6 limiting circuit breakers with 40kA fault
current interrupting capability and operate at a steady state voltage of 253 kV Completed in 2018
Westside Transformer
Replacement Auto#1 was replaced and placed into service Completed in 2018
Addy – Devil’s Gap 115kV Transmission Line
Reconductor 5.19 miles (rebuild between Ford and Long Lake Tap) of limiting conductor which consist
of 266.8 ACSR and 397.5 ACSR conductor resulting in a capacity limitation of 71.5 MVA at
40°C, to be rebuilt to a capacity of 150 MVA at 40°C (likely 240MVA)
Completed in Jan.
2019 (Data included in
2019 Master Case)
Saddle Mountain Integration Othello SS – Warden No.1 115kV Transmission Line upgraded to minimum 240 MVA @ 40°C.
Completed in Feb.
2019 (Data included in
2019 Master Case)
Othello – Warden#2 Partial Rebuild
(Saddle Mountain)
** included in 2020 studies
Replace 2.8 Miles of conductor w/ 795 ACSS
200°C from OSS to OTH City.
Completed in March 2019
(Data included in 2019 Master Case)
Lee & Reynolds Rebuild Substation rebuild. Install 2 – 30 MVA transformers and 6 feeders Completed in May 2019
Hallett & White Rebuild Substation rebuild. Install 2 – 30 MVA transformers
and 6 feeders
Completed in June
2019
North Lewiston Reactors Install two 50 MVAr shunt reactors to the existing
230kV bus at North Lewiston Station
Completed in July 2019
(Data included in 2019 Master Case)
Ford Substation Rebuild Rebuild station with 10 MVA transformer. Tapped
off of ADD-DGP line
Completed in
December 2019
Boulder Substation Install 1 – 30 MVA transformer for load support Completed in October 2019
Priest River Feeder bay rebuild, expanded to two feeders Completed in
October 2018
TABLE 2 COMPLETED PROJECTS

