20230929Application.pdf

LISA D. NORDSTROM
Lead Counsel
[e-mail]

September 29, 2023

VIA ELECTRONIC EMAIL

Jan Noriyuki, Secretary
Idaho Public Utilities Commission
11331 W. Chinden Blvd., Bldg 8,
Suite 201-A (83714)
PO Box 83720
Boise, Idaho 83720-0074

Re: Case No. IPC-E-23-23
Idaho Power Company’s 2023 Integrated Resource Plan

Dear Ms. Noriyuki:

Attached for electronic filing is Idaho Power Company’s 2023 Integrated Resource
Plan.

Additionally, four (4) copies of Idaho Power Company’s 2023 Integrated Resource
Plan will be hand delivered.

If you have any questions about the attached documents, please do not hesitate
to contact me.

Very truly yours,

Lisa D. Nordstrom
LDN:sg
Attachments
RECEIVED
Friday, September 29, 2023 3:53:54 PM
IDAHO PUBLIC
UTILITIES COMMISSION

APPLICATION - 1
LISA D. NORDSTROM (ISB No. 5733)
MEGAN GOICOECHEA ALLEN (ISB. No. 7623)
Idaho Power Company
1221 West Idaho Street (83702)
P.O. Box 70
Boise, Idaho 83707
Telephone: [phone]
Facsimile: [phone]
[e-mail]
[e-mail]

Attorneys for Idaho Power Company

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF IDAHO POWER
COMPANY’S 2023 INTEGRATED
RESOURCE PLAN.
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CASE NO. IPC-E-23-23

APPLICATION

COMES NOW, Idaho Power Company (“Idaho Power” or “Company”), and in
accordance with Idaho Public Utilities Commission (“Commission” or “IPUC”) Order No.
22299, requests that the Commission issue an order acknowledging the Company’s 2023
Integrated Resource Plan (“IRP” or “Plan”). In support of this request, Idaho Power states
as follows:
I. INTRODUCTION
1. Idaho Power’s 2023 IRP represents a comprehensive analysis of the
optimal mix of both demand- and supply-side resources available to reliably serve
customer demand and flexible capacity needs over the Plan’s 20-year planning horizon

APPLICATION - 2
from 2024 to 2043. Using a robust modeling tool called AURORA, resources are selected
from a variety of supply- and demand-side options to develop optimal portfolios (or sets
of resources) for various future scenarios. To ensure that the modeling results in least-
cost, least-risk portfolios, Idaho Power employed verification tests to validate the most
economic portfolio under numerous variations of resources and timing and employed
separate tests to ensure each portfolio would meet the Company’s reliability
requirements.
2. In the 2023 IRP, Idaho Power underscores the critical importance of
flexibility and adaptability in resource planning. The Company is managing and planning
for substantial growth while operating in a rapidly changing technological, market, and
policy landscape. Historically, the biennial development of the IRP has allowed Idaho
Power to timely update its long-term resource plan based on changing circumstances.
Over the past several years, however, balancing load and resources has become
increasingly more dynamic as major planning inputs and assumptions are subject to
change in real time. These long-term planning challenges are certainly not unique to
Idaho Power, as its utility peers and industry partners are facing the same dual
challenges of accelerated demand for clean energy resources and unwavering
commitment to provide customers with reliable, low-cost service.
3. However, several individual uncertainties in this planning cycle are specific
to Idaho Power. Due to the increased level of uncertainty surrounding several important
near-term decisions, the 2023 IRP has been prepared in a manner intended to provide
the flexibility and adaptability necessary to inform decisions as more information
becomes known prior to the next planning cycle. A few examples include significant load

APPLICATION - 3
growth, the timing of the Boardman to Hemingway (“B2H”) transmission line in-service
date, and Idaho Power’s potential involvement in the Southwest Intertie Project-North
(“SWIP-N”) transmission project. These, and other planning scenarios, are discussed in
greater detail throughout the IRP.
4. The importance of flexibility and adaptability in resource planning is a theme
throughout the 2023 IRP and apparent in the optimal, least-cost, and least-risk resource
build out of the Preferred Portfolio, which tells the story of the Company’s substantial
forecasted growth. Specifically, the Preferred Portfolio adds 3,325 megawatts (“MW”) of
solar, 1,800 MW of wind, 1,453 MW of storage (four- and eight-hour batteries, as well as
long-duration 100-hour storage), 360 MW of additional energy efficiency (“EE”), 340 MW
of hydrogen (“H2”), 160 MW of new demand response (“DR”), and 30 MW of geothermal.
Additionally, the Preferred Portfolio includes conversions of multiple coal-fired generation
units to natural gas, showing the Company exiting coal entirely in 2030 and adding a net
total of 261 MW of natural gas via coal conversions through 2043 (reflecting the addition
of 967 MW of gas conversions and 706 MW of gas conversion exits, netting 261 MW of
additional gas generation).
5. In total, the Preferred Portfolio—considering both additions and exits—adds
6,888 MW of incremental resource capacity over the next 20 years. To support these
resource additions, the Preferred Portfolio also includes the B2H transmission line
beginning in July 2026 and three Gateway West (“GWW”) transmission line segments
phased in from 2029 to 2040.
6. The Near-Term Action Plan puts an ever finer point on the Company’s
growth and includes more than a dozen major actions and activities spanning supply-

APPLICATION - 4
and demand-side resources, transmission and distribution expansion, and regional and
customer programs:
 Continue exploring potential participation in the SWIP-N project in 2023-
2024;

 Add 100 MW of solar and 96 MW of four-hour storage in 2024;

 Convert Bridger Power Plant (“Bridger”) units 1 and 2 from coal to natural
gas by summer 2024;

 Add 95 MW of cost-effective EE between 2024 and 2028;

 Explore a 5 MW long-duration storage pilot project between 2024 and 2028;

 Add 200 MW of solar in 2025;

 Add 227 MW of four-hour storage in 2025;

 Install cost-effective distribution-connected storage between 2025 and
2028;

 Bring B2H online in summer 2026;

 Convert North Valmy Generating Station (“Valmy”) units 1 and 2 from coal
to natural gas by summer 2026;

 If economic, acquire up to 1,425 MW of combined wind and solar, or other
economic resources between 2026 and 2028;

 Include 14 MW of capacity associated with the Western Resource
Adequacy Program (“WRAP”) in 2027; and

 Bring the first phase of GWW online (Midpoint–Hemingway #2 500 kilovolt
(“kV”) line, Midpoint–Cedar Hill 500 kV line, and Mayfield substation) in
2028.

7. The complete 2023 IRP consists of four separate documents: (1) the 2023
Integrated Resource Plan; (2) Appendix A—Sales and Load Forecast; (3) Appendix B—
Demand-Side Management Annual Report; and (4) Appendix C—Technical Report. In
prior IRP cycles, Idaho Power developed a separate Appendix D—Transmission

APPLICATION - 5
Supplement. For the 2023 IRP, the information once contained in this supplement with
respect to transmission resources (including B2H) has been moved into the main IRP
report in Chapter 7–Transmission Planning. Interested parties may also request a single
printed copy of the 2023 IRP by contacting [e-mail].
II. IRP GOALS AND ASSUMPTIONS
8. The primary goals of Idaho Power’s 2023 IRP are to: (1) identify sufficient
resources to reliably serve the growing demand for energy within Idaho Power’s service
area throughout the 20-year planning period (2024-2043); (2) ensure the selected
Preferred Portfolio balances cost and risk, while including environmental considerations;
(3) give equal and balanced treatment to supply-side resources, demand-side measures,
and transmission resources; and (4) involve the public in the planning process in a
meaningful way.
9. The 2023 IRP assumes that during the 20-year planning period, Idaho
Power will continue to be responsible for acquiring resources sufficient to serve its retail
customers in its Idaho and Oregon service areas and will continue to operate as a
vertically integrated electric utility. Over the 20-year forecast period, the Company’s
peak load is expected to grow by approximately 80 MW per year, or more than 1,500
MW over the next two decades. Continued customer growth is driving demand, and the
average annual number of customers Idaho Power serves is expected to increase from
nearly 639,000 in 2024 to 855,000 by 2043.
10. To meet this demand, the AURORA model can select from a variety of
supply-side resources, including solar, wind, small modular reactor nuclear power,
geothermal, biomass, and battery and pumped hydropower storage, as well as two new

APPLICATION - 6
technology options for the 2023 IRP: green hydrogen and long-duration storage.
Additionally, the model evaluates the cost-effectiveness of converting its remaining coal-
fired generation to natural gas and assesses the impact of variability of hydroelectric
generation, which will remain the backbone of Idaho Power’s system into the future.
11. The 2023 IRP also examines demand-side management (“DSM”)
programs, which are designed to achieve prudent, cost-effective DR and EE. Idaho
Power also continues to provide customers with tools and information to help them
manage their own energy usage. The Company achieves these objectives through the
implementation and careful management of incentive programs and through outreach
and education.
12. Idaho Power’s resource planning process also evaluates transmission
capacity as a resource to serve retail customers. Transmission projects are often
regional resources, and Idaho Power coordinates transmission planning regionally as a
member of NorthernGrid. The delivery of energy, both within the Idaho Power system
and through regional transmission interconnections, is increasingly important to facilitate
efficient movement of electricity around the region and to help manage and maximize
the use of variable energy resources such as wind and solar. The timing of new
transmission projects is subject to complex permitting, siting, and regulatory
requirements and coordination with co-participants. Transmission is a vital part of the
2023 IRP, with the Preferred Portfolio including B2H as well as three segments of GWW.
13. The 2023 IRP also models Idaho Power’s participation in WRAP, a regional
planning and capacity program that allows for sharing of available resources if a
participant experiences a short-term period of resource deficiency. The goal of this

APPLICATION - 7
program is to maintain reliability across all participants’ systems over the course of an
operating season in which some participants may experience peak load conditions or
extreme weather events and, due to circumstances beyond their control, may need
additional support to meet demand.
14. Finally, Idaho Power engages with public stakeholders when developing its
IRP. To incorporate stakeholder and public input, the Company worked with the
Integrated Resource Plan Advisory Council (“IRPAC”), comprising members of the
environmental community, major industrial customers, agricultural interests,
representatives from both this Commission and the Public Utility Commission of Oregon
(“OPUC"), representatives from the Idaho Governor’s Office of Energy and Mineral
Resources, representatives from the Northwest Power and Conservation Council, and
others. Many members of the public also attended and participated in 12 IRPAC
meetings spanning the 16-month period from May 2022 through August 2023. A list of
the 2023 IRPAC members can be found in Appendix C—Technical Report.
15. The Company also developed training and educational resources on the
long-term planning process and the AURORA model, specifically. Further, the Company
maintained an online forum for stakeholders to submit questions and comments and for
the Company to provide answers available to the public. The forum allowed stakeholders
to develop their understanding of the IRP process, particularly its key inputs, which
enabled more meaningful stakeholder involvement throughout the process.
III. IRP METHODOLOGY
16. As in prior planning cycles, Idaho Power used the AURORA model to
develop portfolios for the 2023 IRP. Using AURORA’s Long-Term Capacity Expansion

APPLICATION - 8
(“LTCE”) modeling tool, resources are selected from a variety of supply- and demand-
side resource options to develop portfolios that are least-cost for a variety of alternative
future scenarios while meeting reliability criteria. The model can also select an exit from
or a conversion to natural gas for existing coal generation units, as well as build resources
based on economics absent a defined capacity need. The LTCE modeling process is
discussed in further detail in the 2023 IRP, Chapter 9—Portfolios.
17. To ensure that AURORA develops least-cost, reasonable, and defensible
portfolios, Idaho Power performed validation and verification tests to confirm the model is
operating as expected and producing the most economic portfolio under numerous
variations of resources and timing. To verify that AURORA-built resource portfolios meet
Idaho Power’s reliability requirements, the Company leveraged the Loss of Load
Expectation (“LOLE”) methodology and calculated annual capacity positions to meet a
LOLE threshold of 0.1 event-days per year. Details about the validation and verification
process can be found in the 2023 IRP, Chapter 9—Portfolios, and a discussion of the
results can be found in Chapter 10—Modeling Analysis. An in-depth discussion of the
LOLE calculation process can be found in the LOLE section of Appendix C—Technical
Report.
18. For each portfolio, Idaho Power modeled costs and benefits including:
 Construction costs;

 Fuel costs;

 Operations and Maintenance (O&M) costs;

 Transmission upgrade costs associated with interconnecting new resource
options;

 Natural gas pipeline reservation or new natural gas pipeline infrastructure

APPLICATION - 9
costs;

 Projected wholesale market purchases and sales;

 Anticipated environmental controls;

 Market value of Renewable Energy Certificates (“REC”) for REC-eligible
resources; and

 Investment/Production Tax Credits associated with qualifying generation.
19. In addition, to enhance the risk-evaluation within the IRP, the Company
worked with IRPAC to develop a variety of future scenarios. Idaho Power ultimately used
these scenarios to test whether the decisions being made within the Near-Term Action
Plan window are robust across multiple futures. The future scenarios developed in
consultation with IRPAC include:
 High Prices: High natural gas price and high price on carbon emissions;
 Low Prices: Low natural gas price and zero price on carbon emissions;
 Constrained Storage: Increased storage prices that would result from an
assumed lithium shortage;

 100% Clean by 2035: All electricity resources must be clean (non-carbon
emitting) by 2035;

 100% Clean by 2045: All electricity resources must be clean (non-carbon
emitting) by 2045;

 Additional Large Load: High customer growth scenario;
 New Forecasted PURPA1 resources: Assumes additional must-take
generating resources at set prices consistent with state and federal policy;

 Extreme Weather: Assumes more frequent extreme weather that increases
demand for electricity;

 Rapid Electrification: Assumes rapid and substantial movement of
individuals and industries to more electrified products and resources,

1 Public Utility Regulatory Policies Act of 1978 (PURPA).

APPLICATION - 10
increasing demand for electricity; and

 Load Flattening: Assumes a shift of demand for electricity from Idaho
Power’s peak hours to lower-demand hours during the day, thereby
“flattening” the visual shape of the demand for electricity across the day.

IV. UPDATES IN THE 2023 IRP
20. Two notable trends emerged in the 2023 IRP: the vital nature of added
transmission and the substantial downward trend in portfolio greenhouse gas emissions.
These trends are addressed in full in the IRP, with two transmission projects and the
Company’s emissions trajectory discussed below.
A. Boardman to Hemingway
21. Idaho Power’s 2023 IRP continues to analyze the addition of the Boardman
to Hemingway Transmission Line Project to ensure that it remains a prudent resource. In
the 2023 IRP, the Company evaluated B2H based on the Company owning 45 percent of
the project and updated cost estimates as directed by the Commission in Order No. 23-
004.
22. As part of the 2023 IRP, the Company provides an evaluation of B2H
compared to portfolios that do not include B2H, as well as several sensitivities of the
project related to the project’s cost contingency, Mid-Columbia market availability, and
project timing. The Preferred Portfolio, which includes B2H coming online in the summer
of 2026, is significantly more cost-effective than the alternative portfolio without B2H. As
shown in the table below, the Preferred Portfolio (which includes B2H) is approximately
$836 million more cost effective than the alternative portfolio (run under the same
modeling conditions) without B2H. For comparison, the 2021 IRP Preferred Portfolio with
B2H was $266 million more cost effective than the non-B2H alternative. Stated simply,

APPLICATION - 11
the inclusion of B2H in the 2023 IRP is more than three times as cost effective as the
project was in the 2021 IRP.

23. There are four primary reasons for the increased benefits associated with
B2H from the 2021 IRP to the 2023 IRP:
 Competing IRP resources have also experienced cost increase pressures.
 In the 2021 IRP, the Company modeled the termination of 510 MW of
transmission-service related revenue upon the completion of B2H. In the
2023 IRP, following discussions with the transmission customer, Idaho
Power is no longer assuming termination of this service. This change
resulted in the addition of wheeling revenue related to this service and the
adjustment of Midpoint West available transmission capacity for
determining the GWW transmission trigger levels from resource additions.

 Idaho Power’s summer load growth has accelerated in the years directly
following B2H in-service, further increasing the cost effectiveness of the
project.

 Idaho Power’s winter needs, which were not a major consideration in the
2021 IRP, have accelerated due to industrial load growth. The Company’s
B2H-related asset exchange with PacifiCorp enables 200 MW of additional
winter connectivity.