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V TECHNICAL ANALYSIS RESULTS
1 STEADY STATE CONTINGENCY ANALYSIS
The state of the current system study examined system normal and outage simulations on all
seasons of the 2020 base cases to determine the present ‘state of the system’ as it exists
today. The existing system configuration was modeled in 2020 Heavy and Light Summer,
2020-21 Heavy and Light Winter, 2020 Spring (high generation, low load) and 2020 high east to west transfer (Montana-Northwest Path 8 and West of Hatwai Path 6 near limits).
Included in the 2020 cases were completed projects and select projects under construction.
Significant system reinforcements or system changes since 2018 are as follows:
• Ninth and Central distribution load moved onto the 115kV bus.
• Westside 230/115 auto-transformers increased to 250 MVA.
• Coeur d’Alene – Pine Creek 115kV line increased capacity to 240 MVA.
• Adams-Neilson Solar (20 MVA) interconnected at Lind Substation.
• Cabinet – Bronx – Sand Creek 115kV line increased capacity to 143 MVA.
• Addy – Devils Gap 115kV line increased capacity to 120 MVA.
• Lind – Warden 115kV line increased capacity to 262 MVA.
• Othello SS – Warden #1 115kV line increased capacity to 262 MVA.
• Othello SS – Warden #2 115kV line increased capacity to 123 MVA.
• North Lewiston Reactors – two steps of 50 MVAr each.
• Benton – Othello SS 115kV line increased capacity to 138 MVA
Known outages of generation or transmission facilities with a duration of at least six months were also included in the 2020 cases as follows:
• Lancaster – Noxon 230kV line derated to 255 MVA by BPA beginning in 2017.
Study results show several previously known issues are now resolved, and few new problems have been observed in the current studies. None of the contingencies evaluated resulted in
Instability, Cascading, Uncontrolled Separation or IROLs. Study results are summarized as
follows.
1.1 Thermal Issues
P0 – No system elements show thermal overload under system normal conditions.
P1.1-P1.4 – No system elements show thermal overload under N-1 conditions, such as the
loss of a generator, transmission circuit, transformer or shunt device.
P2.1 – No system elements show thermal overload with the opening of a line section without a
fault during peak loading.
• Loss of the Liberty Lake – Otis Orchards 115kV line section during summer loading may
load the Ninth & Central – Opportunity 115kV line (up to 98%).
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• Loss of the Nelson – Ninth & Central 115kV line section during summer loading may
load the Opportunity – Otis Orchards 115kV line (up to 98%).
• Planned mitigation is to complete the Spokane Valley Transmission Reinforcement (fall
of 2021).
P2.2 – Several system elements can become thermally overloaded resulting from a bus
section fault during peak loading.
• Loss of the Lolo 115kV bus during summer loading may overload the Clearwater –
North Lewiston 115kV line (up to 96%, 116% if either Clearwater generator is offline)
o The Clearwater – North Lewiston 115kV line is protected by thermal relays and
will automatically drop load (157MW of load, 48MW of generation) when overloaded per SOP 03.
• Loss of the Hot Springs 230kV bus during high Montana to Northwest (Path 8) transfers
may overload the Lancaster – Rathdrum 230kV line (up to 107%).
o Known issue with BPA’s Lancaster – Rathdrum 230kV line derate. BPA will mitigate in real time until the line derate is corrected (fall of 2021).
• Loss of the Rathdrum 115kV east bus during summer loading may overload the
Rathdrum 230/115 transformer #1 (up to 103%) and overload the Ramsey – Rathdrum
#1 115kV line (up to 109%).
o Existing mitigation is transfer Coeur d’Alene area load to Pine Creek.
o Refer to Coeur d'Alene System Reinforcement.
• Loss of the Westside 115kV southwest bus during summer loading may overload the
Ross Park – Third & Hatch 115kV line (up to 114%), the Francis & Cedar – Northwest 115kV line (up to 105%), and the Post Street – Third & Hatch 115kV line (up to 111%).
o Existing mitigation is to shed load (up to 60MW) in the South Spokane area until
Westside rebuild is complete.
o Planned mitigation is to complete the Westside Station Rebuild (fall of 2022).
• Loss of the Larson 115kV bus during spring and summer loading may overload the Chelan - Stratford 115kV line (up to 112%).
o Existing mitigation is to move open point on the Devils Gap – Stratford 115kV line
to Devils Gap.
P2.3 – Several system elements can become thermally overloaded resulting from an internal breaker fault (non-bus tie breaker) during peak loading:
• A breaker failure on the Lolo 115kV bus (5 CB’s & 1 CS) during summer loading may
overload the Clearwater – North Lewiston 115kV line (up to 96%, 116% if either
Clearwater generator is offline).
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o The Clearwater – North Lewiston 115kV line is protected by thermal relays and
will automatically drop load (157MW of load, 48MW of generation) when
overloaded per SOP 03.
• A breaker failure on the Hot Springs 230kV bus (6 CB’s) during high east to west
transfers may overload the Lancaster – Rathdrum 230kV line (up to 106%).
o Known issue with BPA’s Lancaster – Rathdrum 230kV line derate. BPA will
mitigate in real time until derate is corrected (fall of 2021).
• A breaker failure on the Rathdrum 115kV east bus (7 CB’s) during summer loading may
overload the Ramsey – Rathdrum #1 115kV line (up to 101%) and load the Rathdrum
230/115 transformer #1 to near rating.
o Existing mitigation is transfer Coeur d’Alene area load to Pine Creek.
o Refer to Coeur d'Alene System Reinforcement.
• A breaker failure on the Westside 115kV southwest bus (3 CB’s) during summer loading
may overload the Ross Park – Third & Hatch 115kV line (up to 114%), the Francis &
Cedar – Northwest 115kV line (up to 105%), and the Post Street – Third & Hatch 115kV line (up to 111%).
o Existing mitigation is to shed load (up to 60MW) in the South Spokane area.
o Planned mitigation is to complete the Westside Station Rebuild (fall of 2022).
• A breaker failure on the Larson 115kV bus (9 CB’s) during spring and summer loading may overload the Chelan - Stratford 115kV line (up to 112%).
o Existing mitigation is to move open point on the Devils Gap – Stratford 115kV line
to Devils Gap.
P2.4 – Several system elements can become thermally overloaded resulting from an internal
breaker fault on a bus tie breaker during peak loading:
• A Beacon 230kV bus tie breaker failure during summer loading may overload the Bell
230/115 transformer #6 (up to 100%), the Bell – Northeast 115kV line (up to 114%), and
the Francis & Cedar – Northwest 115kV line (up to 105%).
o Existing mitigation is to shed load (up to 40MW) in the North Spokane area.
o Refer to South Spokane Transmission Reinforcement.
• A Beacon 115kV bus tie breaker failure during summer loading may overload the
Opportunity – Otis Orchards 115kV line (up to 122%), the Francis & Cedar – Northwest
115kV line (up to 121%), the Northwest – Westside 115kV line (up to 116%), and the College & Walnut – Westside 115kV line (up to 102%).
o Existing mitigation is to shed load (up to 90MW) in the South Spokane area.
o Refer to South Spokane Transmission Reinforcement.
• A Boulder 115kV bus tie breaker failure during summer loading may overload the Ninth & Central – Opportunity 115kV line (up to 147%).
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o Existing mitigation is to shed load (up to 56MW) east of Otis Orchards.
o Planned mitigation is to complete the Spokane Valley Transmission
Reinforcement (fall of 2021).
• A Ninth & Central 115kV bus tie breaker failure during summer loading may overload
the Ross Park – Third & Hatch 115kV line (up to 95%, 100% with W2E offline).
o Existing mitigation is to shed load (up to 10MW) in the South Spokane area.
o Refer to South Spokane Transmission Reinforcement.
P3 – Several system elements can become thermally overloaded resulting from the loss of a
generator; followed by system adjustments; followed by a subsequent loss of an additional
transmission circuit, transformer or shunt device.
• Loss of Clearwater unit #3 or #4 followed by the loss of either Clearwater 115/34 transformer during any seasonal loading may overload the remaining Clearwater 115/34
transformer (up to 113%).
o Existing mitigation is to reduce facility load.
• Loss of Clearwater generator unit #3 or #4 followed by the loss of Hatwai – Lolo 230kV line during summer loading may overload the Clearwater – North Lewiston 115kV line
(up to 107%).
o The Clearwater – North Lewiston 115kV line is protected by thermal relays and
will automatically drop load when overloaded per SOP 03.
P4 and P5 – No further results beyond those identified in P2.2 thru P2.4
P6 – Several system elements can become thermally overloaded resulting from an N-1-1
contingency event. This is described as the loss of a transmission circuit, transformer or shunt
device; followed by system adjustments; followed by a subsequent loss of an additional
transmission circuit, transformer or shunt device.
• Loss of the Addy – Bell 115kV line, followed by load restoration (Addy to Loon Lake 115kV line section outage shows worst performance), followed by:
o The loss of either Beacon 230/115 transformer during summer loading may
overload the Bell 230/115 transformer #6 (up to 105%).
▪ Existing mitigation is for BPA to operate within their short term rating.
o The loss of Bell 230/115 transformer #6 during summer loading may overload the Beacon – Bell 115kV line (up to 113%) and Beacon – Northeast 115kV line (up to
102%).
▪ Existing mitigation is to transfer Waikiki to Beacon - Francis & Cedar
115kV line.
▪ Refer to North Spokane Transmission Reinforcement.
• Loss of the Airway Heights – Devils Gap 115kV line, followed by load restoration (Devils
Gap – West Plains 115kV line section outage shows worst performance), followed by:
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o The loss of Nine Mile – Westside 115kV line during light spring loading may
overload the Addy – Devils Gap 115kV line (up to 107%).
▪ Existing mitigation is to limit generation at Nine Mile to 8MW per SOP 20
▪ Planned mitigation is to complete the Addy – Devils Gap 115kV line
section rebuild by correcting bottleneck at Devils Gap (spring of 2020).
• Loss of the either Beacon 230/115 transformer followed by:
o The loss of the remaining Beacon 230/115 transformer during summer loading may overload the Bell 230/115 transformer #6 (up to 126%), the Beacon –
Northeast 115kV line (up to 104%), and the Francis & Cedar – Northwest 115kV
line (up to 100%).
▪ Existing mitigation is for BPA to operate within their short term rating and
for Avista to shed load (up to 33MW) at Waikiki or bring up Northeast CT
▪ Refer to West Plains System Reinforcement and South Spokane
Transmission Reinforcement.
o The loss of Bell 230/115 transformer #6 during summer loading may overload the
remaining Beacon 230/115 transformer (up to 119%).
▪ Existing mitigation is for BPA and Avista to shed load (up to 80MW) in the north Spokane area
▪ Refer to West Plains System Reinforcement and South Spokane
Transmission Reinforcement.
• Loss of the either Beacon – Bell 230kV line followed by:
o The loss of the remaining Beacon - Bell 230kV line during summer loading may
overload the Bell 230/115 transformer #6 (up to 118%).
▪ Existing mitigation is for BPA to operate within their short term rating.
• Loss of the Beacon – Bell 115kV line, followed by:
o The loss of Bell 230/115 transformer #6 during summer loading may overload the
Beacon – Northeast 115kV line (up to 126%) and the Bell – Northeast 115kV line
(up to 102%).
▪ Existing mitigation is to transfer Waikiki to Francis & Cedar.
▪ Refer to North Spokane System Reinforcement.
• Loss of the either Beacon – Ninth & Central 115kV line followed by:
o The loss of the remaining Ninth & Central 115kV line during summer loading may
overload the Ross Park – Third & Hatch 115kV line (up to 123%).
▪ Existing mitigation is to shed load (up to 70MW) in the South Spokane area.
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▪ Refer to West Plains System Reinforcement and South Spokane
Transmission Reinforcement.
o The loss of the Beacon – Ross Park 115kV line during summer loading may overload the remaining Beacon – Francis & Cedar 115kV line (up to 106%).
▪ Existing mitigation is to open Ninth & Central – Opportunity 115kV line at
Ninth & Central
▪ Refer to West Plains System Reinforcement and South Spokane
Transmission Reinforcement.
o The loss of the Ross Park – Third & Hatch 115kV line during summer loading
may overload the remaining Beacon – Francis & Cedar 115kV line (up to 102%).
▪ Existing mitigation is to open Ninth & Central – Opportunity 115kV line at
Ninth & Central
▪ Refer to West Plains System Reinforcement and South Spokane Transmission Reinforcement.
• Loss of the Beacon – Northeast 115kV line, followed by:
o The loss of Bell 230/115 transformer #6 during summer loading may overload the
Beacon – Bell 115kV line (up to 162%).
▪ BPA has to radialize their load at Bell pre-contingency
▪ Refer to North Spokane System Reinforcement.
• Loss of the Beacon – Ross Park 115kV line followed by:
o The loss of the either Beacon – Ninth & Central 115kV line during summer loading may overload the remaining Beacon – Ninth & Central 115kV line (up to
107%).
▪ Existing mitigation is to open Ninth & Central – Opportunity 115kV line at
Ninth & Central.
▪ Planned mitigation is to complete the Spokane Valley Transmission Reinforcement (fall of 2021).
• Loss of the Bell 230/115 transformer #6 followed by:
o The loss of the either Beacon 230/115 transformer during summer loading may
overload the remaining Beacon 230/115 transformer (up to 118%).
▪ Existing mitigation is to shed load (up to 80MW) in the north Spokane area
▪ Refer to West Plains System Reinforcement and South Spokane
Transmission Reinforcement.
o The loss of the Beacon – Northeast 115kV line during summer loading may
overload the Beacon – Bell 115kV line (up to 162%).
▪ BPA and Avista shed load (up to 80MW) in the north Spokane area.
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▪ Refer to North Spokane System Reinforcement.
o The loss of the Beacon – Bell 115kV line during summer loading may overload
the Beacon – Northeast 115kV line (up to 126%).
▪ Planning mitigation is to transfer Waikiki to Francis & Cedar.
▪ Refer to North Spokane System Reinforcement.
• Loss of the Bell – Northeast 115kV line, followed by load restoration (Waikiki will auto-
transfer to the Beacon – Francis & Cedar 115kV line), followed by:
o The loss of Bell 230/115 transformer #6 during summer loading may overload the
Beacon – Bell 115kV line (up to 105%).
▪ BPA has to radialize their load at Bell pre-contingency
▪ Refer to North Spokane System Reinforcement.
• Loss of the Bell – Westside 230kV line followed by:
o The loss of either Beacon 230/115 transformer during summer loading may
overload the Bell 230/115 transformer #6 (up to 107%) and the remaining
Beacon 230/115 transformer (up to 106%).
▪ Existing mitigation is for BPA to operate within their short term rating on Bell 230/115 transformer #6 and for Avista to shed load (up to 50MW) at
Waikiki.
▪ Refer to West Plains System Reinforcement and South Spokane
Transmission Reinforcement.
• Loss of the Benewah – Boulder 230kV line followed by:
o Loss of the Dworshak – Hatwai 500 during high east to west transfers may
overload the Benewah – Pine Creek 230kV line (up to 126%).
▪ Existing mitigation is to limit WMH to 1450MW and reduce Avista’s share
of MT-NW by 200MW per SOP 28.
• Loss of the Benewah – Pine Creek 230kV line followed by:
o Loss of the Cabinet – Rathdrum 230 line during high east to west transfers may
overload the Lancaster - Noxon 230kV line (up to 134%).
▪ Existing mitigation is to limit WMH to 1350MW and reduce Avista’s share of MT-NW by 200MW per SOP 28.
• Loss of the Benton – Othello SS 115kV line, followed by load restoration (Benton to
South Othello 115kV line section outage shows worst performance), followed by:
o The loss of the Sand Dunes – Warden 115kV line during summer loading may overload the Larson – Sand Dunes – Warden 115kV line (up to 116%).
▪ Existing mitigation is to open the Larson – Sand Dunes – Warden 115kV
line at Warden per SOP 21.
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▪ Planned mitigation is to complete the Saddle Mountain project Phase I
and II (fall of 2022).
• Loss of the Cabinet - Noxon 230kV line followed by:
o Loss of the Noxon – Pine Creek 230kV line during high WMH and east to west
transfers may overload the Lancaster - Noxon 230kV line (up to 145%).
▪ Existing mitigation is to arm RAS, limit Cabinet Gorge to 200MW, limit
WMH to 1200MW and reduce Avista’s share of MT-NW by 200MW per SOP 28.
• Loss of the College & Walnut – Westside 115kV line, followed by load restoration (Fort
Wright – Westside 115kV line section outage shows worst performance), followed by:
o The loss of the Ninth & Central – Third & Hatch 115kV line during summer loading may overload the Ross Park – Third & Hatch 115kV line (up to 105%).
▪ Existing mitigation is to shed load (up to 10MW) at Fort Wright.
▪ Refer to West Plains System Reinforcement and South Spokane
Transmission Reinforcement.
o The loss of the either Beacon – Ninth & Central 115kV line during summer loading may overload the remaining Beacon – Ninth & Central 115kV line (up to
101%).
▪ Existing mitigation is to open Ninth & Central – Opportunity 115kV line at
Ninth & Central
▪ Planned mitigation is to complete the Spokane Valley Transmission Reinforcement (fall of 2021).
• Loss of the Devils Gap - Stratford 115kV line, followed by load restoration (Stratford –
Wilson Creek 115kV line section outage shows worst performance), followed by:
o The loss of the Larson - Stratford 115kV line during summer loading may overload the Chelan - Stratford 115kV line (up to 107%).
▪ Existing mitigation is to open the Chelan - Stratford 115kV line at Stratford
per SOP 21.
• Loss of the Dry Creek – North Lewiston 230kV line followed by:
o Loss of the Hatwai - Lolo 230kV line during summer loading and high ID-NW transfers may overload the Clearwater – North Lewiston 115kV line (up to 167%),
Dry Creek – North Lewiston 115kV line (up to 121%), and North Lewiston
230/115 transformer #1 (up to 138%).
▪ Existing mitigation is to arm Lolo-Oxbow Back Trip, open Lolo – Pound Lane 115kV line at Lolo, open Lolo – Nez Perce 115kV line at Nez Perce,
Open Dry Creek – North Lewiston 115kV line at North Lewiston, and open
Dry Gulch 69 kV tie.
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▪ Refer to Lewiston/Clarkston System Reinforcement.
• Loss of the Francis & Cedar – Ross Park 115kV line, followed by load restoration (Lions & Standard – Ross Park 115kV line section outage shows worst performance), followed
by:
o The loss of the Northwest - Westside 115kV line during summer loading may
overload the Beacon – Francis & Cedar 115kV line (up to 109%).
▪ Existing mitigation is to open the Beacon – Francis & Cedar 115kV line at Francis & Cedar.
▪ Refer to North Spokane System Reinforcement.
• Loss of the Larson – Stratford 115kV line, followed by:
o The loss of the Devils Gap - Stratford 115kV line during spring and summer loading may overload the Chelan - Stratford 115kV line (up to 107%).
▪ Existing mitigation is to limit generation at Main Canal and Summer Falls
to a total of 90MW per SOP 21.
• Loss of the Larson – Sand Dunes – Warden 115kV line, followed by load restoration (Wheeler to Basset Junction 115kV line section outage shows worst performance),
followed by:
o The loss of the Sand Dunes – Warden 115kV line during spring and summer
loading will overload the Benton – Othello SS 115kV line and result in voltage
collapse in the Othello area (drops up to 168MW).
▪ Existing mitigation is to open the Benton – Othello SS 115kV line at
Othello SS per SOP 21.
▪ Planned mitigation is to complete the Saddle Mountain project Phase I
and II (fall of 2022). This still results in low voltage on GCPD’s system.
• Loss of the Hatwai – Lolo 230kV line followed by:
o Loss of the Dry Creek – Lolo 230kV line during summer loading and high ID-NW
transfers may overload the Clearwater – North Lewiston 115kV line (up to 197%)
and Dry Creek – Pound Lane 115kV line (up to 119%) or the;
o Loss of the Dry Creek – North Lewiston 230kV line during summer loading and high ID-NW transfers may overload the Clearwater – North Lewiston 115kV line (up to 167%), Dry Creek – North Lewiston 115kV line (up to 121%), and North
Lewiston 230/115 transformer #1 (up to 138%) or the;
o Loss of the North Lewiston 230/115 transformer during summer loading and high
ID-NW transfers may overload the Dry Creek – North Lewiston 230kV line (up to 116%).
▪ Arm Lolo-Oxbow Back Trip, open Lolo – Pound Lane 115kV line at Lolo,
open Lolo – Nez Perce 115kV line at Nez Perce, Open Dry Creek – North
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Lewiston 115kV line at North Lewiston, and open Dry Gulch 69 kV tie per
SOP 33.
• This leaves Clearwater – North Lewiston 115kV line in service, but
ready to trip via thermal relays for a subsequent outage.
▪ Refer to Lewiston/Clarkston System Reinforcement.
• Loss of the Moscow 230/115 transformer followed by:
o The loss of the Shawnee 230/115 transformer during any season will overload
the Moscow – Orofino 115kV line and result in voltage collapse in the
Moscow/Pullman area (drops up to 186MW).
▪ Existing mitigation is to open the Moscow – Orofino 115kV line at Moscow.
No current System Operating Procedure.
▪ Can only recover load in the Moscow area (from Orofino & North
Lewiston), which leaves up to 70MW offline until autotransformer issue is
corrected,
▪ Refer to Palouse System Reinforcement.
• Loss of the Moscow – South Pullman 115kV line, followed by load restoration (Moscow
– North Moscow 115kV line section outage shows worst performance), followed by:
o The loss of the Shawnee 230/115 transformer during summer loading may
overload the Moscow – Terre View 115kV line (up to 110%).
▪ Existing mitigation is to transfer Moscow City load to North Lewiston.
▪ Refer to Palouse System Reinforcement.
• Loss of the Moscow – Terre View 115kV line, followed by load restoration (Moscow –
North Moscow 115kV line section outage shows worst performance), followed by:
o The loss of the Shawnee 230/115 transformer during summer loading may overload the Moscow – South Pullman 115kV line (up to 107%).
▪ Existing mitigation is to transfer Moscow City load to North Lewiston.
▪ Refer to Palouse System Reinforcement.
• Loss of the North Lewiston 230/115 transformer followed by:
o Loss of the Hatwai - Lolo 230kV line during summer loading and high ID-NW
transfers may overload the Dry Creek – North Lewiston 115kV line (up to 98%),
▪ Arm Lolo-Oxbow Back Trip per SOP 33.
▪ Refer to Lewiston/Clarkston System Reinforcement.
• Loss of the Nine Mile – Westside 115kV line, followed by load restoration (Indian Trail – Westside 115kV line section outage shows worst performance), followed by:
o The loss of Airway Heights – Devils Gap 115kV line during light spring loading
may overload the Addy – Devils Gap 115kV line (up to 107%).
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▪ Existing mitigation is to limit generation at Nine Mile to 8MW per SOP 20
▪ Planned mitigation is to complete the Addy – Devils Gap 115kV line
section rebuild by correcting bottleneck at Devils Gap (spring of 2020).
• Loss of the Ninth & Central – Sunset 115kV line, followed by load restoration (Glenrose
– Ninth & Central 115kV line section outage shows worst performance), followed by:
o The loss of the Beacon – Ross Park 115kV line during summer loading may
overload the Ninth & Central – Third & Hatch 115kV line (up to 91%, 95% with W2E offline, increases to 100% after Irvin is complete).
▪ Refer to West Plains System Reinforcement and South Spokane
Transmission Reinforcement.
o The loss of the Metro – Post Street 115kV line during summer loading may
overload the Sunset – Westside 115kV line (up to 106%, 105% with W2E offline, increases to 109% after Irvin is complete).
▪ Planned mitigation is to complete the Metro Substation rebuild and
associated projects (spring of 2024).
o The loss of the Metro – Sunset 115kV line during summer loading may overload
the Sunset - Westside 115kV line (up to 96%, 96% with W2E offline, increases to 99% after Irvin is complete).
▪ Refer to West Plains System Reinforcement.
o The loss of the Ninth & Central – Third & Hatch 115kV line during summer
loading may overload the Ross Park – Third & Hatch 115kV line (up to 98%,
103% with W2E offline, increases to 108% after Irvin is complete).
▪ Refer to West Plains System Reinforcement.
• Loss of the Noxon – Pine Creek 230kV line followed by:
o Loss of the Cabinet - Rathdrum 230kV line during high WMH and east to west
transfers may overload the Lancaster - Noxon 230kV line (up to 121%).
▪ Existing mitigation is to arm RAS, limit WMH to 1350MW and reduce
Avista’s share of MT-NW by 200MW per SOP 28.
• Loss of the Opportunity – Otis Orchards 115kV line, followed by load restoration (Liberty
Lake – Otis Orchards line section outage shows worst performance), followed by:
o The loss of the either Beacon 230/115 transformer during summer loading may
overload the remaining Beacon 230/115 transformer (up to 98%).
▪ Refer to West Plains System Reinforcement and South Spokane
Transmission Reinforcement.
o The loss of the either Ninth & Central 115kV line during summer loading may overload the remaining Ninth & Central 115kV line (up to 108%).
▪ Existing mitigation is to shed load (up to 20MW) in the South Spokane
area.
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▪ Planned mitigation is to complete the Spokane Valley Transmission
Reinforcement (fall of 2021).
• Loss of the Othello SS – Warden #2 115kV line, followed by load restoration (Lee &
Reynolds - Warden 115kV line section outage shows worst performance), followed by:
o The loss of the Othello SS – Warden #1 115kV line during spring and summer
loading may overload the Benton – Othello SS 115kV line (up to 125%).
▪ Existing mitigation is to open the Benton – Othello SS 115kV line at Othello SS per SOP 21.
▪ Planned mitigation is to complete the Benton – Othello SS project (spring
of 2020).
• Loss of the Pine Street – Rathdrum 115kV line, followed by load restoration (Old Town
– Pine Street 115kV line section outage shows worst performance), followed by:
o The loss of the Rathdrum 230/115 transformer #2 during summer loading may
overload the remaining Rathdrum 230/115 transformer #1 (up to 117%, 96% with
CDA-PIN 115 closed).
▪ Existing mitigation is to operate Coeur d’Alene – Pine Creek 115kV closed through per SOP 36.
▪ Refer to Coeur d'Alene System Reinforcement.
• Loss of either Rathdrum 230/115 transformer followed by:
o The loss of the remaining Rathdrum 230/115 transformer during any season will overload the Pine Street – Rathdrum 115kV line and result in voltage collapse in
the Coeur d’Alene area (drops up to 275MW).
▪ Existing mitigation is to open the Pine Street – Rathdrum 115kV line at
Rathdrum per SOP 36. Note that closing though on the Coeur d’Alene –
Pine Creek 115kV does not mitigate for the loss of both Rathdrum 230/115 transformers, due to Pine Street – Rathdrum 115kV line overload
(up to 127%).
▪ Refer to Coeur d'Alene System Reinforcement.
• Loss of the Sand Dunes – Warden 115kV line, followed by:
o The loss of the Larson – Sand Dunes – Warden 115kV line 115kV line during summer loading may overload the Benton – Othello SS 115kV line (up to 212%).
▪ Existing mitigation is to open the Larson – Sand Dunes – Warden 115kV
line at Warden per SOP 21.
▪ Planned mitigation is to complete the Benton – Othello SS project (spring of 2020).
• Loss of the Sunset – Westside 115kV line, followed by load restoration (Garden Springs
– Waste to Energy 115kV line section outage shows worst performance), followed by:
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o The loss of the Airway Heights – Devils Gap 115kV line during summer loading
may overload the College & Walnut – Westside 115kV line (up to 102%).
▪ Existing mitigation is to shed load (up to 10MW) at Fort Wright.
▪ Refer to West Plains System Reinforcement.
o The loss of the College & Walnut – Westside 115kV line during summer loading
may overload the Francis & Cedar – Northwest 115kV line (up to 102%), the Post
Street – Third & Hatch 115kV line (up to 103%), and the Ross Park – Third &
Hatch 115kV line (up to 110%).
▪ Existing mitigation is to shed load (up to 50MW) in the South Spokane
area.
▪ Refer to West Plains System Reinforcement and South Spokane
Transmission Reinforcement.
o The loss of the Francis & Cedar – Northwest 115kV line during summer loading may overload the College & Walnut – Westside 115kV line (up to 111%).
▪ Existing mitigation is to shed load (up to 40MW) in the South Spokane
area.
▪ Refer to West Plains System Reinforcement and South Spokane
Transmission Reinforcement.
o The loss of the Metro – Post Street 115kV line during summer loading may
overload the Ninth & Central – Sunset 115kV line (up to 114%).
▪ Existing mitigation is to shed load (up to 20MW) in the South Spokane
area.
▪ Planned mitigation is to complete the Metro Substation rebuild and associated projects (spring of 2024).
o The loss of the Metro – Sunset 115kV line during summer loading may overload
the Ninth & Central – Sunset 115kV line (up to 102%).
▪ Existing mitigation is to shed load (up to 10MW) in the South Spokane
area.
▪ Planned mitigation is to complete the Ninth & Central – Sunset 115kV line
rebuild (Southeast Substation bottleneck) (spring of 2020).
o The loss of the Northwest – Westside 115kV line during summer loading may
overload the College & Walnut – Westside 115kV line (up to 119%).
▪ Existing mitigation is to shed load (up to 80MW) in the South Spokane area.
▪ Refer to West Plains System Reinforcement and South Spokane
Transmission Reinforcement.
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o The loss of the Post Street – Third & Hatch 115kV line during summer loading
may overload the College & Walnut – Westside 115kV line (up to 109%).
▪ Existing mitigation is to shed load (up to 30MW) in the South Spokane area.
▪ Refer to West Plains System Reinforcement.
o The loss of the Ross Park – Third & Hatch 115kV line during summer loading
may overload the College & Walnut – Westside 115kV line (up to 103%).
▪ Existing mitigation is to shed load (up to 10MW) at Fort Wright.
▪ Refer to West Plains System Reinforcement and South Spokane
Transmission Reinforcement.
• Loss of the Sunset – Westside 115kV line, followed by gen/load restoration (Waste to
Energy – Westside 115kV line section outage shows worst performance), followed by:
o The loss of the College & Walnut – Westside 115kV line during summer loading
may overload the Ross Park – Third & Hatch 115kV line (up to 104%).
▪ Existing mitigation is to shed load (up to 20MW) in the South Spokane
area.
▪ Refer to West Plains System Reinforcement and South Spokane Transmission Reinforcement.
o The loss of the Francis & Cedar – Northwest 115kV line during summer loading
may overload the College & Walnut – Westside 115kV line (up to 104%).
▪ Existing mitigation is to shed load (up to 20MW) in the South Spokane
area.
▪ Refer to West Plains System Reinforcement and South Spokane
Transmission Reinforcement.
o The loss of the Metro – Post Street 115kV line during summer loading may
overload the Ninth & Central – Sunset 115kV line (up to 102%).
▪ Existing mitigation is to shed load (up to 10MW) in the South Spokane area.
▪ Planned mitigation is to complete the Ninth & Central – Sunset 115kV line
rebuild (Southeast Substation bottleneck) (spring of 2020).
o The loss of the Northwest – Westside 115kV line during summer loading may
overload the College & Walnut – Westside 115kV line (up to 112%).
▪ Existing mitigation is to shed load (up to 50MW) in the South Spokane
area.
▪ Refer to West Plains System Reinforcement and South Spokane
Transmission Reinforcement.
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P a g e | 46
o The loss of the Post Street – Third & Hatch 115kV line during summer loading
may overload the College & Walnut – Westside 115kV line (up to 102%).
▪ Existing mitigation is to shed load (up to 10MW) in the South Spokane area.
▪ Refer to West Plains System Reinforcement.
o The loss of the Ross Park – Third & Hatch 115kV line during summer loading
may overload the College & Walnut – Westside 115kV line (up to 97%).
P7 – No system elements show thermal overload resulting from an N-2 contingency event. This is described as the loss of any two adjacent circuits on common structure (vertical or
horizontal) and excludes circuits of (1) mile.
1.2 Voltage Issues
P0 – No voltage issues were identified under system normal conditions.
• Minor high voltage is observed under system normal and off-peak loading conditions in
the Big Bend area.
o Issue remains under observation.
• Minor low voltage has been observed under system normal conditions in PacifiCorp’s 69 kV system.
o PacifiCorp planned mitigation is to upgrade the Dry Gulch 115/69 kV transformer
from 20 MVA to a 50 MVA transformer with voltage regulation (LTC).
P1.1-P1.4 – No voltage issues were identified under N-1 conditions, such as the loss of a generator, transmission circuit, transformer or shunt device.
P2.1 – Several voltage issues were identified with the opening of a line section w/o a fault
during peak loading:
• Loss of the Roxboro – Warden 115kV line section requires transferring area load to
Devils Gap and/or Shawnee, may result in low voltage at Roxboro (0.93pu).
o Existing mitigation is to shed load at Roxboro (up to 20MW) per SOP 21.
• Loss of the Stratford – Wilson Creek 115kV line section requires transferring area load
to Devils Gap, which may result in a high voltage step change (0.06pu) when inserting each 13.4 MVAr step at Othello.
o Step change in voltage results in up to 40MW of irrigation load loss.
o Planned mitigation is to investigate reducing cap bank step size.
• Loss of the Garden Springs – Hayford 115kV line section requires transferring area load
to Airway Heights, which may result in low voltage at Cheney (0.95pu).
o Existing mitigation is to transfer Cheney and Four Lakes to the Sunset –
Shawnee 115kV line per SOP 12.
Avista Corp.2021 Electric IRP Appendices 1051
Planning Assessment 2019-2020

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P2.2 – Several voltage issues were identified resulting from a bus section fault during peak
loading:
• Loss of the Sand Dunes 115kV bus during summer loading may result in low voltage at
Ritzville (0.95pu) and Othello City (0.95pu).
o Existing mitigation is to transfer load at Ritzville to Devils Gap
P2.4 – Several voltage issues were identified resulting from an internal breaker fault on a bus
tie breaker during peak loading:
• A Boulder 115kV bus tie breaker failure during summer loading may result in voltage
collapse in the Spokane Valley.
o Shed load east of Otis Orchards
P3 – No further results beyond those identified in P1 and P2.1
P4 & P5 – No further results beyond those identified in P2.2 thru P2.4
P6 – No voltage issues were identified resulting from an N-1-1 contingency event that were not
captured in the previous thermal results section. This is described as the loss of a transmission
circuit, transformer or shunt device; followed by system adjustments; followed by a subsequent
loss of an additional transmission circuit, transformer or shunt device.
P7 – No voltage issues were identified resulting from an N-2 contingency event. This is
described as the loss of any two adjacent circuits on common structure (vertical or horizontal)
and excludes circuits of (1) mile.
1.3 Radial and Consequential Load Loss Issues
The present steady state contingency analysis methods allows for observation of consequential load loss for each studied contingency. Improved study methods are desired to
capture both the amount of consequential load loss and the inability to restore service to
customers. The following list identifies transmission system contingencies resulting in
undesired consequential load loss. The list is not comprehensive of all radial transmission system elements and will be improved in subsequent studies.
• P1.1 – Loss of the Addy - Gifford 115kV line during any season results in an outage to
Gifford (9MW)
o Addy has a main/aux bus arrangement for substation related outages at Addy
• P1.1 – Loss of the Lind – Washtucna 115kV line during any season results in an outage
to Delight and Washtucna (total of 3MW)
o The Lind bypass switch provides service for substation related outages at Lind
• P1.1 – Loss of the Orofino – Weippe 115kV line during any season results in an outage to Weippe (4MW)
o The Orofino bypass switch A196 provides service for substation related outages
at Orofino
Avista Corp.2021 Electric IRP Appendices 1052
Planning Assessment 2019-2020

P a g e | 48
• P1.3 – Loss of the Benewah 230/115 transformer #1 (drops 20MW load), followed by
load restoration (transfer Setters load to Ninth & Central and close the Benewah – Pine Creek 115kV line) did not result in load loss after load was restored from alternate
sources.
• P1.3 – A trip of either Cabinet Gorge GSU A or B (P1.3) during any season will drop all
units at Cabinet Gorge (up to 260MW) and clears the Cabinet 230kV bus due to the lack of a high side GSU breaker. This outage severs the (2) primary station service feeds at
Cabinet Gorge Hydro, it open ends the Cabinet – Noxon 230kV line, the Cabinet –
Rathdrum 230kV line and the Cabinet 230/115kV autotransformer, it results in a
reduction in WMH to 1100MW and cuts MT-NW by 200MW.
o Refer to Cabinet Gorge GSU Isolation.
• P2.4 – A Rathdrum 115kV bus tie breaker failure during any season drops load in the
Coeur d’Alene area (drops up to 275MW).
• P7 / P6 – A forced outage of Beacon – Rathdrum 230kV line and Lancaster – Rathdrum 230kV line (common structure), followed by:
o The loss of the Cabinet – Rathdrum 230kV line during any season will overload
the Pine Street – Rathdrum 115kV line and result in voltage collapse in the Coeur
d’Alene area (drops up to 275MW).
▪ Open the Pine Street – Rathdrum 115kV line at Rathdrum per SOP 36
▪ Refer to Coeur d'Alene System Reinforcement.
2 VOLTAGE STABILITY ANALYSIS
No QV or PV issues were identified during this assessment.

Avista Corp.2021 Electric IRP Appendices 1053
Planning Assessment 2019-2020

P a g e | 49
3 STABILITY CONTINGENCY ANALYSIS
The following transient stability issues were identified during this assessment.
3.1 Kettle Falls Generator Out of Step
The Kettle Falls generator can become unstable if a time delayed three phase fault occurs on the Addy – Kettle Falls 115kV Transmission Line near Addy. Studies indicate that speeding up the Zone 2 clearing (time delay of 9 cycles, 13 cycles total clearing) is not sufficient to correct
this out of step issue.
The stability issue was addressed with the installation of an out of step relay (78) at Kettle
Falls. The transient stability results are shown below and indicate that the local system returns to a stable state once the generators are tripped offline.

FIGURE 3: KETTLE FALLS GENERATION OOS.
Implementing a high speed communication aided tripping scheme on the Addy – Kettle Falls
115kV Transmission Line to improve stability performance of the Kettle Falls generation is
necessary.

Avista Corp.2021 Electric IRP Appendices 1054
Planning Assessment 2019-2020

P a g e | 50
3.2 Nine Mile Generators Out of Step
All Nine Mile Hydro generators can become unstable if a time delayed three phase fault occurs on the Nine Mile – Westside 115kV Transmission Line near Westside. Studies indicate that
speeding up the Zone 2 clearing (time delay of 9 cycles, 13 cycles total clearing) is not
sufficient to correct this out of step issue.
Units #3 and #4 at Nine Mile Hydro have recently been rebuilt, resulting in up to 28MW of total
facility generation. These units were commissioned with an out of step relay (78), but units #1 and #2 do not have this protection. The transient stability results are shown below and indicate
that the local system returns to a stable state once units #1 and #2 are tripped offline.

FIGURE 4: NINE MILE GENERATION OOS.
This issue is corrected after the Nine Mile - Westside 115kV Transmission Line is moved to the
new Westside Southeast 115kV bus and the planned communication aided tripping is
integrated.