24. With respect to the timing of B2H, Idaho Power is planning for the project to
come online in summer of 2026—timing consistent with the Preferred Portfolio. A summer
of 2026 online date is only possible because of the timely receipt of Certificates of Public
Convenience and Necessity in IPUC Case No. IPC-E-23-01 and OPUC Docket No. PCN
Preferred Portfolio (with B2H) $9,746
Portfolio without B2H $10,582
Cost-Effectiveness Differential (Portfolio without B2H - Portfolio with B2H) $836
NPV Comparison of Portfolios with and without B2H ($millions)

APPLICATION - 12
5.2 These key authorizations have allowed the Company to move forward with current
activities related to securing rights-of-way and other permitting, activities for which the
Company does not control the timeline. As a result, the Company also modeled a
November 2026 online date for B2H, finding that that scenario, too, is orders of magnitude
more cost effective than the non-B2H alternative scenario.
B. GWW Phase 1
25. In the 2023 IRP, Idaho Power has identified the need for multiple GWW
phases within the 20-year planning window. The first GWW phase, which falls within the
Near-Term Action Plan window, is the Midpoint–Hemingway #2 500-kV line, Midpoint–
Cedar Hill 500-kV line, and Mayfield 500-kV substation, which will collectively relieve
Idaho Power’s constrained transmission system between the Magic Valley in south-
central Idaho and the Treasure Valley in southwestern Idaho. There were no GWW
phases identified for inclusion in the Preferred Portfolio of the 2021 IRP, but that has
changed in the 2023 IRP primarily because of the following considerations: (1) a
significant increase in Idaho Power’s near-term load forecast; and (2) continuation of tax
credits associated with wind and solar resources.
26. With respect to the first consideration, Idaho Power’s larger near-term load
forecast results in the need for more generation resources. As a result, AURORA is
selecting large amounts of cost-effective renewable resources—and GWW will be
distinctly suited to bring that electricity to load centers. Similarly, the continuation of
energy tax credits makes renewables more cost-effective in the model, thereby adding

2 In the Matter of Idaho Power Company’s Application for a Certificate of Public Convenience and
Necessity for the Boardman to Hemingway 500-kV Transmission Line, IPUC Case No. IPC-E-23-01,
Order No. 35838 (Jun. 30, 2023) and In the Matter of Idaho Power Company Petition for Certificate of
Public Convenience and Necessity, OPUC Docket No. PCN 5, Order No. 23-225 (Jun. 29, 2023).

APPLICATION - 13
more of this generation and making GWW even more necessary to enable delivery of the
additional resources.
C. Reduction in Emissions
27. Since the 2021 IRP, Idaho Power has taken significant steps toward
reducing carbon emissions. The emissions impact of these steps is discussed in the 2023
IRP, Chapter 3—Clean Energy & Climate Change, and includes the conversion of all four
Bridger units and both Valmy units from coal to natural gas operations, as well as
significant additions of clean resources, such as solar, wind, and storage. Forecasted
emissions through the IRP time horizon—as demonstrated in the graph
below—show a continued and substantial downward trend.

V. DEVELOPMENT OF THE PREFERRED PORTFOLIO
28. A fundamental goal of the IRP process is to identify an optimal, or preferred,
resource portfolio. The Preferred Portfolio identifies resource options and timing to allow
Idaho Power to continue to reliably serve customer demand, balancing cost and risk over
the 2024 to 2043 planning period.
-
1
2
3
4
5
6
7
2013 2018 2023 2028 2033 2038 2043
Total CO2 Emissions (Million Metric Tons)
Historical Emissions Forecast Emissions 10-Year Historical Trend

APPLICATION - 14
29. For the 2023 IRP, Idaho Power identified several key resources or potential
projects to evaluate in additional detail, and the Company required the model to build
portfolios both with and without each resource or project. These with and without views
help Idaho Power and interested parties understand the impacts of major decision points.
These with and without views include:
 With and without the B2H project

 With and without different phases of the GWW project

 With and without specific Valmy Unit 1 and Unit 2 natural gas conversion
assumptions

30. These portfolios were compared against each other to determine which
portfolios could be eliminated from contention, and where to focus additional portfolio
robustness testing.
31. To validate the resource selection and the robustness of the Preferred
Portfolio, the Company performed the following additional scenario and sensitivity
analyses:
 The resources selected in the Near-Term Action Plan window of the
Preferred Portfolio were compared to optimal resources selected for the
identified future scenarios to determine the changes that would need to be
made in each of those scenarios.

 Validation and verification studies were performed to test Bridger and Valmy
unit natural gas conversions, Valmy natural gas conversion dates, and both
supply-side and demand-side resources.

32. Based on comprehensive analysis, Idaho Power selected its Preferred
Portfolio, which is identified in the 2023 IRP as “Valmy 1 & 2”, referring to the portfolio’s
conversion of both Valmy units from coal to natural gas. This Preferred Portfolio, which
includes B2H in the summer of 2026, is the least-cost, least-risk option that incorporates

APPLICATION - 15
positive changes toward clean, low-cost resources without compromising system
reliability.
VI. ACTION PLAN (2024-2028)
33. The Near-Term Action Plan for the 2023 IRP reflects near-term actionable
items of the Preferred Portfolio necessary to successfully position Idaho Power to provide
reliable, economic, and environmentally sound service to our customers into the future.
To reduce confusion around near-term actions in the 2023 IRP, Idaho Power has
developed two separate groups of actions. The first group includes actions that Idaho
Power will take in the future, but to which the Company is already committed prior to
review of the 2023 IRP. Idaho Power is not requesting acknowledgment of the items in
this group. The second group includes actions to which the Company has not yet
committed and for which the Company is seeking acknowledgment in this 2023 IRP.
Actions Taken Prior to the 2023 IRP—Not for Regulatory Acknowledgment
 100 MW of solar and 96 MW of four-hour storage added in 2024 (resources
selected through Requests for Proposals [RFP])3

 Conversion of Bridger units 1 and 2 from coal to natural gas by summer 2024
(conversions scheduled to occur by summer of 2024)
 95 MW of additional cost-effective EE between 2024 and 2028 (added EE
identified in Idaho Power’s 2022 Energy Efficiency Potential Study)

3 In the Matter of Idaho Power Company’s Application for a Certificate of Public Convenience and
Necessity to Acquire Resources to be Online by 2024 and for Approval of a Power Purchase Agreement
with Franklin Solar LLC, Case No. IPC-E-23-05, IPUC Order No. 35900 (Aug. 23, 2023); In the Matter of
Idaho Power Company’s Application for a Certificate of Public Convenience and Necessity to Acquire
Resources to be Online in Both 2024 and 2025 and for Approval of an Energy Storage Agreement with
Kuna BESS LLC, Case No. IPC-E-23-20 (filed May 26, 2023); Idaho Power Company’s Notices of
Exception to Competitive Bidding Requirements under OAR 860-089-0100, UM 2255 (filed Feb. 17, 2023
and May 26, 2023).

APPLICATION - 16
 200 MW of solar added in 2025 (executed contract for clean energy customer
resource)4
 227 MW of four-hour storage added in 2025 (resources selected from the 2022
RFP)5
2023 IRP Decisions for Acknowledgment
 B2H online by summer 2026
 Continue exploring Idaho Power’s potential participation in the SWIP-N project
 Install cost-effective distribution-connected storage from 2025 through 2028
 Convert Valmy units 1 and 2 from coal to natural gas by summer 2026
 If economic, acquire up to 1,425 MW of combined wind and solar, or other
economic resources, in 2026 through 2028 (inclusive of 625 MW of forecast
Clean Energy Your Way resources)6
 Explore a 5 MW long-duration storage pilot project
 Include 14 MW of capacity associated with WRAP
 Midpoint–Hemingway #2 500 kV, Midpoint–Cedar Hill 500 kV, and Mayfield 500
kV substation (GWW Phase 1) online by end-of-year 2028
34. Below is a chronological listing of the 2023 IRP’s Action Plan items through
2028:
Near-Term Action Plan (2024–2028)
Year Action
2023–2024 Continue exploring potential participation in the SWIP-N project
2024 Add 100 MW of solar and 96 MW of four-hour storage
Summer 2024 Convert Bridger units 1 and 2 from coal to natural gas
2024-2028 Add 95 MW of cost-effective EE between 2024 and 2028
2024-2028 Explore a 5 MW long-duration storage pilot project

4 In the Matter of Idaho Power Company's Application for Approval of a Power Purchase Agreement with
Pleasant Valley Solar, LLC, Case No. IPC-E-22-29, IPUC Order No. 35739 (Apr. 12, 2023); In the Matter
of Idaho Power Company Application for Waiver of Competitive Bidding Rules, UM 2226, OPUC Order
No. 22-082 (Mar. 11, 2022).
5 In the Matter of Idaho Power Company’s Application for a Certificate of Public Convenience and
Necessity to Acquire Resources to be Online in Both 2024 and 2025 and for Approval of an Energy
Storage Agreement with Kuna BESS LLC, Case No. IPC-E-23-20 (filed May 26, 2023); Idaho Power
Company’s Notice of Exception under OAR 860-089-0100, UM 2255 (filed May 26, 2023).
6 In the Matter of Idaho Power Company Application for Approval of 2026 All-Source Request for
Proposals to Meet 2026 Capacity Resource Need, UM 2255 (filed Sep. 15, 2022).

APPLICATION - 17
Year Action
2025 Add 200 MW of solar
2025 Add 227 MW of four-hour storage
2025-2028 Install cost effective distribution-connected storage
Summer 2026 Bring B2H online
Summer 2026 Convert Valmy units 1 and 2 from coal to natural gas
2026-2028
If economic, acquire up to 1,425 MW of combined wind and solar, or other economic
resources
2027 Include 14 MW of capacity associated with the Western Resource Adequacy Program
2028
Bring the first phase of Gateway West online (Midpoint–Hemingway #2 500 kV line,
Midpoint–Cedar Hill 500 kV line, and Mayfield substation)

VII. 2021 IRP FEEDBACK INCORPORATED INTO THE 2023 IRP
35. During the Idaho Commission and stakeholder review of the 2021 IRP,
Idaho Power received recommendations and committed to provide additional analysis
and/or discussion of several issues in its 2023 IRP.7 The fulfillment of key commitments
is discussed below.
36. Regarding the 2021 IRP’s Action Plan, Commission Staff (“Staff”)
recommended that Idaho Power develop a Bridger exit agreement with PacifiCorp that
determines potential costs of extending or exiting operations early similar to the exit
agreement developed for the closure of Valmy and incorporate those costs into its coal
plant exit costs to properly value different exit dates in its 2023 IRP.8 In Chapter 5—
Future Supply-Side Generation and Storage Resources of the 2023 IRP, Idaho Power
discusses its plans with PacifiCorp to convert Bridger Units 1 and 2 to natural gas
operation in 2024. Coordination with PacifiCorp has led to a scheduled exit date of 2037

7 In the Matter of Idaho Power Company’s 2021 Integrated Resource Plan, Case No. IPC-E-21-43, Order
No. 35603 (Nov. 18, 2022).
8 Case No. IPC-E-21-43, Staff Comments at 17, Order No. 35603 at 4.

APPLICATION - 18
for Bridger Units 1 and 2. Additionally, Idaho Power discusses updates to its plans with
PacifiCorp regarding Bridger Units 3 and 4 conversion/exit dates.
37. Additionally, Staff stated its belief that in the 2023 IRP Idaho Power should
incorporate extreme weather events and variability of water availability through its load
and resource input assumptions, rather than compensating by changing the LOLE
reliability target, which should be set as a matter of public policy.9 In Chapter 8—Planning
Period Forecasts of the 2023 IRP, Idaho Power discusses its 70th percentile load forecast
and how it accounts for load variability due to weather events. A more detailed discussion
of Idaho Power’s weather-based probabilistic scenarios and seasonal peaks is included
in Appendix A—Sales and Load Forecast. In the Loss of Load Expectation section of
Appendix C—Technical Report, Idaho Power also discusses its utilization of a 0.1 event-
days per year LOLE threshold for the 2023 IRP.
38. In its Comments that evaluated the 2021 IRP, Staff argued that Idaho Power
should only include market access backed by firm transmission reservations in its Load
and Resource Balance.10 While noting that the 2021 IRP only included firm transmission
with a corresponding third-party transmission reservation to market hubs, Idaho Power
agreed and describes the existing transmission modeled in the 2023 IRP that provides
transmission capacity for firm market imports in the Existing Transmission Capacity for
Firm Market Imports section of Chapter 7—Transmission Planning.
39. Expressing concern that its LOLE method might not provide a robust
reliability measurement, Staff recommended that Idaho Power evaluate the risks and

9 Case No. IPC-E-21-43, Staff Comments at 9, Order No. 35603 at 4.
10 Case No. IPC-E-21-43, Staff Comments at 4, Idaho Power Reply Comments at 8-9, Order No. 35603
at 4.

APPLICATION - 19
inaccuracies caused by using a single benchmark year (2023) to determine the LOLE-
based Planning Reserve Margin.11 In the Capacity Planning Reserve Margin section of
Chapter 9—Portfolios, Idaho Power explains the implementation of LOLE-based
seasonal Planning Reserve Margin calculations performed at different points along the
planning horizon for utilization in the AURORA LTCE model. Additional information
regarding the LOLE methodology can be found in the Loss of Load Expectation section
of Appendix C—Technical Report.
40. Staff also recommended that Idaho Power provide a comprehensive quality
assurance plan in its 2023 IRP to verify and validate its models by describing the purpose
of each test, how the test was conducted, and the result.12 Idaho Power agreed and
provides details regarding its verification tests and overall validation and verification
process in Chapter 9—Portfolios with resource buildouts located in Appendix C—
Technical Report. Additionally, in Chapter 10—Modeling Analysis, Idaho Power provides
a qualitative risk analysis and comparison for different portfolio buildouts analyzed in the
2023 IRP.
41. Perceiving a lack of risk mitigation and flexibility strategies in the 2021 IRP,
Staff recommended Idaho Power study the costs and benefits of implementing a flexible
resource strategy in its next IRP.13 In Chapter 11—Preferred Portfolio and Near-Term
Action Plan, Idaho Power describes the flexible resource strategy identified in the

11 Case No. IPC-E-21-43, Staff Comments at 6, Idaho Power Reply Comments at 8, Order No. 35603 at
4.
12 Case No. IPC-E-21-43, Staff Comments at 14, Idaho Power Reply Comments at 9-10, Order No. 35603
at 4.
13 Case No. IPC-E-21-43, Staff Comments at 6 and 27, Idaho Power Reply Comments at 16-17, Order
No. 35603 at 4.

APPLICATION - 20
Preferred Portfolio and compares the costs and benefits of the Preferred Portfolio to
varying future scenarios analyzed in the 2023 IRP.
42. Finally, the Commission, in Order No. 35837, granted Idaho Power’s
request for a three-month extension to file this IRP.14 The Order included a requirement
to develop a plan for the timely delivery of the 2025 IRP. Idaho Power met this
requirement at the end of Chapter 11—Preferred Portfolio and Near-Term Action Plan, in
which the Company provides a breakdown of actions and activities that will culminate in
a June 2025 filing of the 2025 IRP.
43. A table showing a discussion of the Company’s Idaho commitments and
compliance is attached as Attachment 2.
VIII. COMMUNICATIONS AND SERVICE OF PLEADINGS
44. Idaho Power requests that any notices, inquiries, and communications
regarding this request be provided to:
Lisa D. Nordstrom
Megan Goicoechea Allen
Idaho Power Company
1221 West Idaho Street (83702)
P.O. Box 70
Boise, Idaho 83707
Telephone: [phone]
Facsimile: [phone]
[e-mail]
[e-mail]
[e-mail]
Timothy E. Tatum
Alison Williams
Idaho Power Company
1221 West Idaho Street (83702)
P.O. Box 70
Boise, Idaho 83707
Telephone: [phone]
Facsimile: [phone]
[e-mail]
[e-mail]

14 In the Matter of Idaho Power’s Petition to Extend the Filing Date of Its 2023 Integrated Resource Plan,
Case No. IPC-E-23-17, Order No. 35837 at 2 (Jun. 30, 2023).

APPLICATION - 21
IX. REQUEST FOR ACKNOWLEDGMENT
45. Idaho Power respectfully requests that the Commission issue its order
acknowledging the Company’s 2023 IRP and finding that the 2023 IRP meets both the
procedural and substantive requirements of Commission Order No. 22299.
DATED at Boise, Idaho, this 29th day of September 2023.