Avista Corp.2021 Electric IRP Appendices 1055
Planning Assessment 2019-2020

P a g e | 51
3.3 Coeur d’Alene Area Voltage Recovery
During moderate to heavy loading, the Coeur d’Alene area has slow voltage recovery for a fault on the double circuit Boulder – Rathdrum and Lancaster – Rathdrum 230kV transmission
lines (P7 contingency). The slow voltage recovery does not meet the WR1.1.4 Part 2
performance criteria as shown in Figure 5. Previous technical studies did not demonstrate the
same performance. The implementation of stalled motor modeling in the composite load model
contributes to the slow voltage recovery. Further detailed analysis is necessary to determine the accuracy of the simulation and potential modeling improvements. The implementation of
the Coeur d’Alene System Reinforcement Project will address the voltage dip performance by
improving the strength of the local transmission system.

FIGURE 5: P7 CONTINGENCY VOLTAGE RECOVERY IN COEUR D'ALENE AREA.

Avista Corp.2021 Electric IRP Appendices 1056
Planning Assessment 2019-2020

P a g e | 52
5 SPARE EQUIPMENT ANALYSIS
Avista’s 230/115kV transformer spare equipment strategy could result in the unavailability of
these units for one year or more due to replacement lead time. The impact of a single
transformer out of service and subsequent P0, P1 and P2 contingencies was studied by area.
5.1 Big Bend Area
Avista does not currently have any 230/115kV autotransformers, in service, in the Big Bend
area.
5.2 Coeur d’Alene Area Transformers
Outage of either Rathdrum 230/115kV transformer may result in area overloads and low
voltage problems for Rathdrum 115kV bus outages or the other Rathdrum transformer outage.
The Coeur d’Alene System Reinforcement Project has been identified for this purpose and will
mitigate the bus issues.
Upgrading the existing #1 transformer, previously identified by Asset Management, will provide
overload mitigation for some contingencies.
Additional analysis is required for mitigation of the double transformer outage.
5.3 Lewiston/Clarkston Area Transformers
Area transformer outages may result in overloads on the Lolo 230/115kV transformers. Area
115kV bus outages may result in area low voltage.
The Lolo Transformer Replacement Project Committed and Planned for completion by 2023 will mitigate the transformer overload problem.
Area low voltage mitigation will require further study.
5.4 Palouse Area Transformers
Outage of either the Moscow or Shawnee 230/115kV transformer may result in area low voltage and 115kV line overloads; outage of both transformers increases the severity.
The Palouse Area Reinforcement Project has been identified for this purpose.
5.5 Spokane Area Transformers
Outage of either Beacon 230/115kV transformer combined with an outage of either of the
Boulder or Westside 230/115kV transformers may result in overload the Bell#6 230/115kV transformer. Additional instances of the Bell#6 transformer overloading as well area
transformer overloading may occur for Beacon 230 and 115kV bus outages.
Upgrading of the BPA Bell#6 230/115kV transformer will mitigate the overload issues.
Avista Corp.2021 Electric IRP Appendices 1057
Planning Assessment 2019-2020

P a g e | 53
The South Spokane System Reinforcement Project has been identified for this purpose.
Additional analysis for an area solution is still required.
Detail results are presented in Appendix D.

Avista Corp.2021 Electric IRP Appendices 1058
Planning Assessment 2019-2020

P a g e | 54
6 SHORT CIRCUIT ANALYSIS
Sunset Substation was previously identified as having available short circuit current above the
interrupting capability of at least one of the circuit breakers. No additional violations were
identified in this year’s assessment.
The Sunset Substation Rebuild Project is Committed and Planned for completion by 2023 which will mitigate this problem.
Detailed results are presented in Appendix E.

Avista Corp.2021 Electric IRP Appendices 1059
Planning Assessment 2019-2020

P a g e | 55
8 FEEDER CAPACITY ANALYSIS
Feeder Capacity analysis was done for feeders that have SCADA data available. Table 3 is a
list of the 20 heaviest loaded feeders from the three year period 2016-2018. The peak
represents the highest five minute average for the season- summer or winter. Seasonal
Capacity is the SCADA Variable Limit for 0°C and 40°C ambient temperatures. Project planned indicates whether a project has been considered, planned, or under construction. It should be noted that peak values are taken without regard to system status.
Detailed results are presented in Appendix H.
Peak Feeder Loading (2016-2018)
Feeder
Name
Summer Peak
Load (Amps)
Winter Peak
Load (Amps)
Summer
Capacity Limit
(Amps)
Winter Capacity
Limit (Amps)
Max
Usage
Project
Planned
WAK12F4 504 316 512 668 99% Yes
ROS12F1 481 521 499 571 96%
HUE142 493 325 512 613 96% Yes
F&C12F2 468 318 512 668 91%
NRC352 84 103 113 113 91%
ODN731 284 297 312 456 91%
COB12F1 463 343 512 668 90% Yes
DAL132 462 262 512 668 90% Yes
SE12F3 368 596 512 668 89% Yes
ORI12F3 111 266 208 302 88%
KET12F2 258 264 293 430 88%
AIR12F2 427 435 485 668 88% Yes
C&W12F6 446 355 512 608 87%
DAL131 522 402 601 668 87% Yes
LOL1359 356 258 413 635 86%
SE12F2 516 502 601 668 86% Yes
MEA12F1 440 284 512 668 86% Yes
GLN12F2 440 398 512 668 86%
APW112 477 436 557 618 86%
F&C12F4 438 321 512 668 86%
TABLE 3 PEAK FEEDER LOADING (2016-2018)

Avista Corp.2021 Electric IRP Appendices 1060
Planning Assessment 2019-2020

P a g e | 56
AVISTA GENERAL
INFORMATION
A.1 GENERATION RESOURCES
Avista has a diverse mix of generation with a majority of its generation being hydro power
based on various projects located on the Spokane River and Clark Fork River. 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. Table 4 through
Table 6 summarize the operational capacities of Avista generating projects.
TABLE 4: AVISTA HYDROELECTRIC GENERATION RESOURCES.
Project Name Fuel Location Area Project Start Date
Maximum Capability (MW)F
Monroe Street Spokane River Spokane, WA Spokane 1890 15.0 Post Falls Spokane River Post Falls, ID CdA 1906 18.0
Nine Mile Spokane River Nine Mile Falls, WA Spokane 1925 32.0
Little Falls Spokane River Ford, WA Big Bend 1910 35.2
Long Lake Spokane River Ford, WA Big Bend 1915 89.0
Upper Falls Spokane River Spokane, WA Spokane 1922 10.2
Cabinet Gorge Clark Fork River Clark Fork, ID CdA 1952 270.5
Noxon Rapids Clark Fork River Noxon, MT CdA 1959 610.0 Total 1079.9

TABLE 5: AVISTA RENEWABLE GENERATION RESOURCES.
Project Name Fuel Location Area
Project
Start Date
Maximum Capability
(MW)F
Palouse Wind Thornton, WA Palouse 2012 104.0
Adams Neilson Solar Lind, WA Big Bend 2018 19.2
Total 123.2

TABLE 6: AVISTA THERMAL GENERATION RESOURCES.
Project Name Fuel Location Area Project
Start Date
Maximum
Capability (MW)F
Colstrip 3&4 (15%) Coal Colstrip, MT N/A 1984 247.0
Rathdrum (CT) Gas Rathdrum, ID CdA 1995 176.0
Northeast (CT) Gas Spokane, WA Spokane 1978 66.0
Boulder Park (IC) Gas Spokane, WA Spokane 2002 24.6
Coyote Springs 2 (CC) Gas Boardman, OR N/A 2003 317.5 Kettle Falls Wood Kettle Falls, WA Big Bend 1983 50.7 Kettle Falls (CT) Gas Kettle Falls, WA Big Bend 2002 11.0
Total 892.8
Avista Corp.2021 Electric IRP Appendices 1061
Planning Assessment 2019-2020

P a g e | 57
For more information on Avista’s generation, please refer to the 2017 Integrated Resource
Plan.
A.2 TRANSMISSION SYSTEM
Avista owns and operates a system of over 2,200 miles of electric transmission facilities which
include approximately 685 miles of 230kV transmission lines and 1,527 miles of 115kV transmission lines. Figure 6 illustrates Avista’s Transmission System within the region.

FIGURE 6 AVISTA TRANSMISSION LINE MAP
The Avista 230kV transmission lines are the backbone of Avista’s Transmission System and
consist of two networked systems centered near the Spokane/Coeur d’Alene area and the
Lewiston/Clarkston area.

Avista Corp.2021 Electric IRP Appendices 1062
Planning Assessment 2019-2020

P a g e | 58
TRANSMISSION MODELS
B.1 PLANNING CASE DESCRIPTION
Avista’s System Planning Group develops a set of base cases (Planning Cases) biannually to
model its 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 for Power System Modeling and Analysis is used which includes using WECC approved base cases and applying steady state and dynamic data
modifications as required to represent desired scenarios. The resulting Planning Cases
represent a normal System condition (N-0). Planning Cases include the following:
• Existing facilities, new planned facilities and changes to existing facilities.
• Known outages of generation or transmission facilities with a duration of at greater than
six months are represented. Presently, Avista does not have long duration planned
outages.
• Forecasted real and reactive loads along with generation resources (supply or demand
side) are modeled as described in TP-SPP-07 – Loads and Resources Data for
Steady State and Dynamic Studies.
• Known commitments for Firm Transmission Service and Interchange are incorporated. WECC Rated Paths are modeled with their published limits. Future commitments
exceeding the limits of WECC Rated Paths are not presently studied.
The following scenarios were developed to represent various seasonal conditions:
• Heavy Summer – this is a typical summer peak scenario where the Avista Balancing Authority Area load is at peak. The local hydro generation is at mid-summer output levels, most thermal generation is on line, and moderate transfers are flowing into
Avista’s Balancing Authority Area. This scenario is limited by the summer thermal limits
on various elements of the transmission system, which helps to identify where the
system is near capacity.
• Light Summer – this is a typical summer night time scenario where the Avista Balancing
Authority Area load is at a minimum.
• Heavy Winter – this is a typical winter peak scenario where the Avista Balancing Authority Area load is at peak. The local hydro generation is at late-winter output levels,
most thermal generation is on line, and moderate transfers are flowing into Avista’s
Balancing Authority Area. This scenario represents Avista heaviest load conditions, but
benefits from lower ambient temperature which increases the operating limits of the
various elements of the Transmission System and power factors near unity.
• Light Winter – this is a typical winter night time scenario where the Avista Balancing
Authority Area load is at a minimum.
Avista Corp.2021 Electric IRP Appendices 1063
Planning Assessment 2019-2020

P a g e | 59
• Light Spring – this is a typical late spring case that captures light loading conditions with
high levels of generation. The local hydro generation is near full capacity due to spring runoff, local wind and solar generation is near full capacity, select thermal generation is
off line for maintenance, and moderate transfers are flowing out of Avista’s Balancing
Authority Area. This scenario is also limited by the summer thermal limits on various
elements of the transmission system, which helps to identify where the system is near
capacity, due to power transfer.
• High East to West Transfer – this is a typical late spring case that captures light loading
conditions with high levels of generation east of Avista’s Balancing Authority Area. This
scenario brings both West of Hatwai (Path 6) and Montana to Northwest (Path 8) up to
their rated path limits. This scenario is also limited by the summer thermal limits on various elements of the transmission system, which helps to identify where the system
is near capacity, due to power transfer.
• High West to East Transfer – this is a typical summer peak scenario where the Avista,
Idaho Power and Northwestern Energy Balancing Authority Area load is near peak. The local hydro generation is at early-summer output levels, most thermal generation is off
line, and moderate transfers are flowing across Avista’s Balancing Authority Area to the
west. This scenario is limited by the summer thermal limits on various elements of the
transmission system, which helps to identify where the system is near capacity.

Avista Corp.2021 Electric IRP Appendices 1064

2021 Electric Integrated
Resource Plan

Appendix H – New Resource
Table for Transmission

Avista Corp.2021 Electric IRP Appendices 1065
Resource Capacity YearResourceNoteLocationPORPODStartStopMWTotal
Wind Montana Colstrip/BPA or AVAT.NWMT AVA.SYS 1/1/2023 Indefinite 100.0 100.0
Wind Montana Colstrip/BPA or AVAT.NWMT AVA.SYS 1/1/2024 Indefinite 100.0 100.0
Kettle Falls Kettle Falls, WA AVA.SYS AVA.SYS 1/1/2026 Indefinite 12.0
Post Falls Post Falls AVA.SYS AVA.SYS 1/1/2026 Indefinite 8.0
Natural Gas Peaker Rathdrum, WA AVA.SYS AVA.SYS 11/1/2026 Indefinite 211.0 231.0
Wind Off-System Colstrip/BPA or AVAT.NWMT AVA.SYS 1/1/2028 Indefinite 100.0 100.0
Hydro Mid-C MIDC AVA.SYS 1/1/2031 Indefinite 75.0 75.0
Rathdrum Rathdrum, WA AVA.SYS AVA.SYS 1/1/2035 Indefinite 5.0 5.0
Natural Gas Peaker TBD AVA.SYS AVA.SYS 1/1/2036 Indefinite 87.0 87.0
Solar & Storage 100 MW Solar w/ 50 MW Storage TBD AVA.SYS AVA.SYS 1/1/2038 Indefinite 100.0 100.0
Wind TBD Colstrip/BPA or AVAT.NWMT AVA.SYS 1/1/2041 Indefinite 100.0
Natural Gas Peaker TBD AVA.SYS AVA.SYS 1/1/2041 Indefinite 36.0 136.0
Solar & Storage 117 MW Solar w/ 58 MW Storage TBD AVA.SYS AVA.SYS 1/1/2042 Indefinite 117.0 117.0
Solar & Storage 122 MW Solar w/ 61 MW Storage TBD AVA.SYS AVA.SYS 1/1/2043 Indefinite 122.0 122.0
Storage Liquid Air TBD AVA.SYS AVA.SYS 1/1/2044 Indefinite 12.0 12.0
Solar & Storage 149 MW Solar w/ 75 MW Storage TBD AVA.SYS AVA.SYS 1/1/2045 Indefinite 149.0
Storage Liquid Air TBD AVA.SYS AVA.SYS 1/1/2045 Indefinite 10.0 159.0
Total 1344.0 1344.0
Appendix H
New Resource Table For Transmission
Avista Corp.2021 Electric IRP Appendices 1066

2021 Electric Integrated
Resource Plan

Appendix I – Publicly Available
Inputs and Models

Avista Corp.2021 Electric IRP Appendices 1067
Appendix I
Avista Corp 2021 Electric IRP 1
Appendix I 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 I.

File Name Folder File Type Description of Content
DR Model Avista Integrated Opt-Demand Excel Final AEG model for opt-in demand response
DR Model Avista Integrated Opt-
Out 3_1_21
Demand
Response
Excel Final AEG model for opt-out demand response
programs.
DR Model Avista Stand Alone Demand Excel Final AEG model for stand-alone demand response
Avista 2020 CPA – Electric EE
Measure List
Energy Efficiency Excel List of residential, commercial and industrial energy
efficiency measures along with an introduction
Avista 2020 Electric CPA –
Summary and IRP
Energy Efficiency Excel Achievable technical potential energy savings, winter
peak savings, summary peak savings inputs used in
Home Electrification Conversion Load Forecast Excel

Regression, assumptions and summary of home
conversions if electrification were to occur and
Load Forecast Load Forecast Excel Energy forecast, peak forecast, retail sales, load split
Climate Shift Scenario Inputs Market Modeling
Inputs and Results
Excel 80-year regional hydro record from NPCC, NPCC
2024 economy load forecast with changing
CO2 Emissions by Market Modeling Excel Regional CO2 emission by year for the expected
CO2 Emissions by Year_SCC Market Modeling Excel Regional CO2 emission by year for the social cost of
Avista Corp.2021 Electric IRP Appendices 1068
Appendix I
Avista Corp 2021 Electric IRP 2
High & Low Natural Gas Prices Market Modeling Excel High (95th percentile) and low (25th percentile)
Market Modeling Results Market Modeling
Inputs and Results
Excel Market modeling results to include stochastic off-
peak/on-peak/flat Mid-C prices, stochastic
greenhouse gas, hourly Mid-C prices, stochastic
historical regional resource dispatch, deterministic
hourly Mid-C prices, deterministic monthly Mid-C
prices scenarios, deterministic annual greenhouse
gas emissions and deterministic regional resource
Natural Gas Prices Market Modeling
Inputs and Results
Excel Monthly natural gas price forecast used for the IRP,
both stochastic and deterministic, as well as basin
Regional Generation
Analysis_ClimateShift_2021_IR
Market Modeling
Inputs and Results
Excel Regional generation analysis by fuel type by state.
Regional Generation
Analysis_Expected-
Market Modeling
Inputs and Results
Excel Regional deterministic generation analysis by fuel
type by state.
Regional Generation
Analysis_Expected-
Market Modeling
Inputs and Results
Excel Regional stochastic generation analysis by fuel type
by state.
Regional Generation
Analysis_HighPrice_2021_IRP
Market Modeling
Inputs and Results
Excel Regional generation analysis by fuel type by state
using the high price scenario.
Regional Generation Market Modeling Excel Regional generation analysis by fuel type by state
Regional Generation
Analysis_SCC-Case_2021_IRP
Excel Regional generation analysis by fuel type by state
using the SCC scenario.
Social Cost of Carbon Market Modeling Excel Social cost of carbon in 2007 and 2019 dollars,
Emissions_Summary_073020 Other Files Excel Avista owned resource emissions summary for
Avista Corp.2021 Electric IRP Appendices 1069
Appendix I
Avista Corp 2021 Electric IRP 3
Named Populations Other Files Excel State FIPS codes, county codes, socioeconomic and
sensitive population ratings (1-10 with 10 being the
Upstream Emission Calculation Other Files Excel Upstream emission calculation for gas and power
1_PRiSM_7.0_GUROBI_12072
0_IRP_PRS_DRAFT_Determini
stic
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
Least reasonable cost, PRS, deterministic scenario.
Includes a summary of resource selected, financial
summary, clean goal progress, loads & resources,
demand response, resource data, energy efficiency
selected, Aurora resource results, transmission
annual revenue requirement from amortization
model, annual cost of resource options, resources
(MWh), hydro & contracts market value, stochastic
variable cost of risk, general assumptions, regional
emissions, conservation load value ($/MW) and new
1_PRiSM_7.0_GUROBI_12072
0_IRP_PRS_DRAFT_HighNGPr
ice
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
Least reasonable cost, PRS, high natural gas price
scenario. Includes a summary of resource selected,
financial summary, clean goal progress, loads &
resources, demand response, resource data, energy
efficiency selected, Aurora resource results,
transmission annual revenue requirement from
amortization model, annual cost of resource options,
resources (MWh), hydro & contracts market value,
stochastic variable cost of risk, general assumptions,
regional emissions, conservation load value ($/MW)
1_PRiSM_7.0_GUROBI_12072
0_IRP_PRS_DRAFT_LowNGPri
ce
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
Least reasonable cost, PRS, low natural gas price
scenario. Includes a summary of resource selected,
Avista Corp.2021 Electric IRP Appendices 1070
Appendix I
Avista Corp 2021 Electric IRP 4
resources, demand response, resource data, energy
efficiency selected, Aurora resource results,
transmission annual revenue requirement from
amortization model, annual cost of resource options,
resources (MWh), hydro & contracts market value,
stochastic variable cost of risk, general assumptions,
regional emissions, conservation load value ($/MW)
1_PRiSM_7.0_GUROBI_12072
0_IRP_PRS_DRAFT_SCC
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
Least reasonable cost, PRS, social cost of carbon
scenario. Includes a summary of resource selected,
financial summary, clean goal progress, loads &
resources, demand response, resource data, energy
efficiency selected, Aurora resource results,
transmission annual revenue requirement from
amortization model, annual cost of resource options,
resources (MWh), hydro & contracts market value,
stochastic variable cost of risk, general assumptions,
regional emissions, conservation load value ($/MW)
1a_PRiSM_7.0_GUROBI_1207
20_IRP_PRS_DRAFT_ClimateS
hift
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
Climate shift scenario, deterministic study, re-
optimized. Includes a summary of resource selected,
financial summary, clean goal progress, loads &
resources, demand response, resource data, energy
efficiency selected, Aurora resource results,
transmission annual revenue requirement from
amortization model, annual cost of resource options,
resources (MWh), hydro & contracts market value,
stochastic variable cost of risk, general assumptions,
regional emissions, conservation load value ($/MW)
Avista Corp.2021 Electric IRP Appendices 1071
Appendix I
Avista Corp 2021 Electric IRP 5
1b_PRiSM_7.0_GUROBI_1207
20_IRP_PRS_DRAFT_SCC
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
Least reasonable cost, PRS, social cost of carbon
scenario, re-optimized for SCC. Includes a summary
of resource selected, financial summary, clean goal
progress, loads & resources, demand response,
resource data, energy efficiency selected, Aurora
resource results, transmission annual revenue
requirement from amortization model, annual cost of
resource options, resources (MWh), hydro &
contracts market value, stochastic variable cost of
risk, general assumptions, regional emissions,
3_PRiSM_7.0_GUROBI_12072
0_IRP_PRS_DRAFT_Determini
stic
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
Baseline 2 portfolio, deterministic. Includes a
summary of resource selected, financial summary,
clean goal progress, loads & resources, demand
response, resource data, energy efficiency selected,
Aurora resource results, transmission annual
revenue requirement from amortization model,
annual cost of resource options, resources (MWh),
hydro & contracts market value, stochastic variable
cost of risk, general assumptions, regional
emissions, conservation load value ($/MW) and new
3_PRiSM_7.0_GUROBI_12072
0_IRP_PRS_DRAFT_HighNGPr
ice
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
Baseline 2 portfolio, high gas price scenario.
Includes a summary of resource selected, financial
summary, clean goal progress, loads & resources,
demand response, resource data, energy efficiency
selected, Aurora resource results, transmission
annual revenue requirement from amortization
model, annual cost of resource options, resources
Avista Corp.2021 Electric IRP Appendices 1072
Appendix I
Avista Corp 2021 Electric IRP 6
variable cost of risk, general assumptions, regional
emissions, conservation load value ($/MW) and new
3_PRiSM_7.0_GUROBI_12072
0_IRP_PRS_DRAFT_LowNGPri
ce
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
Baseline 2 portfolio, low gas price scenario. Includes
a summary of resource selected, financial summary,
clean goal progress, loads & resources, demand
response, resource data, energy efficiency selected,
Aurora resource results, transmission annual
revenue requirement from amortization model,
annual cost of resource options, resources (MWh),
hydro & contracts market value, stochastic variable
cost of risk, general assumptions, regional
emissions, conservation load value ($/MW) and new
3_PRiSM_7.0_GUROBI_12072
0_IRP_PRS_DRAFT_SCC
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
Baseline 2 portfolio, social cost of carbon scenario.
Includes a summary of resource selected, financial
summary, clean goal progress, loads & resources,
demand response, resource data, energy efficiency
selected, Aurora resource results, transmission
annual revenue requirement from amortization
model, annual cost of resource options, resources
(MWh), hydro & contracts market value, stochastic
variable cost of risk, general assumptions, regional
emissions, conservation load value ($/MW) and new
5_PRiSM_7.0_GUROBI_12072
0_IRP_PRS_DRAFT_Determini
stic
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
2027 clean resource plan, add clean energy
resources to = 100% retail sales, deterministic
scenario. Includes a summary of resource selected,
financial summary, clean goal progress, loads &
Avista Corp.2021 Electric IRP Appendices 1073
Appendix I
Avista Corp 2021 Electric IRP 7
efficiency selected, Aurora resource results,
transmission annual revenue requirement from
amortization model, annual cost of resource options,
resources (MWh), hydro & contracts market value,
stochastic variable cost of risk, general assumptions,
regional emissions, conservation load value ($/MW)
5_PRiSM_7.0_GUROBI_12072
0_IRP_PRS_DRAFT_HighNGPr
ice
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
2027 clean resource plan, add clean energy
resources to = 100% retail sales, high natural gas
price scenario. Includes a summary of resource
selected, financial summary, clean goal progress,
loads & resources, demand response, resource
data, energy efficiency selected, Aurora resource
results, transmission annual revenue requirement
from amortization model, annual cost of resource
options, resources (MWh), hydro & contracts market
value, stochastic variable cost of risk, general
assumptions, regional emissions, conservation load
5_PRiSM_7.0_GUROBI_12072
0_IRP_PRS_DRAFT_LowNGPri
ce
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
2027 clean resource plan, add clean energy
resources to = 100% retail sales, low natural gas
price scenario. Includes a summary of resource
selected, financial summary, clean goal progress,
loads & resources, demand response, resource
data, energy efficiency selected, Aurora resource
results, transmission annual revenue requirement
from amortization model, annual cost of resource
options, resources (MWh), hydro & contracts market
value, stochastic variable cost of risk, general
assumptions, regional emissions, conservation load
Avista Corp.2021 Electric IRP Appendices 1074
Appendix I
Avista Corp 2021 Electric IRP 8
5_PRiSM_7.0_GUROBI_12072
0_IRP_PRS_DRAFT_SCC
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
2027 clean resource plan, add clean energy
resources to = 100% retail sales, social cost of
carbon scenario. Includes a summary of resource
selected, financial summary, clean goal progress,
loads & resources, demand response, resource
data, energy efficiency selected, Aurora resource
results, transmission annual revenue requirement
from amortization model, annual cost of resource
options, resources (MWh), hydro & contracts market
value, stochastic variable cost of risk, general
assumptions, regional emissions, conservation load
6_PRiSM_7.0_GUROBI_12072
0_IRP_PRS_DRAFT_Determini
stic
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
2045 clean resource plan, add clean energy
resources to = 100% retail sales, no new thermal
resource, existing thermal resource retire by 2044,
long lake and cabinet upgrades turned on,
deterministic scenario. Includes a summary of
resource selected, financial summary, clean goal
progress, loads & resources, demand response,
resource data, energy efficiency selected, Aurora
resource results, transmission annual revenue
requirement from amortization model, annual cost of
resource options, resources (MWh), hydro &
contracts market value, stochastic variable cost of
risk, general assumptions, regional emissions,
6_PRiSM_7.0_GUROBI_12072
0_IRP_PRS_DRAFT_HighNGPr
ice
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
2045 clean resource plan, add clean energy
resources to = 100% retail sales, no new thermal
resource, existing thermal resource retire by 2044,
Avista Corp.2021 Electric IRP Appendices 1075
Appendix I
Avista Corp 2021 Electric IRP 9
natural gas price scenario. Includes a summary of
resource selected, financial summary, clean goal
progress, loads & resources, demand response,
resource data, energy efficiency selected, Aurora
resource results, transmission annual revenue
requirement from amortization model, annual cost of
resource options, resources (MWh), hydro &
contracts market value, stochastic variable cost of
risk, general assumptions, regional emissions,
6_PRiSM_7.0_GUROBI_12072
0_IRP_PRS_DRAFT_LowNGPri
ce
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
2045 clean resource plan, add clean energy
resources to = 100% retail sales, no new thermal
resource, existing thermal resource retire by 2044,
long lake and cabinet upgrades turned on, low
natural gas price scenario. Includes a summary of
resource selected, financial summary, clean goal
progress, loads & resources, demand response,
resource data, energy efficiency selected, Aurora
resource results, transmission annual revenue
requirement from amortization model, annual cost of
resource options, resources (MWh), hydro &
contracts market value, stochastic variable cost of
risk, general assumptions, regional emissions,
6_PRiSM_7.0_GUROBI_12072
0_IRP_PRS_DRAFT_SCC
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
2045 clean resource plan, add clean energy
resources to = 100% retail sales, no new thermal
resource, existing thermal resource retire by 2044,
long lake and cabinet upgrades turned on, social
cost of carbon scenario. Includes a summary of
resource selected, financial summary, clean goal
Avista Corp.2021 Electric IRP Appendices 1076
Appendix I
Avista Corp 2021 Electric IRP 10
resource data, energy efficiency selected, Aurora
resource results, transmission annual revenue
requirement from amortization model, annual cost of
resource options, resources (MWh), hydro &
contracts market value, stochastic variable cost of
risk, general assumptions, regional emissions,
15_PRiSM_7.0_GUROBI_1207
20_IRP_PRS_DRAFT_Determin
istic
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
Colstrip retire 2025, deterministic scenario. Includes
a summary of resource selected, financial summary,
clean goal progress, loads & resources, demand
response, resource data, energy efficiency selected,
Aurora resource results, transmission annual
revenue requirement from amortization model,
annual cost of resource options, resources (MWh),
hydro & contracts market value, stochastic variable
cost of risk, general assumptions, regional
emissions, conservation load value ($/MW) and new
15_PRiSM_7.0_GUROBI_1207
20_IRP_PRS_DRAFT_HighNG
Price
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
Colstrip retire 2025, high natural gas price scenario.
Includes a summary of resource selected, financial
summary, clean goal progress, loads & resources,
demand response, resource data, energy efficiency
selected, Aurora resource results, transmission
annual revenue requirement from amortization
model, annual cost of resource options, resources
(MWh), hydro & contracts market value, stochastic
variable cost of risk, general assumptions, regional
emissions, conservation load value ($/MW) and new
Avista Corp.2021 Electric IRP Appendices 1077
Appendix I
Avista Corp 2021 Electric IRP 11
15_PRiSM_7.0_GUROBI_1207
20_IRP_PRS_DRAFT_LowNGP
rice
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
Colstrip retire 2025, low natural gas price scenario.
Includes a summary of resource selected, financial
summary, clean goal progress, loads & resources,
demand response, resource data, energy efficiency
selected, Aurora resource results, transmission
annual revenue requirement from amortization
model, annual cost of resource options, resources
(MWh), hydro & contracts market value, stochastic
variable cost of risk, general assumptions, regional
emissions, conservation load value ($/MW) and new
15_PRiSM_7.0_GUROBI_1207
20_IRP_PRS_DRAFT_SCC
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
Colstrip retire 2025, social cost of carbon scenario.
Includes a summary of resource selected, financial
summary, clean goal progress, loads & resources,
demand response, resource data, energy efficiency
selected, Aurora resource results, transmission
annual revenue requirement from amortization
model, annual cost of resource options, resources
(MWh), hydro & contracts market value, stochastic
variable cost of risk, general assumptions, regional
emissions, conservation load value ($/MW) and new
16_PRiSM_7.0_GUROBI_1207
20_IRP_PRS_DRAFT_Determin
istic
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
Colstrip retire 2035, deterministic scenario. Includes
a summary of resource selected, financial summary,
clean goal progress, loads & resources, demand
response, resource data, energy efficiency selected,
Aurora resource results, transmission annual
revenue requirement from amortization model,
annual cost of resource options, resources (MWh),
Avista Corp.2021 Electric IRP Appendices 1078
Appendix I
Avista Corp 2021 Electric IRP 12
cost of risk, general assumptions, regional
emissions, conservation load value ($/MW) and new
16_PRiSM_7.0_GUROBI_1207
20_IRP_PRS_DRAFT_HighNG
Price
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
Colstrip retire 2035, high natural gas price scenario.
Includes a summary of resource selected, financial
summary, clean goal progress, loads & resources,
demand response, resource data, energy efficiency
selected, Aurora resource results, transmission
annual revenue requirement from amortization
model, annual cost of resource options, resources
(MWh), hydro & contracts market value, stochastic
variable cost of risk, general assumptions, regional
emissions, conservation load value ($/MW) and new
16_PRiSM_7.0_GUROBI_1207
20_IRP_PRS_DRAFT_LowNGP
rice
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
Colstrip retire 2035, low natural gas price scenario.
Includes a summary of resource selected, financial
summary, clean goal progress, loads & resources,
demand response, resource data, energy efficiency
selected, Aurora resource results, transmission
annual revenue requirement from amortization