LISA D. NORDSTROM
Attorney for Idaho Power Company
BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-23-23

IDAHO POWER COMPANY

ATTACHMENT 1

2023 INTEGRATED RESOURCE PLAN
IRP
INTEGRATED RESOURCE PLAN
September 2023
Printed on recycled paper
SAFE HARBOR STATEMENT
This document may contain forward-looking statements,
and it is important to note that the future results could
differ materially from those discussed. A full discussion
of the factors that could cause future results to differ
materially can be found in Idaho Power’s filings with the
Securities and Exchange Commission.
Table of Contents
2023 Integrated Resource Plan Page i
TABLE OF CONTENTS
Glossary of Acronyms ...................................................................................................................... x
Executive Summary ......................................................................................................................... 1
Introduction .............................................................................................................................. 1
IRP Methodology Improvements .............................................................................................. 2
Portfolio Analysis Overview ...................................................................................................... 4
2023 Preferred Portfolio ........................................................................................................... 5
Preferred Portfolio Changes from the 2021 IRP ....................................................................... 6
Near-Term Action Plan (2024–2028) ........................................................................................ 7
Actions Committed to Prior to the 2023 IRP—Not for
Regulatory Acknowledgment .............................................................................................. 8
2023 IRP Decisions for Acknowledgment ........................................................................... 8
Valmy Unit Conversions and Exits ............................................................................................ 9
Bridger Unit Conversions and Exits ......................................................................................... 10
Boardman to Hemingway ....................................................................................................... 11
Gateway West Phase 1 ........................................................................................................... 12
Southwest Intertie Project-North ........................................................................................... 13
Historical and Forecasted Emissions ....................................................................................... 14
1. Background ............................................................................................................................. 15
Integrated Resource Plan ........................................................................................................ 15
Public Advisory Process........................................................................................................... 16
IRP Methodology .................................................................................................................... 16
Cost ............................................................................................................................... 17
Risk ............................................................................................................................... 17
Modeling ........................................................................................................................... 18
Validation and Verification ............................................................................................... 18
Reliability ........................................................................................................................... 18
Energy Risk Management Policy ............................................................................................. 19
2. Political, Regulatory, and Operational Considerations ........................................................... 20
Federal Policy & Activities ....................................................................................................... 20
Hydroelectric Relicensing.................................................................................................. 20
Table of Contents
Page ii 2023 Integrated Resource Plan
Recent Executive Orders ................................................................................................... 22
Inflation Reduction Act ..................................................................................................... 22
Clean Power Plan .............................................................................................................. 23
Cross-State Air Pollution Rule ........................................................................................... 23
Wyoming Round 1 Regional Haze Compliance ................................................................. 23
Public Utility Regulatory Policies Act ................................................................................ 24
Idaho Policy & Activities.......................................................................................................... 24
Idaho Strategic Energy Alliance ........................................................................................ 24
Idaho Energy Landscape ................................................................................................... 25
Idaho Water Issues ........................................................................................................... 26
Oregon Policy & Activities ....................................................................................................... 29
State of Oregon 2022 Biennial Energy Report .................................................................. 29
Oregon Renewable Portfolio Standard and Emissions Reduction Requirements ............ 29
Oregon Community Solar Program ................................................................................... 30
Regional Policies & Activities .................................................................................................. 30
Western Resource Adequacy Program ............................................................................. 30
3. Clean Energy & Climate Change ............................................................................................. 33
Climate Change Mitigation ..................................................................................................... 33
A Cleaner Energy Mix ........................................................................................................ 33
Our Clean Energy Goal—Clean Today. Cleaner Tomorrow.® ........................................... 34
Clean Energy Your Way ..................................................................................................... 34
Idaho Power Carbon Emissions ........................................................................................ 36
Climate Change Adaptation .................................................................................................... 37
Risk Identification and Management ...................................................................................... 37
Weather Risk ..................................................................................................................... 38
Wildfire Risk ...................................................................................................................... 38
Water and Hydropower Generation Risk ......................................................................... 40
Policy Risk .......................................................................................................................... 40
Modeling Climate Risks in the IRP .......................................................................................... 41
4. Idaho Power Today ................................................................................................................. 43
Customer Load and Growth .................................................................................................... 43
Table of Contents
2023 Integrated Resource Plan Page iii
2022 Energy Sources ............................................................................................................... 44
Existing Supply-Side Resources ............................................................................................... 45
Hydroelectric Facilities ...................................................................................................... 46
Coal Facilities..................................................................................................................... 50
Natural Gas Facilities and Diesel Units ............................................................................. 50
Battery Energy Storage Systems ....................................................................................... 51
Customer Generation Service ........................................................................................... 52
Public Utility Regulatory Policies Act ................................................................................ 53
Non-PURPA Power Purchase Agreements ........................................................................ 53
Power Market Purchases and Sales .................................................................................. 55
5. Future Supply-Side Generation and Storage Resources ......................................................... 56
Generation Resources ............................................................................................................. 56
Resource Contribution to Peak ............................................................................................... 56
Renewable Resources ............................................................................................................. 57
Hydroelectric ..................................................................................................................... 57
Solar ............................................................................................................................... 57
Targeted Grid Storage ....................................................................................................... 57
Geothermal ....................................................................................................................... 58
Wind ............................................................................................................................... 58
Biomass ............................................................................................................................. 58
Thermal Resources .................................................................................................................. 59
Natural Gas Resources ...................................................................................................... 59
Nuclear Resources ............................................................................................................ 63
Coal Resources .................................................................................................................. 63
Storage Resources ................................................................................................................... 64
Battery Storage ................................................................................................................. 64
Pumped Hydro Storage ..................................................................................................... 64
Multi-Day Storage ............................................................................................................. 65
6. Demand-Side Resources ......................................................................................................... 66
Demand-Side Management Program Overview ..................................................................... 66
Energy Efficiency Forecasting—Energy Efficiency Potential Assessment .............................. 66
Table of Contents
Page iv 2023 Integrated Resource Plan
Energy Efficiency Modeling ..................................................................................................... 67
Technically Achievable Supply Curve Bundling ................................................................. 67
DSM Program Performance and Reliability ............................................................................ 68
Energy Efficiency Performance ......................................................................................... 68
Energy Efficiency Performance ......................................................................................... 69
Demand Response Performance ...................................................................................... 69
Demand Response Resource Potential ................................................................................... 70
T&D Deferral Benefits ............................................................................................................. 71
Energy Efficiency ............................................................................................................... 71
Distribution System Planning .................................................................................................. 72
7. Transmission Planning ............................................................................................................ 74
Past and Present Transmission ............................................................................................... 74
Transmission Planning Process ............................................................................................... 75
Local Transmission Planning ............................................................................................. 75
Regional Transmission Planning ....................................................................................... 76
Existing Transmission System ................................................................................................. 76
Idaho to Northwest Path .................................................................................................. 77
Brownlee East Path ........................................................................................................... 78
Idaho–Montana Path ........................................................................................................ 78
Borah West Path ............................................................................................................... 78
Midpoint West Path .......................................................................................................... 79
Idaho–Nevada Path ........................................................................................................... 79
Idaho–Wyoming Path ....................................................................................................... 79
Idaho–Utah Path ............................................................................................................... 79
Existing Transmission Capacity for Firm Market Imports ....................................................... 80
Idaho to Northwest and Idaho-Montana Path Firm Market Imports .............................. 80
Boardman to Hemingway ....................................................................................................... 83
B2H Value .......................................................................................................................... 84
Project Participants ........................................................................................................... 85
B2H Related Asset Exchange—Four Corners Capacity ..................................................... 86
Permitting Update ............................................................................................................ 86
Table of Contents
2023 Integrated Resource Plan Page v
Construction Update Next Steps ...................................................................................... 88
B2H Modeling in the IRP ................................................................................................... 88
B2H Cost Treatment in the IRP ......................................................................................... 89
Gateway West ......................................................................................................................... 89
Gateway West—Segment 8 and Mayfield Substation ..................................................... 92
Gateway West—Segment 9 and Cedar Hills Substation .................................................. 92
Gateway West—Segment 10 ............................................................................................ 92
Gateway West Cost Treatment and Modeling in the 2023 IRP ........................................ 93
Southwest Intertie Project-North ........................................................................................... 94
Southwest Market Opportunity ........................................................................................ 95
Federal Funding Opportunities for Transmission ................................................................... 96
Transmission Assumptions in the IRP Portfolios .................................................................... 97
8. Planning Period Forecasts ....................................................................................................... 99
Load Forecast .......................................................................................................................... 99
Weather Effects .............................................................................................................. 101
Economic Effects ............................................................................................................. 101
Average-Energy Load Forecast ....................................................................................... 102
Peak-Hour Load Forecast ................................................................................................ 104
Additional Firm Load ....................................................................................................... 106
Generation Forecast for Existing Resources ......................................................................... 108
Hydroelectric Resources ................................................................................................. 108
Natural Gas Resources .................................................................................................... 110
Natural Gas Price Forecast .................................................................................................... 110
Natural Gas Transport ........................................................................................................... 112
Natural Gas Storage Facilities ............................................................................................... 112
Analysis of IRP Resources ...................................................................................................... 113
Resource Costs—IRP Resources ...................................................................................... 113
LCOC—IRP Resources ...................................................................................................... 114
LCOE—IRP Resources ...................................................................................................... 115
Resource Attributes—IRP Resources .............................................................................. 116
9. Portfolios ............................................................................................................................. 119
Table of Contents
Page vi 2023 Integrated Resource Plan
Capacity Expansion Modeling ............................................................................................... 119
Capacity Planning Reserve Margin ....................................................................................... 120
Regulation Reserves .............................................................................................................. 122
Portfolio Design Overview .................................................................................................... 123
Portfolio Naming Conventions ........................................................................................ 124
Future Scenarios—Purpose: Risk Evaluation .................................................................. 126
Model Validation and Verification .................................................................................. 129
New Resource Selections ................................................................................................ 131
B2H Timing ...................................................................................................................... 132
Natural Gas Price Variation Portfolios .................................................................................. 132
Carbon Price Variation Portfolios ......................................................................................... 132
10. Modeling Analysis ................................................................................................................. 135
Portfolio Cost Analysis and Results ....................................................................................... 135
Portfolio Emission Results ............................................................................................... 137
Qualitative Risk Analysis ....................................................................................................... 140
Major Qualitative Risks ................................................................................................... 140
Stochastic Risk Analysis ......................................................................................................... 142
Loss of Load Expectation Based Reliability Evaluation of Portfolios .................................... 143
Annual Capacity Positions of the Preferred Portfolio ..................................................... 144
11. Preferred Portfolio and Near-Term Action Plan ................................................................... 145
Preferred Portfolio ................................................................................................................ 145
Preferred Portfolio Compared to Varying Future Scenarios ................................................ 148
Near-Term Action Plan (2024–2028) .................................................................................... 172
Actions Committed to Prior to the 2023 IRP–Not for Regulatory Acknowledgment ..... 172
2023 IRP Decisions for Acknowledgment ....................................................................... 172
Resource Procurement ......................................................................................................... 173
Annual Capacity Positions Replace Traditional Load and Resource Balance ................. 173
2025 IRP Filing Schedule ....................................................................................................... 175
Conclusion ............................................................................................................................. 176

Table of Contents
2023 Integrated Resource Plan Page vii
LIST OF TABLES
Table 1.1 Preferred Portfolio additions and coal exits (MW) ................................................. 6
Table 1.2 2023 IRP comparison to the 2021 IRP .................................................................... 7
Table 1.3 Near-Term Action Plan (2024–2028) ...................................................................... 9
Table 1.4 Historical and forecasted emissions ..................................................................... 14
Table 4.1 Historical load and customer data ........................................................................ 44
Table 4.2 Existing resources ................................................................................................. 45
Table 4.3 Customer generation service customer count as of August 2023 ....................... 52
Table 4.4 Customer generation service generation capacity (MW) as of August 2023 ....... 52
Table 5.1 Targeted grid storage projects .............................................................................. 57
Table 6.1 Energy efficiency bundles average annual resource potential and average
levelized cost ......................................................................................................... 68
Table 6.2 Total energy efficiency portfolio cost-effectiveness summary, 2022
program performance........................................................................................... 69
Table 6.3 2022 demand response program capacity ........................................................... 70
Table 7.1 Transmission import capacity ............................................................................... 80
Table 7.2 Pacific Northwest to Idaho Power west-to-east transmission capacity ............... 80
Table 7.3 The Idaho to Northwest Path (WECC Path 14) summer allocation ...................... 81
Table 7.4 Third-party secured import transmission capacity for
existing transmission ............................................................................................ 82
Table 7.5 B2H capacity allocation ......................................................................................... 85
Table 7.6 List of transmission entities at Four Corners and Mona....................................... 86
Table 7.7 Gateway West phase modeling ............................................................................ 94
Table 7.8 Transmission assumptions and requirements ...................................................... 98
Table 8.1 Load forecast—average monthly energy (aMW) ............................................... 104
Table 8.2 Load forecast—peak hour (MW) ........................................................................ 106
Table 8.3 Levelized cost of capacity (fixed) in 2024 dollars per kW per month................. 114
Table 8.4 Levelized cost of energy (at stated capacity factors) in 2024 dollars ................. 116
Table 8.5 Resource attributes ............................................................................................. 117
Table 9.1 Regulation reserve requirements—percentage of hourly load MW,
wind MW, and solar MW .................................................................................... 123
Table 9.2. Planning conditions table ................................................................................... 125
Table of Contents
Page viii 2023 Integrated Resource Plan
Table 9.3 High Gas High Carbon table ................................................................................ 126
Table 9.4 Low Gas Zero Carbon table ................................................................................. 127
Table 10.1 Financial assumptions ......................................................................................... 135
Table 10.2 2023 IRP main cases ............................................................................................ 136
Table 10.3 2023 IRP sensitivities .......................................................................................... 137
Table 10.4 2023 IRP validation and verification tests .......................................................... 137
Table 10.5 Qualitative risk comparison ................................................................................ 142
Table 10.6 Preferred Portfolio annual capacity positions (MW) .......................................... 144
Table 11.1 Preferred Portfolio resource selections .............................................................. 146
Table 11.2 Preferred Portfolio—High Gas High Carbon comparison table .......................... 149
Table 11.3 Preferred Portfolio—Low Gas Zero Carbon comparison table ........................... 151
Table 11.4 Preferred Portfolio—Constrained Storage comparison table ............................ 153
Table 11.5 Preferred Portfolio—100% Clean by 2035 comparison table ............................ 155
Table 11.6 Preferred Portfolio—100% Clean by 2045 comparison table ............................ 157
Table 11.7 Preferred Portfolio—Additional Large Load 100 MW comparison table ........... 159
Table 11.8 Preferred Portfolio—Additional Large Load 200 MW comparison table ........... 160
Table 11.9 Preferred Portfolio—New Forecasted PURPA comparison table ....................... 163
Table 11.10 Preferred Portfolio – Extreme Weather comparison table ................................ 165
Table 11.11 Preferred Portfolio—Rapid Electrification (ASHP) comparison table................. 167
Table 11.12 Preferred Portfolio—Rapid Electrification (GSHP) comparison table ................ 168
Table 11.13 Preferred Portfolio—Load Flattening comparison table .................................... 171
Table 11.14 Near-Term Action Plan (2024–2028) .................................................................. 173
Table 11.15 Pre and post Preferred Portfolio annual capacity positions ............................... 174

LIST OF FIGURES
Figure 3.1 Idaho Power’s 2022 energy mix compared to the national average ................... 34
Figure 3.2 Estimated Idaho Power CO2 emissions ................................................................. 36
Figure 4.1 Historical load and customer data ........................................................................ 43
Figure 4.2 PURPA contracts by resource type ....................................................................... 53
Figure 6.1 Cumulative annual growth in energy efficiency compared with IRP targets ....... 68
Table of Contents
2023 Integrated Resource Plan Page ix
Figure 6.2 Historic annual demand response program performance ................................... 70
Figure 7.1 Idaho Power transmission system map ................................................................ 77
Figure 7.2 B2H route submitted in 2017 Oregon Energy Facility Siting Council
Application for Site Certificate .............................................................................. 85
Figure 7.3 Gateway West map ............................................................................................... 91
Figure 7.4 Historical Desert Southwest Summer and Winter Seasonal Peaks ...................... 96
Figure 7.5 Forecasted Desert Southwest Summer and Winter Seasonal Peaks ................... 96
Figure 8.1 Average monthly load-growth forecast (aMW).................................................. 103
Figure 8.2 Peak-hour load-growth forecast (MW) .............................................................. 105
Figure 8.3 Brownlee inflow volume historical and modeled percentiles ............................ 110
Figure 8.4 North American major gas basins ....................................................................... 111
Figure 9.1 Idaho Power’s reliability flowchart ..................................................................... 121
Figure 9.2 Analysis diagram ................................................................................................. 124
Figure 9.3 Model validation and verification tests .............................................................. 130
Figure 9.4 Carbon price forecast .......................................................................................... 134
Figure 10.1 Estimated portfolio emissions from 2021–2040 ................................................ 139
Figure 10.2 NPV stochastic probability kernel—Preferred Portfolio contenders
(likelihood by NPV [$ x 1,000])............................................................................ 143
Figure 11.1 First month of capacity shortfall ......................................................................... 175

LIST OF APPENDICES
Appendix A—Sales and Load Forecast
Appendix B—Demand-Side Management 2022 Annual Report
Appendix C—Technical Report

Glossary of Acronyms
Page x 2023 Integrated Resource Plan
GLOSSARY OF ACRONYMS
A/C—Air Conditioning
AEG—Applied Energy Group
AFUDC—Allowance for Funds Used During Construction
akW—Average Kilowatt
aMW—Average Megawatt
ASHP—Air-Source Heat Pump
ATC—Available Transfer Capacity
B2H—Boardman to Hemingway
BAA—Balancing Authority Area
BESS—Battery Energy Storage System
BLM—Bureau of Land Management
BPA—Bonneville Power Administration
CAISO—California Independent System Operator
CBM—Capacity Benefit Margin
CCCT—Combined-Cycle Combustion Turbine
CEYW—Clean Energy Your Way
cfs—Cubic Feet per Second
CHP—Combined Heat and Power
CO2—Carbon Dioxide
CPCN—Certificate of Public Convenience and Necessity
CPP—Critical Peak Pricing
CSPP—Cogeneration and Small-Power Production
CWA—Clean Water Act of 1972
DOE—Department of Energy
DPO—Draft Proposed Order
DR—Demand Response
DSM—Demand-Side Management
DSP—Distribution System Planning
EE—Energy Efficiency
EFSC—Energy Facility Siting Council
EIA—Energy Information Administration
EIM—Energy Imbalance Market
EIS—Environmental Impact Statement
ELCC—Effective Load Carrying Capability
ELR—Energy Limited Resource
EPA—Environmental Protection Agency
Glossary of Acronyms
2023 Integrated Resource Plan Page xi
ESA—Energy Service Agreement
ESPA—Eastern Snake River Plain Aquifer
ESPAM—Eastern Snake Plain Aquifer Model
FCRPS—Federal Columbia River Power System
FERC—Federal Energy Regulatory Commission
FPA—Federal Power Act of 1920
FPI—Fire Potential Index
GHG—Greenhouse Gas
GSHP—Ground-Source Heat Pump
GWMA—Ground Water Management Area
GWW—Gateway West
H2—Hydrogen
HB—House Bill
HCC—Hells Canyon Complex
INL—Idaho National Laboratory
IPCC—Intergovernmental Panel on Climate Change
IPUC—Idaho Public Utilities Commission
IRA—Inflation Reduction Act of 2022
IRP—Integrated Resource Plan
IRPAC—IRP Advisory Council
ISEA—Idaho Strategic Energy Alliance
ISO—International Standards Organization
ITC—Investment Tax Credit
IWRB—Idaho Water Resource Board
kV—Kilovolt
kW—Kilowatt
kWh—Kilowatt-Hour
LCOC—Levelized Cost of Capacity
LCOE—Levelized Cost of Energy
Li-ion—Lithium Ion
LiDAR—Light Detection and Ranging
LOLE—Loss of Load Expectation
LTCE—Long-Term Capacity Expansion
MMBtu—Million British Thermal Units
MSA—Metropolitan Statistical Area
MW—Megawatt
MWh—Megawatt-Hour
NEPA—National Environmental Policy Act of 1969
Glossary of Acronyms
Page xii 2023 Integrated Resource Plan
NOx—Nitrogen Oxide
NPV—Net Present Value
O&M—Operations and Maintenance
ODOE—Oregon Department of Energy
OPUC—Public Utility Commission of Oregon
PCA—Power Cost Adjustment
PPA—Power Purchase Agreement
PRM—Planning Reserve Margin
PTC—Production Tax Credit
PURPA—Public Utility Regulatory Policies Act of 1978
PV—Photovoltaic
QF—Qualifying Facility
RCAT—Reliability and Capacity Assessment Tool
REC—Renewable Energy Certificate
RFA—Request for Amendment
RFP—Request for Proposal
ROD—Record of Decision
ROR—Run-of-River
RPS—Renewable Portfolio Standard
SCCT—Simple-Cycle Combustion Turbine
SCR—Selective Catalytic Reduction
SIP—State Implementation Plan
SMR—Small Modular Reactor
SNOWIE—Seeded and Natural Orographic Wintertime Clouds: the Idaho Experiment
SRBA—Snake River Basin Adjudication
SWIP-N—Southwest Intertie Project-North
T&D—Transmission and Distribution
TOU—Time-of-Use
TRC—Total Resource Cost
TRM—Transmission Reliability Margin
UCT—Utility Cost Test
VER—Variable Energy Resource
WECC—Western Electricity Coordinating Council
WMP—Wildfire Mitigation Plan
WPP—Western Power Pool
WRAP—Western Resource Adequacy Program

Executive Summary
2023 Integrated Resource Plan Page 1
EXECUTIVE SUMMARY
Introduction
The 2023 Integrated Resource Plan (IRP) is Idaho Power’s 16th resource plan prepared in
accordance with regulatory requirements and guidelines established by the Idaho Public
Utilities Commission (IPUC) and the Public Utility Commission of Oregon (OPUC).
The 2023 IRP evaluates the 20-year planning period from 2024 through 2043. During this
period, Idaho Power’s demand for electricity is expected to grow significantly. Over the 20-year
forecast period, the company’s peak load is expected to grow by approximately 80 megawatts
(MW) per year, or 1,500 MW over the next two decades. Continued customer growth is driving
demand, and the average annual number of customers is expected to increase from nearly
639,000 in 2024 to 855,000 by 2043.
To meet this growing demand, the 20-year IRP includes the addition of large quantities of
cost-effective clean resources: 3,325 MW of solar, 1,800 MW of wind, 1,453 MW of battery
storage, 360 MW of energy efficiency, 340 MW of peaking hydrogen, 160 MW of incremental
demand response, and 30 MW of geothermal. The 2023 IRP also identifies the conversion of
coal-fired generation units to natural gas, including Valmy units 1 and 2 and Bridger units 3 and
4. These conversions are cost-effective, ensure future reliability, and result in significant
reductions in the company’s forecasted carbon dioxide (CO2) emissions. With these
conversions, the company’s operations will be free from coal-fired generation beginning
in 2030.
Energy experts, engineers, and system operators generally agree that new, high-voltage
transmission systems are necessary for a reliable energy future. “New and upgraded
transmission lines deliver electricity to where it’s needed, whether that means delivering wind
and solar power to towns and cities across the country or moving power from one region to
another that needs it in the face of storms, heat waves, or extreme weather.”1 Consistent with
this recent statement and Idaho Power’s own IRP analysis dating back to 2009, the 2023 IRP
includes transmission as a cost-effective way to integrate renewables and facilitate regional
energy exchange. Specifically, the IRP includes the Boardman to Hemingway (B2H) 500-kilovolt
(kV) transmission line in 2026 to connect the Pacific Northwest and Idaho; and three Gateway
West (GWW) transmission phases spread across the 20-year plan to connect the Magic Valley
and Treasure Valley, with the first phase (Midpoint–Hemingway #2 500-kV line, Midpoint–
Cedar Hill 500-kV line, and Mayfield substation) modeled with an online date of late 2028.
The company has also identified potential value associated with the addition of the Southwest

1 whitehouse.gov/briefing-room/statements-releases/2022/11/18/fact-sheet-the-biden-harris-administration-
advances-transmission-buildout-to-deliver-affordable-clean-electricity/.
Executive Summary
Page 2 2023 Integrated Resource Plan
Intertie Project-North (SWIP-N) transmission line. The 500-kV SWIP-N line would run between
Idaho and Nevada, with connectivity to the Las Vegas area. Idaho Power’s potential
involvement in the project remains uncertain and, therefore, the SWIP-N project is not included
in the Preferred Portfolio of this IRP.
The IRP is a 20-year plan, prepared biennially, which has historically allowed Idaho Power to
timely update its long-term resource plan based on changing circumstances. However,
balancing load and resources has become increasingly more dynamic as major planning inputs
and assumptions are subject to change in real-time. These long-term planning challenges are
not unique to Idaho Power; however, several individual uncertainties in this planning cycle are
specific to Idaho Power. Due to the increased level of uncertainty surrounding several
important near-term decisions, the 2023 IRP has been prepared in a manner intended to
provide the flexibility and adaptability necessary to inform decisions as more information
becomes known before the next planning cycle. A few examples include load growth, the timing
of the B2H transmission line in-service date, and Idaho Power’s potential involvement in the
SWIP-N project. These, and other planning scenarios, are discussed in greater detail throughout
this planning document.
IRP Methodology Improvements
The primary goal of the long-term resource planning process is to ensure Idaho Power’s system
has sufficient resources to reliably serve customer demand and flexible capacity needs. In each
IRP, the company models resource needs over a 20-year planning period with the primary
objective of minimizing costs and risks to customers.
As in prior planning cycles, Idaho Power used Energy Exemplar’s AURORA model for the
2023 IRP. Using AURORA’s Long-Term Capacity Expansion (LTCE) modeling tool, resources are
selected from a variety of supply- and demand-side resource options to develop portfolios
that are least-cost for a variety of alternative future scenarios while meeting reliability criteria.
The model can also select an exit from or a conversion to natural gas for existing coal
generation units, as well as build resources based on economics absent a defined capacity
need. The LTCE modeling process is discussed in further detail in Chapter 9—Portfolios.
To ensure that AURORA develops least-cost, reasonable, and defensible portfolios, Idaho Power
performed validation and verification tests to confirm the model is operating as expected and
producing the most economic portfolio under numerous variations of resources and timing.
To verify that AURORA-built resource portfolios meet Idaho Power’s reliability requirements,
the company leveraged the Loss of Load Expectation (LOLE) methodology and calculated annual
capacity positions to meet a LOLE threshold of 0.1 event-days per year.
Executive Summary
2023 Integrated Resource Plan Page 3
Details about the validation and verification process can be found in Chapter 9—Portfolios,
and a discussion of the results can be found in Chapter 10—Modeling Analysis. An in-depth
discussion of the LOLE calculation process can be found in the Loss of Load Expectation section
of Appendix C—Technical Report.
For each portfolio, Idaho Power modeled costs and benefits including:
• Construction costs
• Fuel costs
• Operations and Maintenance (O&M) costs
• Transmission upgrade costs associated with interconnecting new resource options
• Natural gas pipeline reservation and new natural gas pipeline infrastructure costs
• Projected wholesale market purchases and sales
• Anticipated environmental controls
• Market value of Renewable Energy Certificates (REC) for REC-eligible resources
• Investment/Production Tax Credits (ITC/PTC) associated with qualifying generation
Additionally, to enhance the risk evaluation within the 2023 IRP, the company worked with the
IRP Advisory Council (IRPAC) to develop a variety of scenarios that build portfolios based on
several hypothetical versions of the future. Some of the hypothetical futures align with
Idaho Power’s near- and long-term objectives, making the associated scenario portfolios a good
point of comparison to the final Preferred Portfolio. Specifically, the company used the scenario
results to confirm that decisions identified in the Near-Term Action Plan window (2024–2028)
are robust and reliable across different futures. The future scenarios developed with
IRPAC include:
• High Prices: High natural gas price and high price on carbon emissions
• Low Prices: Low natural gas price and zero price on carbon emissions
• Constrained Storage: Increased battery storage prices that would result from an
assumed lithium shortage
• 100% Clean by 2035: All electricity resources must be clean (non-carbon emitting)
by 2035
• 100% Clean by 2045: All electricity resources must be clean (non-carbon emitting)
by 2045
• Additional Large Load: High customer growth scenario
Executive Summary
Page 4 2023 Integrated Resource Plan
• New Forecasted PURPA2 Resources: Assumes additional must-take generating resources
at set prices consistent with state and federal policy
• Extreme Weather: Assumes more frequent extreme weather that increases demand
for electricity
• Rapid Electrification: Assumes rapid and substantial movement of individuals and
industries to more electrified products and resources, increasing demand for electricity
• Load Flattening: Assumes a shift of demand for electricity from Idaho Power’s peak
hours to lower-demand hours during the day, thereby “flattening” the visual shape of
the demand for electricity across the day
Portfolio Analysis Overview
The AURORA model selects resources based on set criteria—primarily, resources that most
cost-effectively meet future demand for electricity and maintain Idaho Power’s reliability
criteria. Generally, resources in the model are “selectable,” meaning the model can pick a given
resource—such as adding solar or batteries—if doing so will help achieve the model’s objectives
of building the lowest-cost, most-reliable portfolio.3 Conversely, the model can choose not to
select resources if doing so will lead to higher costs or an unreliable portfolio that doesn’t meet
demand requirements.
Ultimately, the best portfolio—the one that meets all demand and reliability criteria—at the
best combination of least cost and least risk is selected as the Preferred Portfolio. Put simply,
the Preferred Portfolio is the best and most affordable path to meet the needs of Idaho Power’s
customers for the next 20 years, based on information known today. The Preferred Portfolio
reflects additional resources to Idaho Power’s system and, apart from identifying an exit from
certain resources, does not present the company’s current system and existing resource mix.
For the 2023 IRP, Idaho Power identified several key resources or potential projects to evaluate
in additional detail, and the company required the model to build portfolios both with and
without each resource or project. These with and without views help Idaho Power and
interested parties understand the impacts of major decision points. These with and without
views include:
• With and without the B2H project

2 Public Utility Regulatory Policies Act of 1978 (PURPA)
3 In some instances, resources are not selectable and are treated as “must take” or have conditions placed upon
them. These specific conditions are discussed in Chapter 5—Future Supply-Side Generation and Storage
Resources and Appendix C—Technical Report.
Executive Summary
2023 Integrated Resource Plan Page 5
• With and without different phases of the Gateway West project
• With and without specific Valmy Unit 1 and Unit 2 natural gas conversion
date assumptions
These portfolios were compared against each other to determine which portfolios could be
eliminated from contention, and where to focus additional portfolio robustness testing.
To validate the resource selection and robustness of the Preferred Portfolio, the company
performed additional scenario and sensitivity analyses, including the following:
• The resources selected in the Near-Term Action Plan window of the Preferred Portfolio
were compared to optimal resources selected for alternative future scenarios, identified
in conjunction with IRPAC, to determine the changes that would need to be made in
each of those scenarios.
• Validation and verification studies were performed to test coal exit dates, Bridger and
Valmy unit natural gas conversions, and both supply-side and demand-side resources.
2023 Preferred Portfolio
Idaho Power’s selected Preferred Portfolio for the 2023 IRP includes a diverse mix of generation
resources, storage, and transmission. Specifically, the Preferred Portfolio adds 3,325 MW of
solar, 1,800 MW of wind, 1,453 MW of storage (four- and eight-hour batteries, as well as
long-duration 100-hour storage), 360 MW of additional energy efficiency (EE), 340 MW of
hydrogen (H2), 160 MW of new demand response (DR), and 30 MW of geothermal.
Additionally, the Preferred Portfolio includes conversions of multiple coal-fired generation units
to natural gas, showing the company exiting coal entirely in 2030 and adding a net total of
261 MW of natural gas via coal conversions through 2043. In total, the Preferred Portfolio—
considering both additions and exits—adds 6,888 MW of resource capacity over the next
20 years. To support these resource additions, the Preferred Portfolio also includes the B2H
transmission line beginning in July 2026 and three Gateway West transmission line segments
phased in from 2029 to 2040.
Table 1.1 shows the resource additions, coal exits, as well as new transmission that make up
Idaho Power’s 2023 IRP Preferred Portfolio. Within AURORA, Idaho Power names each portfolio
with a short reference that describes a notable aspect of the portfolio. As shown in Table 1.1,
the short-hand name of the Preferred Portfolio is “Valmy 1 & 2”, referring to the portfolio’s
conversion of both Valmy units from coal to natural gas.
Executive Summary
Page 6 2023 Integrated Resource Plan
Table 1.1 Preferred Portfolio additions and coal exits (MW)
Preferred Portfolio—Valmy 1 & 2 (MW)
Year Coal Exits Gas H2 Wind Solar 4 Hr 8 Hr 100 Hr Trans. Geo DR EE Forecast
2024 -357 357 0 0 100 96 0 0 0 0 0 17
2025 0 0 0 0 200 227 0 0 0 0 0 18
2026 -134 261 0 0 100 0 0 0 Jul B2H 0 0 19
2027 0 0 0 400 375 5 0 0 0 0 0 20
2028 0 0 0 400 150 5 0 0 0 0 0 21
2029 0 0 0 400 0 5 0 0 GWW1 0 20 22
2030 -350 350 0 100 500 155 0 0 0 30 0 21
2031 0 0 0 400 400 5 0 0 GWW2 0 0 21
2032 0 0 0 100 100 205 0 0 0 0 0 20
2033 0 0 0 0 0 105 0 0 0 0 20 20
2034 0 0 0 0 0 5 0 0 0 0 40 19
2035 0 0 0 0 0 5 0 0 0 0 40 18
2036 0 0 0 0 0 5 0 0 0 0 40 17
2037 0 0 0 0 0 55 50 0 0 0 0 17
2038 0 -706 340 0 0 155 50 200 0 0 0 17
2039 0 0 0 0 0 5 50 0 0 0 0 15
2040 0 0 0 0 400 5 0 0 GWW3 0 0 14
2041 0 0 0 0 200 5 0 0 0 0 0 14
2042 0 0 0 0 200 55 0 0 0 0 0 14
2043 0 0 0 0 600 0 0 0 0 0 0 14
Sub Total 841 261 340 1,800 3,325 1,103 150 200 30 160 360
Total 6,888