model, annual cost of resource options, resources
(MWh), hydro & contracts market value, stochastic
variable cost of risk, general assumptions, regional
emissions, conservation load value ($/MW) and new
16_PRiSM_7.0_GUROBI_1207
20_IRP_PRS_DRAFT_SCC
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
Colstrip retire 2035, social cost of carbon scenario.
Includes a summary of resource selected, financial
summary, clean goal progress, loads & resources,
demand response, resource data, energy efficiency
Avista Corp.2021 Electric IRP Appendices 1079
Appendix I
Avista Corp 2021 Electric IRP 13
annual revenue requirement from amortization
model, annual cost of resource options, resources
(MWh), hydro & contracts market value, stochastic
variable cost of risk, general assumptions, regional
emissions, conservation load value ($/MW) and new
17_PRiSM_7.0_GUROBI_1207
20_IRP_PRS_DRAFT_Determin
istic
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
Colstrip retire 2045, deterministic scenario. Includes
a summary of resource selected, financial summary,
clean goal progress, loads & resources, demand
response, resource data, energy efficiency selected,
Aurora resource results, transmission annual
revenue requirement from amortization model,
annual cost of resource options, resources (MWh),
hydro & contracts market value, stochastic variable
cost of risk, general assumptions, regional
emissions, conservation load value ($/MW) and new
17_PRiSM_7.0_GUROBI_1207
20_IRP_PRS_DRAFT_HighNG
Price
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
Colstrip retire 2045, high natural gas price scenario.
Includes a summary of resource selected, financial
summary, clean goal progress, loads & resources,
demand response, resource data, energy efficiency
selected, Aurora resource results, transmission
annual revenue requirement from amortization
model, annual cost of resource options, resources
(MWh), hydro & contracts market value, stochastic
variable cost of risk, general assumptions, regional
emissions, conservation load value ($/MW) and new
17_PRiSM_7.0_GUROBI_1207
20_IRP_PRS_DRAFT_LowNGP
PRiSM Model
Files- Portfolio
Excel PRiSM model - must have Gurobi license to run.
Colstrip retire 2045, low natural gas price scenario.
Avista Corp.2021 Electric IRP Appendices 1080
Appendix I
Avista Corp 2021 Electric IRP 14
summary, clean goal progress, loads & resources,
demand response, resource data, energy efficiency
selected, Aurora resource results, transmission
annual revenue requirement from amortization
model, annual cost of resource options, resources
(MWh), hydro & contracts market value, stochastic
variable cost of risk, general assumptions, regional
emissions, conservation load value ($/MW) and new
17_PRiSM_7.0_GUROBI_1207
20_IRP_PRS_DRAFT_SCC
PRiSM Model
Files- Portfolio
Scenarios
Excel PRiSM model - must have Gurobi license to run.
Colstrip retire 2045, social cost of carbon scenario.
Includes a summary of resource selected, financial
summary, clean goal progress, loads & resources,
demand response, resource data, energy efficiency
selected, Aurora resource results, transmission
annual revenue requirement from amortization
model, annual cost of resource options, resources
(MWh), hydro & contracts market value, stochastic
variable cost of risk, general assumptions, regional
emissions, conservation load value ($/MW) and new
1_PRiSM_7.0_GUROBI_12072
0_IRP_PRS
PRiSM Model
Files- Portfolio
Studies
Excel PRiSM model - must have Gurobi license to run.
Least reasonable cost. preferred resource strategy.
Includes a summary of resource selected, financial
summary, clean goal progress, loads & resources,
demand response, resource data, energy efficiency
selected, Aurora resource results, transmission
annual revenue requirement from amortization
model, annual cost of resource options, resources
(MWh), hydro & contracts market value, stochastic
variable cost of risk, general assumptions, regional
emissions, conservation load value ($/MW) and new
Avista Corp.2021 Electric IRP Appendices 1081
Appendix I
Avista Corp 2021 Electric IRP 15
2_PRiSM_7.0_GUROBI_12072
0_IRP_Baseline1
PRiSM Model
Files- Portfolio
Studies
Excel PRiSM model - must have Gurobi license to run.
Baseline 1, removes clean energy targets in
Washington. Includes a summary of resource
selected, financial summary, clean goal progress,
loads & resources, demand response, resource
data, energy efficiency selected, Aurora resource
results, transmission annual revenue requirement
from amortization model, annual cost of resource
options, resources (MWh), hydro & contracts market
value, stochastic variable cost of risk, general
assumptions, regional emissions, conservation load
3_PRiSM_7.0_GUROBI_12072
0_IRP_Baseline2
PRiSM Model
Files- Portfolio
Studies
Excel PRiSM model - must have Gurobi license to run.
Baseline 2, no clean goal, no SCC, EE held
constant, existing resources held constant, remove
flex plant as option due to size even though it’s
preferred. Includes a summary of resource selected,
financial summary, clean goal progress, loads &
resources, demand response, resource data, energy
efficiency selected, Aurora resource results,
transmission annual revenue requirement from
amortization model, annual cost of resource options,
resources (MWh), hydro & contracts market value,
stochastic variable cost of risk, general assumptions,
regional emissions, conservation load value ($/MW)
4_PRiSM_7.0_GUROBI_12072
0_IRP_Baseline3
PRiSM Model
Files- Portfolio
Studies
Excel PRiSM model - must have Gurobi license to run.
Baseline 3, no clean goal, no SCC, EE held
constant, existing resources held constant. Includes
a summary of resource selected, financial summary,
clean goal progress, loads & resources, demand
response, resource data, energy efficiency selected,
Avista Corp.2021 Electric IRP Appendices 1082
Appendix I
Avista Corp 2021 Electric IRP 16
revenue requirement from amortization model,
annual cost of resource options, resources (MWh),
hydro & contracts market value, stochastic variable
cost of risk, general assumptions, regional
emissions, conservation load value ($/MW) and new
5_PRiSM_7.0_GUROBI_12072
0_IRP_2027 CRP
PRiSM Model
Files- Portfolio
Studies
Excel PRiSM model - must have Gurobi license to run.
2027 clean resource plan, add clean energy
resources to = 100% retail sales. Includes a
summary of resource selected, financial summary,
clean goal progress, loads & resources, demand
response, resource data, energy efficiency selected,
Aurora resource results, transmission annual
revenue requirement from amortization model,
annual cost of resource options, resources (MWh),
hydro & contracts market value, stochastic variable
cost of risk, general assumptions, regional
emissions, conservation load value ($/MW) and new
6_PRiSM_7.0_GUROBI_12072
0_IRP_2045 CRP
PRiSM Model
Files- Portfolio
Studies
Excel PRiSM model - must have Gurobi license to run.
2045 clean resource plan, add clean energy
resources to = 100% retail sales, no new thermal
resource, existing thermal resource retire by 2044,
long lake and cabinet upgrades turned on. Includes
a summary of resource selected, financial summary,
clean goal progress, loads & resources, demand
response, resource data, energy efficiency selected,
Aurora resource results, transmission annual
revenue requirement from amortization model,
annual cost of resource options, resources (MWh),
hydro & contracts market value, stochastic variable
Avista Corp.2021 Electric IRP Appendices 1083
Appendix I
Avista Corp 2021 Electric IRP 17
emissions, conservation load value ($/MW) and new
6b_PRiSM_7.0_GUROBI_1207
20_IRP_2045 CRP
PRiSM Model
Files- Portfolio
Studies
Excel PRiSM model - must have Gurobi license to run.
2045 clean resource plan, add clean energy
resources to = 100%, Colstrip exits in 2022 retail
sales, no new thermal resource, existing thermal
resource retire by 2044, long lake and cabinet
upgrades turned on. Includes a summary of resource
selected, financial summary, clean goal progress,
loads & resources, demand response, resource
data, energy efficiency selected, Aurora resource
results, transmission annual revenue requirement
from amortization model, annual cost of resource
options, resources (MWh), hydro & contracts market
value, stochastic variable cost of risk, general
assumptions, regional emissions, conservation load
7_PRiSM_7.0_GUROBI_12072
0_IRP_SCC Applied to ID
PRiSM Model
Files- Portfolio
Studies
Excel PRiSM model - must have Gurobi license to run.
Social cost of carbon applied to Idaho, EE held
constant. Includes a summary of resource selected,
financial summary, clean goal progress, loads &
resources, demand response, resource data, energy
efficiency selected, Aurora resource results,
transmission annual revenue requirement from
amortization model, annual cost of resource options,
resources (MWh), hydro & contracts market value,
stochastic variable cost of risk, general assumptions,
regional emissions, conservation load value ($/MW)
8_PRiSM_7.0_GUROBI_12072
0_IRP_Low Load Forecast
PRiSM Model
Files- Portfolio
Studies
Excel PRiSM model - must have Gurobi license to run.
Low load forecast scenario, EE held constant from
PRS. Includes a summary of resource selected,
Avista Corp.2021 Electric IRP Appendices 1084
Appendix I
Avista Corp 2021 Electric IRP 18
resources, demand response, resource data, energy
efficiency selected, Aurora resource results,
transmission annual revenue requirement from
amortization model, annual cost of resource options,
resources (MWh), hydro & contracts market value,
stochastic variable cost of risk, general assumptions,
regional emissions, conservation load value ($/MW)
9_PRiSM_7.0_GUROBI_12072
0_IRP_High Load Forecast
PRiSM Model
Files- Portfolio
Studies
Excel PRiSM model - must have Gurobi license to run.
High load forecast scenario, EE held constant from
PRS. Includes a summary of resource selected,
financial summary, clean goal progress, loads &
resources, demand response, resource data, energy
efficiency selected, Aurora resource results,
transmission annual revenue requirement from
amortization model, annual cost of resource options,
resources (MWh), hydro & contracts market value,
stochastic variable cost of risk, general assumptions,
regional emissions, conservation load value ($/MW)
10_PRiSM_7.0_GUROBI_1207
20_RA Market
PRiSM Model
Files- Portfolio
Studies
Excel PRiSM model - must have Gurobi license to run.
Resource adequacy market scenario, uses RA
market planning requirements rather than Avista’s,
includes change to existing resources and changes
to peak credits for new resources. Includes a
summary of resource selected, financial summary,
clean goal progress, loads & resources, demand
response, resource data, energy efficiency selected,
Aurora resource results, transmission annual
revenue requirement from amortization model,
annual cost of resource options, resources (MWh),
hydro & contracts market value, stochastic variable
Avista Corp.2021 Electric IRP Appendices 1085
Appendix I
Avista Corp 2021 Electric IRP 19
emissions, conservation load value ($/MW) and new
11_PRiSM_7.0_GUROBI_1207
20_IRP_Electirication 1
PRiSM Model
Files- Portfolio
Studies
Excel PRiSM model - must have Gurobi license to run.
Electrification scenario 1, forecast of additional load
due to natural gas customers moving to electric,
uses Avista forecast on load changes, updates EE
programs & DR for additional opportunities,
adjustments made to load value & retail sales.
Includes a summary of resource selected, financial
summary, clean goal progress, loads & resources,
demand response, resource data, energy efficiency
selected, Aurora resource results, transmission
annual revenue requirement from amortization
model, annual cost of resource options, resources
(MWh), hydro & contracts market value, stochastic
variable cost of risk, general assumptions, regional
emissions, conservation load value ($/MW) and new
12_PRiSM_7.0_GUROBI_1207
20_IRP_Electirication 2
PRiSM Model
Files- Portfolio
Studies
Excel PRiSM model - must have Gurobi license to run.
Electrification scenario 2 – hybrid scenario, forecast
of additional load due to natural gas customers
moving to electric, uses Avista forecast on load
changes, updates EE programs & DR for additional
opportunities, adjustments made to load value &
retail sales. Includes a summary of resource
selected, financial summary, clean goal progress,
loads & resources, demand response, resource
data, energy efficiency selected, Aurora resource
results, transmission annual revenue requirement
from amortization model, annual cost of resource
options, resources (MWh), hydro & contracts market
Avista Corp.2021 Electric IRP Appendices 1086
Appendix I
Avista Corp 2021 Electric IRP 20
assumptions, regional emissions, conservation load
13_PRiSM_7.0_GUROBI_1207
20_IRP_Electirication 3
PRiSM Model
Files- Portfolio
Studies
Excel PRiSM model - must have Gurobi license to run.
Electrification scenario 3 – high efficiency, forecast
of additional load due to natural gas customers
moving to electric, uses Avista forecast on load
changes, updates EE programs & DR for additional
opportunities, adjustments made to load value &
retail sales. Includes a summary of resource
selected, financial summary, clean goal progress,
loads & resources, demand response, resource
data, energy efficiency selected, Aurora resource
results, transmission annual revenue requirement
from amortization model, annual cost of resource
options, resources (MWh), hydro & contracts market
value, stochastic variable cost of risk, general
assumptions, regional emissions, conservation load
14_PRiSM_7.0_GUROBI_1207
20_IRP_2xSCC
PRiSM Model
Files- Portfolio
Studies
Excel PRiSM model - must have Gurobi license to run.
Social cost of carbon times 2, doubles SCC for
Washington – least cost strategy with this
assumption. Includes a summary of resource
selected, financial summary, clean goal progress,
loads & resources, demand response, resource
data, energy efficiency selected, Aurora resource
results, transmission annual revenue requirement
from amortization model, annual cost of resource
options, resources (MWh), hydro & contracts market
value, stochastic variable cost of risk, general
assumptions, regional emissions, conservation load
Avista Corp.2021 Electric IRP Appendices 1087
Appendix I
Avista Corp 2021 Electric IRP 21
15_PRiSM_7.0_GUROBI_1207
20_IRP_Colstrip2025
PRiSM Model
Files- Portfolio
Studies
Excel PRiSM model - must have Gurobi license to run.
Colstrip retire in 2025. Includes a summary of
resource selected, financial summary, clean goal
progress, loads & resources, demand response,
resource data, energy efficiency selected, Aurora
resource results, transmission annual revenue
requirement from amortization model, annual cost of
resource options, resources (MWh), hydro &
contracts market value, stochastic variable cost of
risk, general assumptions, regional emissions,
16_PRiSM_7.0_GUROBI_1207
20_IRP_Colstrip2035
PRiSM Model
Files- Portfolio
Studies
Excel PRiSM model - must have Gurobi license to run.
Colstrip retire in 2035. Includes a summary of
resource selected, financial summary, clean goal
progress, loads & resources, demand response,
resource data, energy efficiency selected, Aurora
resource results, transmission annual revenue
requirement from amortization model, annual cost of
resource options, resources (MWh), hydro &
contracts market value, stochastic variable cost of
risk, general assumptions, regional emissions,
17_PRiSM_7.0_GUROBI_1207
20_IRP_Colstrip2045
PRiSM Model
Files- Portfolio
Studies
Excel PRiSM model - must have Gurobi license to run.
Colstrip retire in 2045. Includes a summary of
resource selected, financial summary, clean goal
progress, loads & resources, demand response,
resource data, energy efficiency selected, Aurora
resource results, transmission annual revenue
requirement from amortization model, annual cost of
resource options, resources (MWh), hydro &
contracts market value, stochastic variable cost of
risk, general assumptions, regional emissions,
Avista Corp.2021 Electric IRP Appendices 1088
Appendix I
Avista Corp 2021 Electric IRP 22
18_PRiSM_7.0_GUROBI_1207
20_IRP_2045 100 Delivered
PRiSM Model
Files- Portfolio
Studies
Excel PRiSM model - must have Gurobi license to run. Not
optimized, add clean resources and storage to meet
delivery to load requirements. Includes a summary of
resource selected, financial summary, clean goal
progress, loads & resources, demand response,
resource data, energy efficiency selected, Aurora
resource results, transmission annual revenue
requirement from amortization model, annual cost of
resource options, resources (MWh), hydro &
contracts market value, stochastic variable cost of
risk, general assumptions, regional emissions,
19_PRiSM_7.0_GUROBI_1207
20_IRP_SCC_PS
PRiSM Model
Files- Portfolio
Studies
Excel PRiSM model - must have Gurobi license to run.
Social cost of carbon applied to net purchases,
includes net purchase included storage purchases.
Includes a summary of resource selected, financial
summary, clean goal progress, loads & resources,
demand response, resource data, energy efficiency
selected, Aurora resource results, transmission
annual revenue requirement from amortization
model, annual cost of resource options, resources
(MWh), hydro & contracts market value, stochastic
variable cost of risk, general assumptions, regional
emissions, conservation load value ($/MW) and new
20_PRiSM_7.0_GUROBI_1207
20_IRP_EE-Avg Mrkt Emissions
PRiSM Model
Files- Portfolio
Studies
Excel PRiSM model - must have Gurobi license to run. Use
average market emission rate rather than
incremental for EE SCC calculation, all other PRS
inputs/constraints are the same, this study is
conducted iteratively, meaning resulting EE is added
back in the model to adjust loads and re-run.
Includes a summary of resource selected, financial
Avista Corp.2021 Electric IRP Appendices 1089
Appendix I
Avista Corp 2021 Electric IRP 23
demand response, resource data, energy efficiency
selected, Aurora resource results, transmission
annual revenue requirement from amortization
model, annual cost of resource options, resources
(MWh), hydro & contracts market value, stochastic
variable cost of risk, general assumptions, regional
emissions, conservation load value ($/MW) and new
21_PRiSM_7.0_GUROBI_1207
20_IRP_PRS_Draft_Maximum
Benefit
PRiSM Model
Files- Portfolio
Studies
Excel PRiSM model - must have Gurobi license to run.
Washington maximum benefit. Includes a summary
of resource selected, financial summary, clean goal
progress, loads & resources, demand response,
resource data, energy efficiency selected, Aurora
resource results, transmission annual revenue
requirement from amortization model, annual cost of
resource options, resources (MWh), hydro &
contracts market value, stochastic variable cost of
risk, general assumptions, regional emissions,
PRiSM Draft Results_120720 PRiSM Model
Files- Portfolio
Studies
Excel Scenario list, summary data, sensitivity summary,
sensitivity data, summary resources PRS, existing
resources, annual summary by scenario, summary
table of PVRR ($ Mill) by state and select years, cost
vs risk by scenario, clean goal, GHG emissions,
PRiSM Model Guide PRiSM Model
Files- Portfolio
Word User guide for the PRiSM models.
2021 IRP New Supply Side Appendix I Excel Supply side resource option assumptions for cost,