Preferred Portfolio Changes from the 2021 IRP
The Preferred Portfolio of the 2023 IRP reflects movement toward clean, low-cost resources,
while maintaining focus on system reliability. Table 1.2 highlights the changes from the 2021
IRP to the 2023 IRP.
Executive Summary
2023 Integrated Resource Plan Page 7
Table 1.2 2023 IRP comparison to the 2021 IRP
2021 IRP Preferred Portfolio 2023 IRP Preferred Portfolio
The last coal generation unit exit was planned in 2028. Coal generation units have planned conversions to natural
gas with the last taking place by 2030.
Emissions gradually reduced to approximately 1.8M short
tons of CO2 by the end of the plan.
CO2 emissions fall to just over 500-k short tons by the end
of the plan—less than half the emissions as the previous IRP.
The B2H transmission line was identified as a least-cost
resource.
B2H continues to be a least-cost resource.
The plan included a conversion of Bridger coal units 1 and 2
to natural gas operation.
Bridger units 1, 2, 3, and 4 as well as Valmy units 1 and 2
are identified for a natural gas conversion.
700 MW of wind plus 1,405 MW of solar were included. 1,800 MW of wind plus 3,325 MW of solar are included.
1,685 MW of battery storage was included. 1,453 MW of storage was included, including 200 MW of
long-duration storage.
An additional 100 MW of DR was selected. An additional 160 MW of DR is selected.
A total of 440 MW of cost-effective EE was selected. A total of 360 MW of EE is selected.
GWW was not included. GWW is identified as necessary for system reliability and
to enable incremental renewables.
No new firm capacity generation resources were identified. Two hydrogen peaking units are selected in 2038 to
replace the Bridger natural gas converted units.

Importantly, the 2021 and 2023 IRPs were assessed on the same principles of minimizing cost
and risk (i.e., the least-cost, least-risk portfolio). Relative to the 2021 IRP, the 2023 IRP
Preferred Portfolio includes significantly more wind and solar resources to meet increased load
projections, driving the need for Gateway West transmission phases to facilitate the
interconnection and delivery of 1,800 MW of wind and 3,325 MW of solar.
To maintain reliability for all seasons of each year across the modeled time horizon,
the company will convert four coal units to natural gas. Valmy units 1 and 2 are identified for a
conversion in 2026, and Bridger units 3 and 4 in 2030. Idaho Power plans to be out of all coal
operations in 2030. With respect to natural gas, the only additions in the 2023 IRP stem from
coal-to-natural gas conversions.
The quantity of DR has grown considerably in the 2023 IRP, with 160 MW of incremental DR
included in the Preferred Portfolio compared to 100 MW in the 2021 IRP. Finally, cost-effective
EE measures continue to be a major part of the plan in the 2023 IRP, with a total of 360 MW of
incremental EE across the 20-year planning horizon.
Near-Term Action Plan (2024–2028)
The Near-Term Action Plan for the 2023 IRP reflects actionable items in the Preferred Portfolio
from 2024 to 2028. The Near-Term Action Plan identifies key milestones to successfully position
Idaho Power to provide reliable, economic, and environmentally conscious service to customers
Executive Summary
Page 8 2023 Integrated Resource Plan
into the future. The current regional electric market, regulatory environment, and the pace of
technological change make the 2023 Near-Term Action Plan especially relevant.
To reduce confusion around near-term actions in the 2023 IRP, Idaho Power has developed two
separate groups of actions. The first group includes actions that Idaho Power will take in the
future, but to which the company was already committed prior to review of the 2023 IRP.
The company is not requesting regulatory acknowledgment of the items in this group.
In contrast, the second group includes actions to which the company has not yet committed or
is not fully committed and for which the company is seeking regulatory acknowledgment in this
2023 IRP.
Actions Committed to Prior to the 2023 IRP—Not for
Regulatory Acknowledgment
• 100 MW of solar and 96 MW of four-hour storage added in 2024 (resources selected
through Requests for Proposals [RFP])
• Conversion of Bridger units 1 and 2 from coal to natural gas by summer 2024
(conversions scheduled to occur by summer of 2024)
• 95 MW of additional cost-effective EE between 2024 and 2028 (added EE identified in
Idaho Power’s 2022 Energy Efficiency Potential Study)
• 200 MW of solar added in 2025 (executed contract for clean energy customer resource)
• 227 MW of four-hour storage added in 2025 (resources selected from the 2024 RFP)
2023 IRP Decisions for Acknowledgment
• B2H online by summer 2026
• Continue exploring Idaho Power’s potential participation in the SWIP-N project
• Install cost-effective distribution-connected storage from 2025 through 2028
• Convert Valmy units 1 and 2 from coal to natural gas by summer 2026
• If economic, acquire up to 1,425 MW of combined wind and solar, or other economic
resources, in 2026 through 2028 (inclusive of 625 MW of forecast Clean Energy Your
Way [CEYW] resources)
• Explore a 5 MW long-duration storage pilot project
• Include 14 MW of capacity associated with the Western Resource Adequacy
Program (WRAP)
• Midpoint–Hemingway #2 500-kV, Midpoint–Cedar Hill 500-kV, and Mayfield 500-kV
substation (Gateway West Phase 1) online by end-of-year 2028
Executive Summary
2023 Integrated Resource Plan Page 9
Further discussion of resource actions in the Near-Term Action Plan window, and attributes
of the Preferred Portfolio, is included in Chapter 11—Preferred Portfolio and Action Plan.
Table 1.3 includes a chronological listing of the near-term actions.
Table 1.3 Near-Term Action Plan (2024–2028)
Year Action
2023–2024 Continue exploring potential participation in the SWIP-N project
2024 Add 100 MW of solar and 96 MW of four-hour storage
Summer 2024 Convert Bridger units 1 and 2 from coal to natural gas
2024–2028 Add 95 MW of cost-effective EE between 2024 and 2028
2024–2028 Explore a 5 MW long-duration storage pilot project
2025 Add 200 MW of solar
2025 Add 227 MW of four-hour storage
2025–2028 Install cost effective distribution-connected storage
Summer 2026 Bring B2H online
Summer 2026 Convert Valmy units 1 and 2 from coal to natural gas
2026–2028 If economic, acquire up to 1,425 MW of combined wind and solar, or other economic resources
2027 Include 14 MW of capacity associated with WRAP
2028 Bring the first phase of GWW online (Midpoint–Hemingway #2 500-kV line, Midpoint–Cedar Hill 500-kV line, and Mayfield substation)

Given the complexities and ongoing developments related to Valmy and Bridger units, B2H,
and Gateway West, an update on each is provided below. Additionally, a status update on the
SWIP-N project is also provided below.
Valmy Unit Conversions and Exits
As co-owners of the North Valmy Generating Station, NV Energy and Idaho Power aligned on
2026 as the year to evaluate the coal to gas conversion for units 1 and 2. Idaho Power owns half
of the North Valmy Generating Station. Although Idaho Power exited coal operations at Unit 1
in 2019, if Unit 1 is converted to natural gas-operation, the company would have the option to
participate in the conversion. NV Energy owns the remaining half of both units and is the
plant operator.
For the 2023 IRP, Idaho Power used AURORA’s LTCE model to determine the best Valmy
operating option specific to Idaho Power’s system subject to the following constraints:
• Allow for the exit of Unit 2 at the end of 2025 or the conversion to natural gas with SCR
in 2026.
Executive Summary
Page 10 2023 Integrated Resource Plan
• If the conversion of Unit 2 to natural gas is selected, then the conversion of Unit 1 with
SCR becomes available to the model and it can either select to remain out of Unit 1 or to
convert it to natural gas operation.
In the event that the model selects any conversion to natural gas option, the company also
evaluated early retirement dates of the converted natural gas units. The results of the LTCE
model indicate that the conversion of Valmy units 1 and 2 to natural gas in 2026 is economical
and the units will continue to economically run through the 20-year plan. To ensure the
robustness of these modeling outcomes, the company performed validation and verification
studies around the Unit 1 and Unit 2 conversion or exit determination. These validation and
verification studies are detailed in Chapter 9—Portfolios.
Bridger Unit Conversions and Exits
Idaho Power owns one-third of Bridger units 1–4, and PacifiCorp owns the remaining two-thirds
and is the plant operator. In its 2023 IRP, PacifiCorp concluded it would be cost-effective to
convert Bridger units 3 and 4 to natural gas beginning in 2030 and operate as a natural gas
plant through 2037. Idaho Power and PacifiCorp have not developed contractual terms that
would be necessary to allow for the potential earlier exit or conversion to a non-coal fuel
source by one party or both parties for units 3 and 4. Any new contractual terms may impact
costs and assumptions and, therefore, affect the specific timing of exits identified in the
2023 IRP.
For the 2023 IRP, Idaho Power used AURORA’s LTCE model to determine the best Bridger
operating option specific to Idaho Power’s system subject to the following constraints:
• Units 1 and 2—Convert to natural gas in 2024 and operate through 2037.
• Unit 3—Can exit no earlier than year-end 2025 and must either exit from coal at
year-end 2029 or convert to natural gas by summer 2030. If the unit converts to natural
gas, it operates through 2037.
• Unit 4—Can exit no earlier than year-end 2025 and must either exit from coal at year-
end 2029 or convert to natural gas by summer 2030. If the unit converts to natural gas,
it operates through 2037.
The model results indicate that the conversion of units 3 and 4 to natural gas in 2030, with
operation through 2037, is economical. To ensure the robustness of these modeling outcomes,
the company performed validation and verification studies around the unit 3 and 4 conversion
or exit determination. These validation and verification studies are detailed in Chapter 9—
Portfolios. The company will continue to evaluate whether to exit or convert Bridger units 3 and
4 to natural gas in the 2025 IRP.
Executive Summary
2023 Integrated Resource Plan Page 11
Boardman to Hemingway
Idaho Power plans to break ground on the B2H project in the fourth quarter of 2023. Since the
2021 IRP, Idaho Power has accomplished the following actions:
• Received Certificates of Public Convenience and Necessity (CPCN) from the OPUC
and IPUC.
• Received a site certificate for the project from the Oregon Energy Facility Siting Council
(EFSC), which was affirmed on appeal to the Oregon Supreme Court.
• Completed a purchase and sale transfer agreement with Bonneville Power
Administration (BPA) increasing Idaho Power’s share of the project to 45.45%.
• Executed a construction agreement with PacifiCorp.
• Executed a joint purchase and sale agreement with PacifiCorp exchanging various
assets, including Idaho Power gaining ownership of assets that provide access to the
Four Corners market hub.
Although Idaho Power has right of way grants from the Bureau of Land Management (BLM)
and the site certificate from Oregon Department of Energy (ODOE), both entities require
additional steps prior to authorizing construction. Idaho Power is working through the BLM’s
process to secure Notice To Proceed approvals and with the ODOE to obtain Pre-Construction
Compliance Determinations. Idaho Power expects these authorizations to be granted in phases
between the fourth quarter of 2023 and third quarter of 2024. Additionally, Idaho Power is in
the process of securing bids and awarding contracts for the various aspects of the project to
move into the construction phase.
In the 2023 IRP, the company evaluated a resource portfolio without B2H to determine
whether B2H remains cost-effective. This sensitivity revealed that B2H is even more
cost-effective than it was shown to be in the in the 2021 IRP.
• Preferred Portfolio (with B2H) Net Present Value (NPV)—$9,746 million
• Portfolio without B2H Portfolio NPV—$10,582 million
• B2H NPV Cost Effectiveness Differential—$836 million
Under planning conditions, the inclusion of B2H (Preferred Portfolio) is approximately
$836 million more cost effective than the portfolio run under the same conditions without the
B2H project (up from approximately a $266 million difference in the 2021 IRP). Detailed
portfolio costs can be found in Chapter 10—Modeling Analysis.
The cost-effectiveness of B2H has continued to increase even with increased pressures on
project costs. The company has included its most recent B2H estimate, updated in
Executive Summary
Page 12 2023 Integrated Resource Plan
September 2023, inclusive of a contingency amount. There are four primary reasons for the
increased benefits associated with B2H:
1. Competing IRP resources have also experienced cost increase pressures.
2. In the 2021 IRP, the company modeled the termination of 510 MW of
transmission-service-related revenue upon the completion of B2H. In the 2023 IRP,
following discussions with the transmission customer, Idaho Power is no longer
assuming termination of this service. This change resulted in the addition of wheeling
revenue related to this service and the adjustment of Midpoint West available
transmission capacity for determining the GWW transmission trigger levels from
resource additions.
3. The company’s summer load growth has accelerated in the years directly following
B2H in-service, further increasing the cost effectiveness of the project.
4. The company’s winter needs, which were not a major consideration in the 2021 IRP,
have accelerated due to industrial load growth. The company’s B2H-related asset
exchange with PacifiCorp enables 200 MW of additional winter connectivity.
Gateway West Phase 1
In the 2023 IRP, the company has identified the need for multiple Gateway West phases within
the 20-year planning window. The first Idaho Power Gateway West phase, which falls within the
Action Plan window, is the Midpoint–Hemingway #2 500-kV line, Midpoint–Cedar Hill 500-kV
line, and Mayfield 500-kV substation (GWW Phase 1), which will collectively relieve Idaho
Power’s constrained transmission system between the Magic Valley and the Treasure Valley.
There were no Gateway West phases identified for inclusion in the Preferred Portfolio of the
2021 IRP, but that has changed in the 2023 IRP primarily because of the following
considerations: 1) a significant increase in the company’s near-term load forecast and 2)
continuation of tax credits associated with wind and solar resources. With respect to the first
consideration, Idaho Power’s larger near-term load forecast results in the need for more
generation resources. As a result, AURORA is selecting large amounts of cost-effective
renewable resources—and Gateway West will be distinctly suited to bring that electricity to
load centers. Similarly, the continuation of tax credits makes renewables more cost-effective in
the model, thereby adding more renewables and making Gateway West even more necessary
to enable delivery of the additional renewables.
To evaluate the cost effectiveness of transmission facilities, the company uses AURORA’s LTCE
model. A transmission facility is evaluated by first developing an optimal portfolio inclusive of
the transmission facility, and second an optimal portfolio exclusive of the transmission facility.
Executive Summary
2023 Integrated Resource Plan Page 13
The Preferred Portfolio, inclusive of GWW Phase 1, is $577 million NPV more cost effective than
the optimized portfolio that is exclusive of any Gateway West phases.
• Preferred Portfolio (with GWW) NPV—$9,746 million
• Portfolio without GWW NPV—$10,326 million
• GWW NPV Cost Effectiveness Differential—$580 million
Transmission is a necessity to interconnect and deliver electricity from new resources.
Some resources, such as natural gas power plants, can theoretically be sited near load without
major transmission upgrades, but even this can be challenging due to factors, such as natural
gas pipeline limitations and air quality permitting. The “Without Gateway West Phases”
portfolio illustrates that even if local area challenges can be overcome, a future without
Gateway West is not cost effective.
The company’s additional load growth, coupled with opportunities to leverage wind and solar
tax credits, necessitate additional east-to-west transmission connectivity across southern Idaho
to enable a least-cost, least-risk resource portfolio.
Southwest Intertie Project-North
SWIP-N is a federally permitted 500-kV transmission project being developed by Great Basin
Transmission, LLC, which would provide a connection between southern Idaho and southern
Nevada. As part of the 2023 IRP process, the company has identified potential value associated
with the addition of SWIP-N.
SWIP-N is a unique opportunity that could provide Idaho Power a transmission connection to
the southern power markets that could be leveraged in the winter months and further diversify
the company’s market access. Idaho Power’s interest in the SWIP-N project would be in the
south-to-north direction. Based on the California Independent System Operator (CAISO) plan4,
CAISO may have an interest in the north-to-south capacity on the project. Due to Idaho Power’s
interest in only a minority capacity position and uncertainty that is inherent around potential
co-participant arrangements on the project, Idaho Power has not placed SWIP-N into its
Preferred Portfolio of resources for the 2023 IRP.
Should the company decide to move forward with the project, the company will seek
appropriate regulatory review and approval. Depending on the timing of Idaho Power’s
decision, the company may supplement the 2023 IRP proceedings in the Idaho and Oregon
jurisdictions with additional SWIP-N related information.