Avista Corp.2021 Electric IRP Appendices 1090

2021 Electric Integrated
Resource Plan

Appendix J – Confidential Inputs
and Models

Idaho – Confidential pursuant to Sections 74-109, Idaho Code
Washington – Confidential per WAC 480-07-160

Avista Corp.2021 Electric IRP Appendices 1091
Appendix J
Avista Corp 2021 Electric IRP 1
Appendix J 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 J.

File Name Folder File Type Description of Content
ARAM Model Guide ARAM-Reliability Word User guide for ARAM models.
ARAM_2021_IRP_2025_No_Ad
ditions_121020_With Colstrip
ARAM-Reliability
Studies
Excel Reliability study considering no additions, with
Colstrip for select year.
ARAM_2021_IRP_2025_No_Ad ARAM-Reliability Excel Reliability study considering no additions, without
ARAM_2021_IRP_2025_PRS ARAM-Reliability Excel Reliability study considering PRS for select year.
ARAM_2021_IRP_2030_330 ARAM-Reliability Excel Reliability study considering 330 market and PRS
ARAM_2021_IRP_2030_330 ARAM-Reliability Excel Reliability study considering 330 market scenario 5
ARAM_2021_IRP_2030_330 ARAM-Reliability Excel Reliability study considering 330 market scenario 10
ARAM_2021_IRP_2030_330 ARAM-Reliability Excel Reliability study considering 330 market scenario 16
ARAM_2021_IRP_2030_333MW ARAM-Reliability Excel Reliability study considering 333 MW of CTs and
ARAM_2021_IRP_2040_No_Ad ARAM-Reliability Excel Reliability study considering no additions, for select
ARAM_2021_IRP_2040_PRS ARAM-Reliability Excel Reliability study considering PRS for select year.
ARAM_2021_IRP_2040_PRS_3 ARAM-Reliability Excel Reliability study considering PRS and 3 units for
Avista Corp.2021 Electric IRP Appendices 1092
Appendix J
Avista Corp 2021 Electric IRP 2
ARAM_2021_IRP_2040_Scenari ARAM-Reliability Excel Reliability study considering scenario 6-CR2045 for
2021 IRP Aurora Files Aurora Deterministic model updated for climate change
2021 IRP
Deterministic_High_NG_Prices
Aurora Files Aurora Deterministic model updated for high natural gas
prices used for 2021 IRP.
2021 IRP Aurora Files Aurora Deterministic model updated for low natural gas
2021 IRP
Deterministic_No_AVA_EE
Aurora Files Aurora Deterministic model updated for no Avista energy
efficiency used for 2021 IRP.
2021 IRP Deterministic_SCC Aurora Files Aurora Deterministic model updated for social cost of
IRP_2021_US_Canada_DB_201 Aurora Files Database Aurora database for US/Canada
New Resources_Expected Case Aurora Files Excel Annual table inputs, summary, resource tables
DR Input Generator – Avista Appendix J Excel Demand response participation rates, impact,

Avista Corp.2021 Electric IRP Appendices 1093

Avista Corp.2021 Electric IRP Appendices 1094

2021 Electric Integrated
Resource Plan

Appendix K – Load Forecast
Supplement

Avista Corp.2021 Electric IRP Appendices 1095
Appendix K Page 1
Appendix K
Climate Change

The process of integrating climate change into the load forecast starts with estimating the
long-run trend in the 20-year average of annual heating degree days (HDD) and cooling
degree days (CDD). Ideally, trending the 20-year moving average introduces climate
change while still maintain a smoothed measure of normal (average) weather. Figure K.1
demonstrates the issues that need to be considered when choosing a method to introduce
climate change using HDD.
Figure K.1: Issues Related to Forecasted HDD and CDD

Line A reflects the most recent 20-year moving average (HDD20) ending with the current
calendar year (yc). In the current IRP, this is the 2000-2019 period. Without a climate
change adjustment, Line A is the assumed normal weather over Yc+n. Line A will only shift
up or down as the 20-year average is updated with a new year of HDD data. If climate
change is occurring, then line A will gradually shift down over time along the vertical axis.

A forward-looking climate change adjustment to line A requires introducing a trended
moving going forward in time—this is shown by line B or C. However, a method that
produces line C is problematic because, compared to line B, it introduces a significant
amount of year-to-year variation over the forecast period. In turn, this produces significant
amount of volatility in forecasted load, revenues, and earnings that may not be acceptable
to the planning process. However, even if a method produces a smooth trend over the
forecast horizon, another problem can arise. Specifically, if the method that produces line
B generates large shifts in the slope and intercept between forecast runs (i.e., the forecast
completed in year y versus the forecast completed in year y+1), this method will also
yc yc+n
HDD20

B*

Avista Corp.2021 Electric IRP Appendices 1096
Appendix K Page 2
produce a level of volatility that may not be acceptable. This is shown by line B* compared
to line B. This analysis shows that the method chosen should be stable over and between
forecast runs, yet still capture the current best guess path of climate change over the
forecast horizon.