4 ISO-Board-Approved-2022-2023-Transmission-Plan.pdf (caiso.com).
Executive Summary
Page 14 2023 Integrated Resource Plan
Historical and Forecasted Emissions
Since the 2021 IRP, Idaho Power has taken significant steps toward reducing carbon emissions.
The emissions impact of these steps is discussed in Chapter 3—Clean Energy & Climate Change
and include the conversion of all four Bridger units and both Valmy units from coal to natural
gas operations, as well as the addition of significant amounts of clean resources, such as solar,
wind, and storage.
Because Idaho Power uses clean hydropower resources, the company’s carbon emissions vary
annually based on factors that influence hydropower production, including precipitation and
temperature. Low hydro conditions, which materialized in both 2021 and 2022, result in the
need for Idaho Power to leverage resources that produce carbon emissions. As seen in
Table 1.4, historical emissions (generation emissions plus emissions from purchased power
minus emissions from sold power) were higher in low hydro years. Despite individual year
increases, the historical trend is downward. Emissions for 2023 were not available at the time
of completing the IRP, thereby creating a gap in the data. Forecasted emissions show continued
and substantial downward trend in emissions—the result of coal-to-gas conversions and the
addition of clean resources through the IRP time horizon.
Table 1.4 Historical and forecasted emissions

-
1
2
3
4
5
6
7
2013 2018 2023 2028 2033 2038 2043
Total CO2 Emissions (Million Metric Tons)
Historical Emissions Forecast Emissions 10-Year Historical Trend
1. Background
2023 Integrated Resource Plan Page 15
1. BACKGROUND
Integrated Resource Plan
Idaho Power’s resource planning process has four primary goals:
1. Identify sufficient resources to reliably serve the growing demand for energy and
flexible capacity within Idaho Power’s service area throughout the 20-year
planning period.
2. Ensure the selected resource portfolio balances cost and risk while also considering
environmental factors.
3. Give equal and balanced treatment to supply-side resources, demand-side measures,
and transmission resources.
4. Involve the public in the planning process in a meaningful way.
The Integrated Resource Plan (IRP) evaluates a 20-year planning period in which demand is
forecasted and additional resource requirements are identified.
Idaho Power relies on current resources, including hydroelectric projects, solar photovoltaic
(PV) projects, wind farms, geothermal plants, natural gas-plants, coal-facilities, and energy
markets via transmission interconnections. The company’s existing supply-side resources are
detailed in Chapter 4, while possible future supply-side resources are explored in Chapter 5.
Other resources relied on for planning include demand-side management (DSM) and
transmission resources, which are further explored in chapters 6 and 7, respectively. The goal
of DSM programs is to achieve cost-effective, energy efficiency savings and provide an optimal
amount of peak reduction from demand response (DR) programs. Idaho Power also strives to
provide customers with tools and information to help them manage their own energy use.
The company achieves these objectives by implementing and carefully managing incentive
programs as well as through outreach and education.
Idaho Power’s resource planning process evaluates additional stand-alone transmission
capacity as a resource alternative to serve retail customers. Transmission projects are often
regional resources, and Idaho Power coordinates transmission planning as a member of
NorthernGrid. Idaho Power is obligated under Federal Energy Regulatory Commission (FERC)
regulations to plan and expand its local transmission system to provide requested firm
transmission service to third parties and to construct and place in service sufficient
transmission capacity to reliably deliver energy and capacity to network customers and
Idaho Power retail customers. The delivery of energy, both within Idaho Power’s system and
through regional transmission interconnections, is of increasing importance for several reasons.
First, adequate transmission is essential to achieve cost savings benefits through robust
1. Background
Page 16 2023 Integrated Resource Plan
participation in the Energy Imbalance Market (EIM). Second, it is necessary to unlock
geographic resource diversity benefits for Variable Energy Resources (VER). The timing of new
transmission projects is subject to complex permitting, siting, and regulatory requirements and
coordination with co-participants.
Public Advisory Process
Idaho Power has involved representatives of the public in the resource planning process since
the early 1990s. The IRP Advisory Council (IRPAC) meets regularly during the development of
the resource plan, and the meetings are open to the public. Members of the council include
staff from the Idaho Public Utilities Commission (IPUC) and Public Utility Commission of Oregon
(OPUC); political, environmental, and customer representatives; and representatives of other
public-interest groups. Many members of the public also participate in the IRPAC meetings.
Some individuals have participated in Idaho Power’s resource planning process for over
20 years. A list of the 2023 IRPAC members can be found in Appendix C—Technical Report.
Idaho Power facilitated 12 IPRAC meetings (see Appendix C—Technical Report, IRPAC Meeting
Schedule and Agenda). With the exception of the introductory meeting, all 2023 IRPAC
meetings were conducted virtually, which resulted in increased and more diverse participation
of members and the general public. The company received positive feedback from IRPAC
members that the virtual forum was logistically easier and aided in the presentation and review
of materials.
To further enhance engagement, Idaho Power also maintained an online webpage for
stakeholders to submit requests for information and for Idaho Power to provide responses.
The webpage allowed stakeholders to develop their understanding of the IRP process,
particularly its key inputs, consequently enabling more meaningful stakeholder involvement.
The company made presentation slides and other materials used at the IRPAC meetings,
in addition to the question-submission portal and other IRP documents, available to the public
on its website at idahopower.com/IRP. For the first time as part of the IRP process, Idaho Power
included educational resources provided and prepared to help IRPAC members and attendees
understand and catch up on industry concepts on its IRP webpage (accessed at the prior link).
These resources include information on industry topics and pre-recorded presentations
prepared by the National Renewable Energy Laboratory, the United States Energy Information
Administration (EIA), the U.S. Department of Energy (DOE), and Idaho Power. A list of acronyms
and a directory of Idaho Power employees involved in the process was also posted.
IRP Methodology
The primary goal of the IRP is to ensure Idaho Power’s system has sufficient resources to
reliably serve customer demand and flexible capacity needs over the 20-year planning period
while also minimizing costs and risks to customers. This process is completed, and a new plan is
1. Background
2023 Integrated Resource Plan Page 17
produced every two years. To ensure Idaho Power can meet its customers’ growing need for
energy, the capability of the existing system is included and then resources are added (or
removed). Multiple portfolios consisting of varying resource additions (and exits) are produced.
Resource additions include supply-side resources like solar generation facilities, while resource
exits include coal- and gas-fired resources. Other resource additions include demand-side
resources like energy efficiency measures and transmission projects that increase access to
energy markets or support integration of renewable resources. The portfolios are then
compared, and the portfolio that best minimizes cost and risk is selected in the plan.
Cost
Costs for each portfolio include the capital costs of designing and constructing each resource,
including transmission builds and expansions, through the 20-year timeframe of the plan.
Operational costs—such as fuel costs, maintenance costs, environmental controls, and the price
to purchase and sell energy on the electrical market—are modeled and included to compare
the cost effectiveness of each portfolio.
Risk
Typical of long-term planning, uncertainty increases the further into the future one attempts to
evaluate. Acknowledging this uncertainty and the risk this creates, the 2023 IRP includes a
robust risk analysis and approaches the subject in three ways.
The first risk analysis method evaluates different future scenarios to test the decisions
being made, especially in the Near-Term Action Plan window—which is the first five years in the
plan (2024–2028). Future scenarios typically include multiple assumptions that combine to
define the scenario. To enhance the risk evaluation within the 2023 IRP, the company worked
with the IRPAC to develop a variety of unique future scenarios. The company ultimately used
these scenarios to test whether the decisions being made within the Near-Term Action Plan
window are robust across multiple futures. The future scenarios are as follows:
• High Gas Price–High Carbon Price
• Low Gas Price–Zero Carbon Price
• Constrained Battery Storage
• 100% Clean Energy by 2045
• Additional Large Load
• 100% Clean Energy by 2035
1. Background
Page 18 2023 Integrated Resource Plan
• New Forecasted PURPA5 resources
• Extreme Weather
• Rapid Electrification
• Constrained Transmission
• Load Flattening
The second method employed by the 2023 IRP is an analysis of stochastic risk. Stochastic
analyses help quantify the sensitivity and risk associated with variables over which Idaho Power
has little or no control. For more information, see Chapter 10.
The third method of risk analysis, qualitative risk, is used to identify risks that are not easily
quantified. A detailed discussion of qualitative risk can be found in Chapter 10.
Modeling
Due to the complexity involved in an analysis that includes a 20-year forecast for energy
demand, fuel prices, resource costs and more, Idaho Power uses modeling software to generate
and optimize resources selected in portfolios. For the 2023 IRP, the company used AURORA’s
Long-Term Capacity Expansion (LTCE) platform to generate resource portfolios. As described in
Chapter 9—Portfolios, the software evaluates how to cost-effectively meet future needs by
selecting resources that are optimized within modeling constraints.
Validation and Verification
In the 2023 IRP, the company employed additional verification tests to ensure the AURORA
LTCE model produced an optimized solution within its modeling tolerance. Verification tests
validated the most economic portfolio under numerous variations of resources and timing.
Details about the validation and verification process can be found in the Validation and
Verification section of Appendix C—Technical Report.
Reliability
In addition to AURORA-specific validation and verification, the company measured the
reliability of select portfolios using the Loss of Load Expectation (LOLE) methodology to
verify that the AURORA-produced portfolios meet Idaho Power’s reliability requirements.
Idaho Power implements the LOLE methodology through an internally developed Reliability and
Capacity Assessment Tool (RCAT), which calculates portfolio Planning Reserve Margins (PRM)
and resource Effective Load Carrying Capability (ELCC) values. PRMs and ELCCs from the RCAT
are then provided as an input to the AURORA LTCE model. To verify that the translation from

5 Public Utility Regulatory Policies Act of 1978 (PURPA)
1. Background
2023 Integrated Resource Plan Page 19
the RCAT to the AURORA LTCE model produces reliable portfolios, the RCAT calculates annual
capacity positions for the select portfolios’ resource buildouts to validate that each year in
the 20-year planning horizon is in a position of capacity length when the LOLE threshold is
0.1 event-days per year. This verifies that the select portfolios meet Idaho Power’s
reliability threshold.
An in-depth discussion of the LOLE calculation process can be found in the Loss of Load
Expectation sections of Appendix C—Technical Report.
Energy Risk Management Policy
While the 2023 IRP addresses Idaho Power’s long-term resource needs, near-term energy
needs are evaluated in accordance with the company’s Energy Risk Management Policy and
Energy Risk Management Standards. The risk management standards were collaboratively
developed in 2002 among Idaho Power, IPUC staff, and interested customers (IPUC Case
No. IPC-E-01-16). The risk management standards provide guidelines for Idaho Power’s
physical and financial hedging and are designed to systematically identify, quantify,
and manage the exposure of the company and its customers to uncertainties related to the
energy markets in which Idaho Power is an active participant. The risk management standards
specify an 18-month load and resource review period, and Idaho Power’s Risk Management
Committee assesses the resulting operations plan monthly.
2. Political, Regulatory, and Operational Considerations
Page 20 2023 Integrated Resource Plan
2. POLITICAL, REGULATORY,
AND OPERATIONAL CONSIDERATIONS
As a regulated utility, Idaho Power’s operations and long-term planning are guided by federal,
regional, and state policies and requirements. This chapter addresses the long-standing and
new federal policies; Idaho- and Oregon-specific policies and regulations; and new
developments in regional energy policy.
Federal Policy & Activities
Hydroelectric Relicensing
As a utility that operates non-federal
hydroelectric projects on qualified
waterways, Idaho Power obtains licenses
from FERC for its hydroelectric projects.
The licenses are valid for 30 to 50 years,
depending on the size, complexity,
and cost of the project.
Idaho Power is currently relicensing two
projects: the Hells Canyon Complex
(HCC) and American Falls. The HCC is
the more significant of the two
relicensing efforts.
The HCC provides approximately 70% of Idaho Power’s hydroelectric generating capacity
and 30% of the company’s total generating capacity. The HCC provides clean energy to
Idaho Power’s system, supporting Idaho Power’s long-term clean energy goals. The HCC also
provides flexible capacity critical to the successful integration of VERs, which provide low-cost
energy and further enable Idaho Power to achieve its clean energy goals.
Idaho Power’s HCC license application was filed in July 2003 and accepted by FERC for filing in
December 2003. FERC has been processing the application consistent with the requirements of
the Federal Power Act of 1920, as amended (FPA); the National Environmental Policy Act of
1969, as amended (NEPA); the Endangered Species Act of 1973; the Clean Water Act of 1972
(CWA); and other applicable federal laws. Since issuance of the final environmental impact
statement (EIS) (NEPA document) in 2007, FERC has been waiting for Idaho and Oregon to issue
a final Section 401 certification under the CWA. The states issued the final CWA 401
certification on May 24, 2019. In July 2019, three third parties filed lawsuits against the Oregon
Department of Environmental Quality in Oregon state court challenging the Oregon CWA 401
certification. Two of the lawsuits were consolidated, and Idaho Power intervened in that

Hells Canyon Dam.
2. Political, Regulatory, and Operational Considerations
2023 Integrated Resource Plan Page 21
lawsuit. The parties reached a settlement in September 2021. The court dismissed the third
challenge with prejudice. No parties challenged the Idaho CWA 401 certification. FERC will now
be able to continue with the relicensing process, which includes consultation under the
Endangered Species Act of 1973, among other actions.
Efforts to obtain a new, multi-year license for the HCC will likely continue through 2024.
Until the multi-year license is issued, Idaho Power continues to operate the project under
annual licenses issued by FERC.
After a new multi-year license is issued, further costs will be incurred to comply with the terms
of the new license. Because the new license for the HCC has not been issued—and discussions
on protection, mitigation, and enhancement packages are still being conducted—Idaho Power
cannot determine the ultimate terms of, and costs associated with, any resulting
long-term license.
In addition to the relicensing of the HCC, Idaho Power is also relicensing its American Falls
hydroelectric project. In February 2023, Idaho Power filed its Final License Application with
FERC. The current license expires in February 2025.
Relicensing activities included the following:
• Coordinating the relicensing process
• Consulting with regulatory agencies, tribes, and interested parties on resource and
legal matters
• Preparing and conducting studies or analysis on fish; endangered species;
terrestrial resources; water quality; recreation; and archaeological resources,
among others
• Analyzing data and reporting study results
• Preparing all necessary reports, exhibits, and filings to support ongoing regulatory
processes related to the relicensing effort
Failure to relicense any of the existing hydroelectric projects at a reasonable cost will create
upward pressure on the electric rates of Idaho Power customers. The relicensing process also
has the potential to decrease available capacity and increase the cost of a project’s generation
through additional operating constraints and requirements for environmental protection,
mitigation, and enhancement measures imposed as a condition of relicensing. Idaho Power’s
goal throughout the relicensing process is to maintain the low cost of generation at the
hydroelectric facilities while implementing non-power measures designed to protect and
enhance the river environment. As noted earlier, Idaho Power views the relicensing of the HCC
as critical to its clean energy goals.
2. Political, Regulatory, and Operational Considerations
Page 22 2023 Integrated Resource Plan
The 2023 IRP assumes that the available capacity and operational flexibility of the HCC and
American Falls will be consistent with the most current relicensing proposals and Idaho Power’s
anticipation of what will be included in a future FERC license. All other hydroelectric facilities
are assumed to have available capacity and operational flexibility as outlined in their current
FERC licenses.
Recent Executive Orders
In January 2021, the Biden Administration issued several executive orders to establish new
federal environmental mandates, revoke several existing executive orders, and require agencies
to review regulations related to environmental matters issued by the previous presidential
administration. One executive order results in the United States rejoining the Paris Agreement
on climate change, which requires commitments to reduce greenhouse gas (GHG) emissions,
among other things. A more recent executive order, signed by President Biden on
December 8, 2021, seeks to leverage government actions and procurement to further the clean
energy transition. Among several directives in the order, is the requirement to achieve net-zero
emissions from federal procurement and from overall federal operations by 2050.6
Inflation Reduction Act
On August 16, 2022, President Biden signed into law the Inflation Reduction Act of 2022 (IRA),
a federal law intended to curb national inflation by, among other items, investing in
domestic energy production and expanding incentives for clean energy. The law includes
$783 billion for energy- and climate change-related efforts, notably expanding the type and
availability of tax credits for clean energy investment and production. Specifically, the IRA
extends the investment tax credit (ITC) for solar projects and now offers this tax credit for
standalone storage projects; establishes a nuclear power production credit; and creates broad
and technology-neutral investment and production tax credits (PTC) for new clean electricity
generation that produces zero or negative GHG emissions.
The amount, duration, and requirements of the incentives vary by type, and each has the
potential to unlock additional “bonus” credits for qualifying conditions: domestic
manufacturing and delivery of energy to low-income communities.
As with all legislation, the IRA establishes these incentives as new laws, but a variety of
government agencies are tasked with implementing and creating access to these incentives.
As a result, the 2023 IRP includes elements of the IRA that were understood at the time of
developing this long-term plan.

6 whitehouse.gov/briefing-room/statements-releases/2021/12/08/fact-sheet-president-biden-signs-executive-
order-catalyzing-americas-clean-energy-economy-through-federal-sustainability/.
2. Political, Regulatory, and Operational Considerations
2023 Integrated Resource Plan Page 23
Clean Power Plan
In June 2014, the United States Environmental Protection Agency (EPA) released, under Section
111(d) of the Clean Air Act of 1970, a proposed rule for addressing GHG emissions from existing
fossil fuel electric generating units. The proposed rule was intended to achieve a 30% reduction
in carbon dioxide (CO2) emissions from the power sector by 2030. In August 2015, the EPA
released the final rule under Section 111(d) of the Clean Air Act, referred to as the Clean Power
Plan, which required states to adopt plans to collectively reduce 2005 levels of power sector
CO2 emissions by 32% by 2030.
In June 2019, the EPA released the Affordable Clean Energy rule to replace the Clean Power
Plan under Section 111(d) of the Clean Air Act for existing electric utility generating units.
In August 2019, 22 states sued the EPA in federal appeals court to challenge the Affordable
Clean Energy rule. In January 2021, the United States Court of Appeals for the District of
Columbia Circuit vacated the Affordable Clean Energy rule in its entirety and directed the EPA
to create a new regulatory approach. On February 12, 2021, the EPA issued a memorandum
notifying states that it will not require states to submit plans to the EPA under Section 111(d)
of the Clean Air Act because the Court vacated the Affordable Clean Energy rule without
reinstating the Clean Power Plan.
Cross-State Air Pollution Rule
On March 15, 2023, the EPA pre-published the final Federal Good Neighbor Plan for the 2015
Ozone National Ambient Air Quality Standards. The Good Neighbor Plan is intended to address
23 states’ obligations to eliminate their contribution to nonattainment, or interference with
maintenance, of the 2015 ozone National Ambient Air Quality Standards under the “good
neighbor” or “interstate transport” provision of the Clean Air Act. Nevada is included in this
rule; however, Wyoming’s inclusion has been deferred pending further review of air quality
modeling and analysis. The rule will become effective 60 days after publication in the
Federal Register.
Idaho Power has entered discussions with NV Energy on the impact the rule will have on
operations at North Valmy. Modeling of North Valmy will include compliance with the Good
Neighbor Plan, including a range of nitrogen oxide (NOx) allowances based on the probable split
between the partners. Jim Bridger will be modeled with a sensitivity that Wyoming may be
included in the Good Neighbor Plan in the future.
Wyoming Round 1 Regional Haze Compliance
On February 14, 2022, Wyoming and PacifiCorp filed a Consent Decree in the Wyoming State
District Court, settling potential State compliance claims with the State Implementation Plan
(SIP) previously approved for the Jim Bridger Power Plant (Bridger) by the EPA in 2015.
The Consent Decree required PacifiCorp to submit a new permit application and a proposed SIP
2. Political, Regulatory, and Operational Considerations
Page 24 2023 Integrated Resource Plan
revision within two months, reflecting emission limits consistent with the conversion of Bridger
units 1 and 2 to natural gas generation by January 1, 2024. In April 2022, PacifiCorp submitted
the new permit application and proposed SIP revision, consistent with the terms of the
Consent Decree.
The 2023 IRP modeling includes the natural gas conversion of Bridger units 1 and 2 and
considers the monthly emission limits of the Consent Decree. After the natural gas conversion
at Bridger units 1 and 2, the monthly emission limits outlined in the Consent Decree will not
restrict Bridger operations.
Public Utility Regulatory Policies Act
In 1978, the United States Congress passed PURPA, requiring investor-owned electric utilities to
purchase energy from any qualifying facility (QF) that delivers energy to the utility. A QF is
defined by FERC as a small renewable-generation project or small cogeneration project.
Electricity from Cogeneration and Small-Power Production (CSPP) is often associated with
PURPA. Individual states were tasked with establishing Power Purchase Agreement (PPA) terms
and conditions, including prices that each state’s utilities are required to pay as part of the
PURPA agreements. Because Idaho Power operates in Idaho and Oregon, the company must
adhere to IPUC rules and regulations for all PURPA facilities located in Idaho, and to OPUC rules
and regulations for all PURPA facilities located in Oregon. The rules and regulations are similar
but not identical for the two states.
Under PURPA, Idaho Power is required to pay for generation at the utility’s avoided cost,
which is defined by FERC as the incremental cost to an electric utility of electric energy or
capacity that, but for the purchase from the QF, such utility would generate itself or purchase
from another source. The process to request an Energy Sales Agreement for Idaho QFs is
described in Idaho Power’s Tariff Schedule 73; and for Oregon QFs, Schedule 85. QFs also have
the option to sell energy “as-available” under Idaho Power’s Tariff Schedule 86.
Idaho Policy & Activities
Idaho Strategic Energy Alliance
Under the umbrella of the Idaho Governor’s Office of Energy and Mineral Resources, the Idaho
Strategic Energy Alliance (ISEA) helps develop effective and long-lasting responses to existing
and future energy challenges. The purpose of the ISEA is to enable the development of a
sound energy portfolio that emphasizes the importance of an affordable, reliable, and secure
energy supply.
ISEA’s strategy focuses on three foundational elements: 1) maintaining and enhancing a stable,
secure, and affordable energy system; 2) determining how to maximize the economic value of
Idaho’s energy systems and in-state capabilities, including attracting jobs and energy-related
2. Political, Regulatory, and Operational Considerations
2023 Integrated Resource Plan Page 25
industries and creating new businesses with the potential to serve local, regional, and global
markets; and 3) educating Idahoans to increase their knowledge about energy and
energy issues.
Idaho Power representatives serve on the ISEA Board of Directors and several volunteer task
forces on the following topics:
• Energy efficiency and conservation
• Wind
• Geothermal
• Hydropower
• Baseload resources
• Biogas
• Biofuel
• Solar
• Transmission
• Communication and outreach
• Energy storage
• Transportation
Idaho Energy Landscape
In 2022, the ISEA prepared the 2022 Idaho Energy Landscape Report to help Idahoans better
understand the contemporary energy landscape in the state and to make informed decisions
about Idaho’s energy future.
The 2022 Idaho Energy Landscape Report concludes, “The strength of Idaho’s economy and
quality of life for its citizens depend upon access to affordable and reliable energy resources.”7
The report provides information about energy resources, production, distribution, and use in
the state. The report also discusses the need for reliable, affordable, and sustainable energy for
individuals, families, and businesses, while protecting the environment to achieve sustainable
economic growth and maintain Idaho’s quality of life.
The report states that low average rates for electricity and natural gas are the most important
feature of Idaho’s energy outlook. Large hydroelectric facilities on the Snake River and other

7 2022-Idaho-Energy-FINAL.pdf. Accessed July 2023.
2. Political, Regulatory, and Operational Considerations
Page 26 2023 Integrated Resource Plan
tributaries of the Columbia River provide the energy and flexibility required to meet the
demands of this growing region.
In 2022, hydroelectricity remained the largest source of Idaho’s in-state electricity generation,
comprising 51%.8 Low-cost hydroelectricity helps preserve Idaho’s low electricity rates and is
the cornerstone of Idaho Power’s low electricity rates. As the largest utility in the state,
Idaho Power’s total retail average rate was 32% below the national average in 2022, based on
data compiled by the Edison Electric Institute.9
Idaho Water Issues
Power generation at Idaho Power’s hydroelectric projects on the Snake River and its
tributaries is dependent on the management of water resources by local, state, and federal
entities, and the administration of water rights by the states within the Snake River Basin.
In addition to a FERC license and other associated state and federal permits, Idaho Power must
also secure and maintain state water rights for the operation of these projects.
The long-term sustainability of the Snake River Basin streamflows, including tributary spring
flows and the regional aquifer system, is crucial for Idaho Power to maintain generation
from these projects. Idaho Power is dedicated to the vigorous defense of its water rights.
The company’s ongoing participation in various efforts to develop sustainable water
rights-related policy and studies is intended to guarantee sufficient water is available for use at
the company’s hydroelectric projects on the Snake River and to ensure the state’s
acknowledgment of the value of hydroelectric power to Idaho’s economy.
Idaho Power, along with other Snake River Basin water-right holders, was engaged in the Snake
River Basin Adjudication (SRBA), a general streamflow adjudication process started in 1987 to
define the nature and the extent of water rights in the Snake River Basin. Idaho Power filed
claims for all its hydroelectric water rights in the SRBA. Because of the SRBA, Idaho Power’s
water rights were adjudicated, resulting in the issuance of partial water-right decrees. The Final
Unified Decree for the SRBA was signed on August 25, 2014.
The initiation of the SRBA resulted from the Swan Falls Agreement, which was entered into by
Idaho Power and the governor and attorney general of the State of Idaho in October 1984.
The Swan Falls Agreement resolved a struggle over the company’s water rights at the Swan
Falls Hydroelectric Project (Swan Falls Project). The agreement stated Idaho Power’s water
rights at its hydroelectric facilities between Milner Dam and Swan Falls entitled Idaho Power to

8 eia.gov/state/analysis.php?sid=ID
9 Edison Electric Institute, Typical Bills and Average Rates Report Winter 2023.

2. Political, Regulatory, and Operational Considerations
2023 Integrated Resource Plan Page 27
a minimum flow at Swan Falls of 3,900 cubic feet per second (cfs) during the irrigation season
and 5,600 cfs during the non-irrigation season.
The Swan Falls Agreement placed the portion of the company’s water rights beyond the
minimum flows in a trust established by the Idaho Legislature for the benefit of Idaho Power
and Idahoans. Legislation establishing the trust granted the state authority to allocate trust
water to future beneficial uses in accordance with state law. Idaho Power retained the right to
use water in excess of the minimum flows at its facilities for hydroelectric generation until it
was reallocated to other uses.
Idaho Power filed suit in the SRBA in 2007 because of disputes about the meaning and
application of the Swan Falls Agreement. The company asked the court to resolve issues
associated with Idaho Power’s water rights and the application and effect of the trust
provisions of the Swan Falls Agreement. In addition, Idaho Power asked the court to determine
whether the agreement subordinated Idaho Power’s hydroelectric water rights to managed
aquifer recharge.
A settlement signed in 2009 reaffirmed the Swan Falls Agreement and resolved the litigation by
clarifying the water rights held in trust by the State of Idaho are subject to subordination to
future upstream beneficial uses, including managed aquifer recharge. The settlement also
committed the State of Idaho and Idaho Power to further discussions on important
water-management issues concerning the Swan Falls Agreement and the management of water
in the Snake River Basin. Pursuant to the Framework, Idaho Power, the Idaho Water Resource
Board (IWRB), and the State of Idaho actively work cooperatively to explore resolution of issues
as members of the Swan Falls Implementation Group.
In 2014, Idaho Power expanded its long-standing cloud-seeding program, which began in the
Payette basin in 2003. The expansion of cloud-seeding activities to the Boise and Wood River
basins was conducted in collaboration with basin water users and the IWRB. Today,
Idaho Power financially supports and operates its cloud-seeding program in the Payette and
operates and collaboratively financially supports programs in the Upper Snake, Boise, and
Wood River basins. Along with augmenting surface flows in the Snake River basins, cloud
seeding in the Wood River Basin, along with the Upper Snake River Basin, benefits the Eastern
Snake River Plain Aquifer (ESPA) Comprehensive Aquifer Management Plan implementation
through additional water supply for natural and managed aquifer recharge.
In recent years, water management activities for the ESPA have been driven by the 2015
Settlement Agreement between the Surface Water Coalition and the Idaho Ground Water
Appropriators. This agreement had settled a call by the Surface Water Coalition against
groundwater appropriators for the delivery of water to its members at the Minidoka and Milner
dams. The agreement had provided a plan for the management of groundwater resources on
2. Political, Regulatory, and Operational Considerations
Page 28 2023 Integrated Resource Plan
the ESPA, with the goal of improving aquifer levels and spring discharge upstream of Milner
Dam. The plan provided short- and long-term aquifer level goals that must be met to ensure a
sufficient water supply for the Surface Water Coalition. The plan also references ongoing
management activities, such as aquifer recharge.10
On November 4, 2016, the Idaho Department of Water Resources Director signed an order
creating a Ground Water Management Area (GWMA) for the ESPA. The Director told the Idaho
Water Users Association at their November 2016 Water Law Seminar:
By designating a groundwater management area in the Eastern Snake Plain
Aquifer region, we bring all of the water users into the fold—cities, water
districts and others—who may be affecting aquifer levels through their
consumptive use. […] As we’ve continued to collect and analyze water data
through the years, we don’t see recovery happening in the ESPA. We’re losing
200,000 acre-feet of water per year.
The director said creating a GWMA will embrace the terms of a historic water settlement
between the Surface Water Coalition and groundwater users, but the GWMA for the ESPA will
also seek to bring other water users under management who have not joined a groundwater
district—including some cities. In 2023, an advisory committee was formed and tasked with
developing a groundwater management plan to address water supply issues impacting the
ESPA. Idaho Power participates as an advisory committee member.
On October 21, 2022, the director of the Idaho Department of Water Resources signed an order
re-establishing a moratorium on the issuance of new consumptive water rights permits from
surface and groundwater tributary to the Snake River upstream from Milner Dam, as well as
from Milner Dam to King Hill. The order also created a new moratorium on the issuance of new
consumptive water right permits from surface and groundwater tributary to the Snake River
between King Hill and Swan Falls Dam. In issuing the moratorium, the director concluded that
additional appropriation of surface or groundwater upstream of Swan Falls could lead to a
violation of the minimum streamflow rights of 3,900 cfs and 5,600 cfs at the Murphy gage.
Effectively, the moratorium order acknowledges that water supplies are fully allocated above
Swan Falls Dam, and that a moratorium is necessary to protect the minimum streamflow rights
resulting from the Swan Falls Agreement. The moratorium is important to Idaho Power because
it demonstrates the role that the State of Idaho has in protecting a minimum water supply for
the company’s hydroelectric system.