The method used by Avista, starts with an analysis of the 20-year moving average of HDD
and CDD using a 20-year moving average time-series going back to 1967. In other words,
the first observation in the time series is the 20-year moving average for the period 1948-
1967, where 1948 is the start of Avista’s (AVA) annual billing adjusted HDD data
(discussed above). After analyzing the time-series behavior of both series, the following
time series regression equations are estimated:

[1A] ∆𝐻𝐷𝐷,=𝛿+𝜃∆𝐻𝐷𝐷,+𝜃∆𝐻𝐷𝐷,+𝜃∆𝐻𝐷𝐷,+𝜃∆𝐻𝐷𝐷,+
𝜃∆𝐻𝐷𝐷,+𝜖
[2A] ∆𝐶𝐷𝐷,=𝛿+𝛾∆𝐶𝐷𝐷,+𝛾∆𝐶𝐷𝐷,+𝛾∆𝐶𝐷𝐷,+𝛾∆𝐶𝐷𝐷,+
𝛾∆𝐶𝐷𝐷,+𝜖
Here, εy is a white noise, mean zero error term.
Assuming model stationarity, the constant value δ can be used to calculate the long-run
expected change in annual HDD and CDD:
[3A] 𝜇∆=()
[4A] 𝜇∆=()
This can then be applied to the current 20-year moving average to generate trended
values out a total of N years:
[5A] 𝐹(𝐻𝐷𝐷,) =𝐻𝐷𝐷,+𝑛𝜇∆ 𝑓𝑜𝑟 𝑛= 1, …,𝑁

[6A] 𝐹(𝐶𝐷𝐷,) =𝐶𝐷𝐷,+𝑛𝜇∆ 𝑓𝑜𝑟 𝑛= 1,… ,𝑁
For most IRPs, N = 25. If monthly values are needed over the forecast period, then the
annual values can be allocated monthly as follows:
[7A] 𝐹(𝐻𝐷𝐷,,) = ℎ𝐹(𝐻𝐷𝐷,) 𝑤ℎ𝑒𝑟𝑒 ℎ=
∑, 𝑓𝑜𝑟 𝑡=𝐽𝑎𝑛, …,𝐷𝑒𝑐
[8A] 𝐹(𝐶𝐷𝐷,,) =𝑐̅𝐹(𝐶𝐷𝐷,) 𝑤ℎ𝑒𝑟𝑒 𝑐̅=
∑,𝑓𝑜𝑟 𝑡=𝐽𝑎𝑛,…,𝐷𝑒𝑐

Avista Corp.2021 Electric IRP Appendices 1097
Appendix K Page 3
Here, ℎ and 𝑐̅ are the 20-year average share of HDD and CDD, respectively, in month
t. These monthly values can be used to convert the annual IRP simulation model forecasts
to monthly values or, alternatively, adding climate change to the peak load forecast. It
should be noted that an analysis of the share of HDD and CDD by month going back to
1948 do not show any apparent trends. This suggests, even under climate change, the
relative allocation of HDD and CDD across the months each year will not change
significantly going forward.
Returning to the annual, trended moving average forecasts of HDD and CDD, those can
be used to estimate the long-run impact on annual residential UPC (UPCr,y) in the face of
climate change, which can be applied to the long-run annual residential UPC forecast in
the IRP simulation model. This process starts with the following regression model:
[9A] 𝑈𝑃𝐶,=𝛼+𝛼𝐻𝐷𝐷+𝛼𝐶𝐷𝐷+𝛼𝑇∗+𝛼𝐷 +𝛼𝐷+
𝜖

Here HDDyAVA and CDDyAVA are the actual Avista adjusted degree days in year y; T* is a
linear trend starting with T*= 1 in 1997 (the beginning of the historical series); the
structural change dummies control for a change in data reporting after 1999 and the LEAP
gas program that ended in 2019;and εy is N(0, σ). None linear trends were also tried, by
the linear trend produced the best fit on the annual data. Using the estimated coefficients
(a), a forecast for UPC under climate change can be generated as follows:
[10A] 𝐹𝑈𝑃𝐶,=𝑎+𝑎𝐻𝐷𝐷,+𝑛𝜇∆+𝑎𝐶𝐷𝐷,+𝑛𝜇∆+𝑎𝑇∗+
𝑛 𝑓𝑜𝑟 𝑛= 0,… ,𝑁
Simplifying terms:
[11A] 𝐹𝑈𝑃𝐶,=𝑎+𝑎𝐻𝐷𝐷,+ 𝑎𝐶𝐷𝐷,+𝑎(𝑇∗+𝑛) + (𝑎𝜇∆+
𝑎𝜇∆)𝑛

[12A] 𝐹𝑈𝑃𝐶,=𝑎+𝑎𝐻𝐷𝐷,+ 𝑎𝐶𝐷𝐷,+𝑎𝑇∗+𝑛+𝑏𝑛 𝑤ℎ𝑒𝑟𝑒 𝑏≡
(𝑎𝜇∆+𝑎𝜇∆)
Note that 𝑏≡ (𝑎𝜇∆+𝑎𝜇∆) is treated as the annual marginal impact of total
climate change on UPC. Using the times series questions [3A] and [4A], we have µΔHDD
= -9.6 and µΔHDD = 3.4. Combining these with the estimated values of a1 = 0.732 and a2 =
1.170 we have:

[13A] 𝑏= 𝑎𝜇∆+𝑎𝜇∆= 0.732 ∙(−9.6)+ 1.170 ∙(3.4)= −3.049

This means the net impact of falling HDD and rising CDD is to reduce residential UPC
approximately 3 kWh a year, or a total cumulative impact b·N. Note that in the case of the
NPCC data, [x.x] becomes:

[14A] 𝑏= 0.732 ∙(−38)+ 1.170 ∙(8)= −18.455
Avista Corp.2021 Electric IRP Appendices 1098
Appendix K Page 4

In the context of the IRP simulation model, it is necessary to convert the annual load and
energy forecasts into a monthly number. Without climate change, this is straightforward
because it only requires extrapolating out the most recent 5-year forecast using the
forecasted long-run annual growth rates from the simulation model. This approach
essentially assumes the share of load by month in each year will not change significantly
over time, which is equivalent to assuming the most current 20-year moving average of
HDD and CDD is constant over the forecast horizon (see again Line A in Figure 1A).

However, with climate change, the share of load occurring each month will change
overtime. This means a method for estimating those future monthly load shares is
necessary to allocate the annual load values from the IRP simulation model. Since total
load can be trended over time, the method chosen here estimates a regression using the
first difference of month-to-month changes in total load and HDD and CDD, monthly
dummies (Dt,y), and an ARIMA error correction term to account for short-term
autocorrelation:
[15A] ∆𝐿,=𝛽+ 𝛽∆𝐻𝐷𝐷,+ 𝛽∆𝐶𝐷𝐷,+ 𝜷𝟑,𝑺𝑫𝑫𝒕,𝒚+
𝐴𝑅𝐼𝑀𝐴𝜖,(𝑝,𝑑,𝑞)(𝑝,𝑑,𝑞)

Here ΔLt,y = Lt - Lt-1; ΔHDDt,yAVA = HDDtAVA - HDD t-1AVA; ΔCDDt,yAVA = CDDtAVA - CDD t-1AVA.
Note that as will be shown shortly, β0 reflects the growth in load that occurs each month
over the forecast horizon. If β0 > 0, then this reflects positive load growth; β0 = 0 means
no load growth; and β0 > 0.

For the purposes of forecasting future load shares, the ARIMA portion is ignored and the
forecasted change in load relies solely on the estimated coefficients (b). This is done
because simulations including and excluding error term corrections found little impact
after the first year:

[16A] 𝐹∆𝐿,=𝑏+ 𝑏𝐹∆𝐻𝐷𝐷,,+ 𝑏𝐹∆𝐶𝐷𝐷,,+ 𝒃𝟑,𝑺𝑫𝑫𝒕,𝒚𝒏 𝑓𝑜𝑟 𝑛=
1, …,𝑁

Given [16A] and forecast of HDD and CDD, a monthly load forecast can start with, L12,Yc,
the last actual value for December of the most recent full calendar year, and the forecast
would carry to year N. For simplicity, note that the forecast notation, F(·), has been
dropped:
𝐿,=𝐿,+ ∆𝐿,
𝐿,=𝐿,+ ∆𝐿,
𝐿,=𝐿,+ ∆𝐿,
⋮
Avista Corp.2021 Electric IRP Appendices 1099
Appendix K Page 5
𝐿,=𝐿,+ ∆𝐿,
𝐿,=𝐿,+ ∆𝐿,
𝐿,=𝐿,+ ∆𝐿,
⋮
𝐿,=𝐿,+ ∆𝐿,
𝐿,=𝐿,+ ∆𝐿,
⋮
𝐿,=𝐿,+ ∆𝐿,
𝐿,=𝐿,+ ∆𝐿,

This process generates a series of total load values for each calendar year, n, over the
forecast horizon.

[17A] 𝐿=𝐿,

Therefore, for each year, n, the forecasted load share over that year can be calculated
as:

[18A] ,=𝜆,= 1

The monthly load shares can be applied to the annual forecast values in the simulation
model convert the annual forecasts to monthly values. However, prior to this allocation, it
may be required to manually adjust the estimated constant, b0, so that the average annual
load growth rate associated with [16A] matches the average annual growth rate from the
IRP simulation model. That is, because [16A] is being estimated from historical data, b0
reflects historical non-weather related growth. This can be seen by re-arranging [17A] as
follows:
[19A] 𝐿=𝐿,=𝐿,()+𝐿,+∆𝐿, 𝑓𝑜𝑟 𝑛= 1,…,𝑁
Substituting in the estimated regression [16A]:
[20A] 𝐿=𝐿,()+𝐿,+(𝑏+ 𝑏∆𝐻𝐷𝐷,,+
𝑏∆𝐶𝐷𝐷,,+ 𝒃𝟑,𝑺𝑫𝑫𝒕,𝒚)
Avista Corp.2021 Electric IRP Appendices 1100
Appendix K Page 6
[21A] 𝐿= 12𝑏+𝐿,()+𝐿,+( 𝑏∆𝐻𝐷𝐷,,+
𝑏∆𝐶𝐷𝐷,,+ 𝒃𝟑,𝑺𝑫𝑫𝒕,𝒚)

[21A] shows that for any calendar year, non-weather-related load accumulates by 12b0.
Accounting for the accumulation over all N periods:

[22A] 𝐿,=𝐿,+∆𝐿,+∆𝐿,+∆𝐿,…+∆𝐿,()+
∆𝐿,

[23A] 𝐿,=𝐿,+(∑∆𝐿)

[24A] 𝐿,=𝐿,+𝑏+ 𝑏∆𝐻𝐷𝐷,+ 𝑏∆𝐶𝐷𝐷,+ 𝒃𝟑,𝑺𝑫𝑫𝒕,𝒚

[25A] 𝐿,=𝐿,+𝑁12𝑏+𝑏∆𝐻𝐷𝐷,+ 𝑏∆𝐶𝐷𝐷,+ 𝒃𝟑,𝑺𝑫𝑫𝒕,𝒚

Non-weather related load accumulation over all N periods is N12b0.
To integrate climate change into the peak load model, note that any 20-year moving
average can be used to calculate the implied average temperature associated with a
given month, t; note that C is the cut-off for CDD and HDD, which Avista sets at 65
degrees, and D is the number of days in month t:
[26A] 𝐶𝐷𝐷,,=,=
,,=
,,∙
=
∙∙,,
= −𝐷∙𝐶+𝐷
,,
= −𝐷∙𝐶+𝐷𝑇,,⇒𝑇,,=∙,,

[27A] 𝐻𝐷𝐷,,=
,
=
,,
=
∙,,
=
∙∙,,
=𝐷∙𝐶−𝐷
,,
=𝐷∙𝐶−𝐷∙𝑇,,⇒𝑇,,=∙,,

Given forecasted values for the 20-year moving average of HDD and CDD (equations
[5A] and [6A]), the formulas above are used to calculate the implied 20-year moving
Avista Corp.2021 Electric IRP Appendices 1101
Appendix K Page 7
average of average temperature forecasted for month t. The average annual change in
this temperature can be applied to calculate the expected change in average summer
and winter peak temperatures for integrating climate change into the peak load forecast.
Note that the growing (summer) or falling (winter) temperatures with act to accelerate
growth (in the case of summer) or decelerate growth (in the case of winter), in addition to
any impact associated with assumed economic growth. Thus:
[28A] ∆𝑇,=,,,,
() 𝑓𝑜𝑟 𝑒𝑖𝑡ℎ𝑒𝑟 𝐶𝐷𝐷 𝑜𝑟 𝐻𝐷𝐷 𝑓𝑜𝑟 𝑚𝑜𝑛𝑡ℎ 𝑡

[29A] 𝐹(𝐴,,) =
,,
+𝑛∙ ∆𝑇, 𝑓𝑜𝑟 𝑛= 1,…,𝑁 𝑦𝑒𝑎𝑟𝑠
[30A] 𝐹(𝐴,,) =,,+𝑛∙ ∆𝑇, 𝑓𝑜𝑟 𝑛= 1,…,𝑁 𝑦𝑒𝑎𝑟𝑠
From each series At,y, MAX is based on maximum daily average temperature and MIN is
based on minimum average daily temperatures. The first expression on the right of the
equals sign is the current 20-year historic average of MAX and MIN temperatures. The
second expression is the trending factor applied to the 20-year average. These trended
averages can then be converted back into CDD and HDD to be used in the peak-load
forecast model. These provide a trended values of CDD and HDD associated with peak
load.

Avista Corp.2021 Electric IRP Appendices 1102