10 In 2023, it became apparent that the goals set in the agreement would not be achieved; however, the
settlement agreement provides the framework for modeling future management activities on the ESPA. These management activities are included in the modeling of hydropower production through the IRP
planning horizon.
2. Political, Regulatory, and Operational Considerations
2023 Integrated Resource Plan Page 29
Oregon Policy & Activities
State of Oregon 2022 Biennial Energy Report
In 2017, the ODOE introduced House Bill (HB) 2343, which required ODOE to develop a new
biennial report to inform local, state, regional, and federal energy policy development and
energy planning and investments. The 2022 Biennial Energy Report11 provides foundational
energy data about Oregon and examines the existing policy landscape while identifying options
for continued progress toward meeting the state’s goals in the areas of climate change,
renewable energy, transportation, energy resilience, energy efficiency, and consumer
protection.
Renewable energy continues to make up an increasing share of Oregon’s energy mix each year.
With the increase in renewable energy sources, other resources in the electricity mix have
changed as well. The amount of coal included in Oregon’s resource mix declined from 32% in
2012 to 26% in 2020. Natural gas—a resource that can help manage the hourly variation of
renewable resources and smooth out seasonal hydropower variation—has steadily increased its
share of Oregon’s resource mix from 12% in 2012 to 21.5% in 2020.
The main theme of the 2022 biennial report was Oregon’s transition to a low-carbon economy.
According to the report, achieving Oregon’s energy and climate goals, while protecting
consumers, will take collaboration among state agencies; policymakers; state and local
governments; and private-sector business and industry leaders.12
Oregon Renewable Portfolio Standard and Emissions
Reduction Requirements
As part of the Oregon Renewable Energy Act of 2007 (Senate Bill 838), the State of Oregon
established a Renewable Portfolio Standard (RPS) for electric utilities and retail electricity
suppliers. Under the Oregon RPS, Idaho Power is classified as a smaller utility because the
company’s Oregon customers represent less than 3% of Oregon’s total retail electric sales.
In 2021 per EIA data, Idaho Power’s Oregon customers represented 1.3% of Oregon’s total
retail electric sales. As a smaller utility in Oregon, Idaho Power will likely have to meet a 5% RPS
requirement beginning in 2025.
In 2016, the Oregon RPS was updated by Senate Bill 1547 to raise the target from 25% by 2025
to 50% renewable energy by 2040; however, Idaho Power’s obligation as a smaller utility does
not change. Additionally, the Oregon Legislature in 2021 passed HB 2021, which sets GHG
emissions reduction requirements associated with electricity sold to utility customers. Idaho

11 energyinfo.oregon.gov/ber. Accessed April 2023.
12 ODOE, 2022 Biennial Energy Report.
2. Political, Regulatory, and Operational Considerations
Page 30 2023 Integrated Resource Plan
Power is exempt from the conditions of this bill, as the company has fewer than 25,000 retail
customers in Oregon.
The State of Idaho does not currently have an RPS.
Oregon Community Solar Program
In 2016, the Oregon Legislature enacted Senate Bill 1547, which requires the OPUC to establish
a program for the procurement of electricity from community solar projects. Community solar
projects provide electric company customers the opportunity to share in the costs and benefits
associated with the electricity generated by solar PV systems, as owners of or subscribers to a
portion of the solar project.
Since 2016, the OPUC has conducted an inclusive implementation process to carefully design
and execute a program that will operate successfully, expand opportunities, and have a fair and
positive impact across electric company ratepayers. After an inclusive stakeholder process,
the OPUC adopted formal rules for the Community Solar Pilot program on June 29, 2017,
through Order No. 17-232, which adopted Division 88 of Chapter 860 of the Oregon
Administrative Rules. The rules also define the program size, community solar project
requirements, program participant requirements, and details surrounding the opportunity for
low-income participants, as well as information regarding on-bill crediting.
Under the Oregon Community Solar Program rules, Idaho Power’s initial capacity tier is
3.3 MW. As of completion of the 2023 IRP, Idaho Power has executed all the necessary
agreements with Verde Light, a 2.95 MW project that intends to participate in the community
solar program, with an estimated in-service date of late 2024. The proposed 2.95 MW project
will use all but 305 kilowatts (kW) of Idaho Power’s initial capacity allocation.
Additionally, Order No. 17-232 requires Idaho Power to 1) include all energized community
solar projects participating in the community solar program in its generation mix included in its
IRP and 2) include forecasts of market potential for community solar projects when assessing
the load-resource balance in the IRP. Because the potential project is not planning to be fully
operational until late 2024, the resource has not been included in this IRP. Once operational,
the project will be included as part of the generation mix in future IRP cycles.
Regional Policies & Activities
Western Resource Adequacy Program
The Western Resource Adequacy Program (WRAP) is the first regional reliability planning and
compliance program in the western United States. At its simplest, WRAP is a region-wide
planning process that assesses resource adequacy across the footprint and seeks to increase
regional reliability while providing economic benefits associated with regional coordinated
planning to participants. WRAP facilitates a reliability program that allows for available
2. Political, Regulatory, and Operational Considerations
2023 Integrated Resource Plan Page 31
resources to be shared among participants during short-term periods of resource deficiency.
The goal of this program is to maintain reliability across all participants’ systems over the
course of an operating season in which some participants may experience peak load
conditions or extreme weather events. WRAP is being developed through a collaborative,
participant-driven process that is facilitated by the Western Power Pool (WPP). WPP will be
the program operator of the WRAP, including managing implementation of the WRAP rules
and tariff.
To facilitate the sharing of resources among participants, WRAP is organized into two parts over
two seasons (summer and winter): an advanced viewing of resources—called the forward
showing—and an operations phase during which resources can be shared in times of need.
Each season has its own forward showing and operations program, and each participant
is individually responsible for complying with the forward showing and operations
program requirements.
On August 31, 2022, WPP filed a tariff with FERC requesting approval of WRAP and its proposed
framework for implementation and operation.13 On February 10, 2023, FERC approved the
WRAP tariff and underscored the importance of a regional program and the enhanced reliability
and resource adequacy that WRAP would bring.14 Following the tariff’s approval, the WPP
Board of Directors approved the slate of nominees to serve on the new Independent Board of
Directors, which includes one board chairperson and four board members with various
executive and consultative backgrounds in the electric industry.15 With the WRAP tariff
approved, the program can now transition from a non-binding to a fully-binding program.
This transition will occur in phases, with binding participation starting as early as Summer 2025
or as late as Summer 2028. While participation in WRAP is voluntary, binding participants must
meet capacity and delivery requirements and pay participation costs.
In December of 2022 and January of 2023, WPP received formal commitments from
20 participants, including Idaho Power, supporting a move forward with the next phases of
WRAP. On December 19, 2022, Idaho Power announced its plans to move forward with the
non-binding phase of WRAP.16 To date, Idaho Power has participated in WRAP’s non-binding,

13 ER22-2762, Northwest Power Pool submits tariff filing per 35.1: Western Power Pool Western Resource
Adequacy Program Tariff (submitted August 31, 2022).
14 FERC, ER22-2762-000 National Order, p. 10. (“Through increased coordination, we find that the WRAP has the
potential to enhance resource adequacy planning, provide for the benchmarking of resource adequacy
standards, and more effectively encourage the use of western regional resource diversity compared to the
status quo.”)
15 WPP, Western Power Pool Approves Nominees for New Independent Board of Directors (February 21, 2023).
16 Idaho Power news release, “Idaho Power Moves Forward with Regional Energy Adequacy Group,”
December 19, 2022.
2. Political, Regulatory, and Operational Considerations
Page 32 2023 Integrated Resource Plan
forward-showing program. Idaho Power submitted forward-showings for the winter
2022/2023, summer 2023, and winter 2023/2024 seasons.
In June 2023, Idaho Power and the other committed WRAP participants commenced the initial
account and connectivity testing in preparation for the first non-binding operational phase of
the program.
Please see the Western Resource Adequacy Program Modeling section in Appendix C—
Technical Report for details on how Idaho Power modeled WRAP benefits in the 2023 IRP.

3. Clean Energy & Climate Change
2023 Integrated Resource Plan Page 33
3. CLEAN ENERGY & CLIMATE CHANGE
Idaho Power recognizes the need to assess the impacts of climate change on industry,
customers, and long-term planning. The company undertakes a variety of analysis exercises and
impact evaluations to understand and prepare for climate change. This chapter of the IRP
focuses on identifying climate-related risks, discussing the company’s approach to monitoring
and mitigating identified risks, and examining climate-related risk considerations in the IRP.
In a climate change assessment, it is important to underscore the distinction between
mitigation and adaptation. Climate change mitigation refers to efforts associated with reducing
the severity of climate change, most commonly through the reduction of GHG emissions,
primarily CO2. In contrast, climate change adaptation involves understanding the scope of
potential physical and meteorological changes that could result from climate change and
identifying ways to adapt to such changes. Idaho Power’s climate change risk assessment
examines both mitigation and adaptation in the sections below.
Climate Change Mitigation
A Cleaner Energy Mix
Combined with the energy purchased from PPAs and PURPA projects, Idaho Power’s resource
mix was approximately 47% clean in 2022 (see below).17 The company’s clean generation mix is
primarily driven by hydropower. Idaho Power experienced the worst two-year drought in the
history of the service area from 2021 to 2022, which reduced Idaho Power’s clean production in
those years.
The 2022 energy mix notably includes more than 1,200 megawatts (MW) of power purchase
contracts for renewable energy (primarily, but not exclusively, PURPA projects): 725 MW of
wind, 316 MW of solar, 150 MW of small hydropower, and 35 MW of geothermal.

17 The company sells the RECs associated with renewable energy, meaning that the overall mix does not represent
the energy delivered to customers.
3. Clean Energy & Climate Change
Page 34 2023 Integrated Resource Plan

Figure 3.1 Idaho Power’s 2022 energy mix compared to the national average
The company’s plan to cost-effectively exit participation in coal-fired generation resources is
evident in the 2023 IRP’s Preferred Portfolio and Near-Term Action Plan. The addition of
renewable resources over the 20-year planning horizon, combined with the completion of the
Boardman to Hemingway (B2H) transmission line in 2026, will significantly change the
company’s energy mix in the future to include primarily clean resources.
Our Clean Energy Goal—Clean Today. Cleaner Tomorrow.®
In March 2019, Idaho Power announced a goal to provide 100% clean energy by 2045. This goal
furthers Idaho Power’s legacy as a leader in clean energy. The key to achieving this goal of 100%
clean energy is the company’s existing backbone of hydropower—our largest energy source—
as well as the plan contained in the Preferred Portfolio to continue reducing carbon emissions
by ending reliance on coal plants by 2030.
The Preferred Portfolio identified in the 2023 IRP reflects a clean mix of generation and
transmission resources that ensures reliable, affordable energy. Achieving our 100% clean
energy goal by 2045 will require additional technological advances and reductions in cost,
as well as a continued focus on EE and DR programs. As it has for more than a decade,
the IRPAC will continue to play a fundamental role in updating the IRP every two years,
including analyzing new and evolving technologies to help the company on its path toward a
cleaner tomorrow while providing low-cost, reliable energy to our customers.
Clean Energy Your Way
On August 15, 2023, the IPUC approved Idaho Power’s proposal to expand optional customer
clean energy offerings through the Clean Energy Your Way (CEYW) Program. Idaho Power has
long supported customers’ individual goals and initiatives to achieve clean energy through
3. Clean Energy & Climate Change
2023 Integrated Resource Plan Page 35
various program offerings, as well as becoming one of the first investor-owned utilities to
proactively establish a 100% clean energy goal by 2045.
CEYW will allow the company to better meet the needs of the growing number of customers
and communities pursuing or exploring sustainability targets, such as powering their operations
on 100% renewable energy by the end of the decade—if not sooner.
CEYW includes three options for customers:
1. CEYW—Flexible, a Renewable Energy Certificate (REC) purchase program available to all
customers in Idaho and Oregon
2. CEYW—Subscription, a forthcoming subscription option for customers of all sizes in
Idaho
3. CEYW—Construction, an option for the company’s largest customers in Idaho
Clean Energy Your Way—Flexible
The Flexible offering is a renaming of the company’s Green Power Program. Business and
residential customers can continue to purchase RECs in blocks of 100 kilowatt-hours (kWh) or
covering 100% of their usage.
Clean Energy Your Way—Subscription
The IPUC authorized the company to move to the next phase of developing a subscription
program, including identification of a resource, as well as program details and pricing.
The CEYW—Subscription offering will provide opportunities for business and residential
customers in Idaho to receive an amount of renewable energy equal to 25, 50, 75, or 100% of
their historic average annual energy use by subscribing to a new renewable resource.
Subscription terms will be intended to provide customers the ability to opt-in and opt-out
based on their individual preferences. Terms for residential customers could be as short as
monthly, and terms for business customers would range from 5 to 20 years.
In late 2023 and early 2024, Idaho Power will work with stakeholders and customers to develop
the CEYW-Subscription offering, and then file an application with the IPUC to approve the
program as proposed.
Clean Energy Your Way—Construction
The CEYW—Construction offering, now approved, allows industrial customers (Special Contract
and Schedule 19 customers) in Idaho to partner with Idaho Power to develop new renewable
resources through a long-term arrangement. Customers can work with Idaho Power and
provide input on the size, location, and type of renewable project (i.e., wind or solar) to meet
their individual requirements. The new renewables must connect to Idaho Power’s system,
but customers are able to claim the renewable attributes as their own.
3.Clean Energy & Climate Change
Page 36 2023 Integrated Resource Plan
This offering requires detailed, negotiated contracts between an Idaho customer and
Idaho Power that will require individual approval by the IPUC. In the 2023 IRP, two such
CEYW—Construction projects have been factored into portfolio modeling—Brisbie, LLC’s
supporting renewables and Micron’s Black Mesa solar project.
Details about the modeling inputs of the CEYW Program can be found in the Loss of Load
Expectation sections of Appendix C—Technical Report.
Idaho Power Carbon Emissions
Limiting the impact of climate change requires reducing GHG emissions, primarily CO2.
Idaho Power’s CO2 emissions from generating resources levels have historically been below
the national average for the 100 largest electric utilities in the United States, both in terms
of emissions intensity (pounds per megawatt-hour [MWh] generation) and total CO2 emissions
(tons). The overall declining trend of carbon demonstrates Idaho Power’s commitment
to reducing emissions. This is shown in the Figure 3.2 graph with the light green dashed
line indicating the long-term trend and the dark green solid line indicating the actual
annual amounts.
Figure 3.2 Estimated Idaho Power CO2 emissions
Idaho Power is working to reduce the amount of CO2 emitted from energy-generating sources.
Since 2009, the company has met various voluntary goals to realize its CO2 reductions.
From 2010 to 2022, Idaho Power reduced carbon emissions by an average of 29% compared to
2005. The general trend continues to be downward as Idaho Power exits coal generation
facilities and adds clean resources. The uptick in 2020 correlates with low water supply,
increased demand for electricity, and market conditions.
-
1
2
3
4
5
6
7
8
2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023
Resource CO2 Emissions (Million Metric Tons)
Historical Emissions 10 Year Historical Trend
3. Clean Energy & Climate Change
2023 Integrated Resource Plan Page 37
Generation and emissions from company-owned resources are included in the CO2 emissions
intensity calculation. Idaho Power’s progress toward achieving this intensity reduction goal and
additional information on Idaho Power’s CO2 emissions are reported on the company’s website.
Information is also available through the Carbon Disclosure Project at cdp.net.
The portfolio analysis performed for the 2023 IRP assumes carbon emissions are subject to a
per-ton cost of carbon. The carbon cost forecasts are provided in Chapter 9—Portfolios,
while the projected CO2 emissions for each analyzed resource portfolio are provided in
Chapter 10—Modeling Analysis.
Climate Change Adaptation
As noted earlier, climate change adaptation relates to steps or measures that may need to be
taken to adapt to a changing climate. To understand what these steps might be first requires
understanding the potential regional impacts of climate change that Idaho Power may
experience. To this end, Idaho Power stays current on climate change research and analysis
both generally and specific to the Pacific Northwest. The sixth assessment report from the
United Nations’ Intergovernmental Panel on Climate Change (IPCC) states “Human-induced
climate change is already affecting many weather and climate extremes in every region across
the globe. Evidence of observed changes in extremes such as heatwaves, heavy precipitation,
droughts, and tropical cyclones… has strengthened.”18
More regionally focused studies have assessed the potential impact of climate change on the
Pacific Northwest. The Fourth National Climate Assessment19 and the River Management Joint
Operating Committee20 addressed water availability in the region under multiple climate
change and response scenarios. Both reports highlight the uncertainty related to future climate
projections. However, many of the model projections show warming temperatures and
increased precipitation into the future.
In the 2023 IRP, Idaho Power approached climate change risk in two ways: through adjusted
modeling inputs and scenarios and then with specific scenarios to understand portfolio impacts
as a result of potential future climate change policies. Both approaches are summarized below
and detailed in later chapters of this report.
Risk Identification and Management
Identification of and response to specific risks are managed via Idaho Power’s annual Enterprise
Risk and Compliance Assessment, which includes a robust review of current and emerging

18 P. 8, ipcc.ch/report/ar6/wg1/downloads/report/IPCC_AR6_WGI_SPM_final.pdf.
19 nca2018.globalchange.gov/.
20 bpa.gov/p/Generation/Hydro/Pages/Climate-Change-FCRPS-Hydro.aspx.
3. Clean Energy & Climate Change
Page 38 2023 Integrated Resource Plan
regulations and external factors impacting the company’s internal operations in the areas of
technology, legal, market, weather, reputation, and safety, among other risks. Management of
each risk is identified and can include internal risk oversight by an internal department,
committee, internal or external auditor process review, and Board of Directors oversight.
Climate change-specific risks are an evolving category that includes, but may not be limited to,
changes in customer usage and hydro generation due to changing weather conditions and
severe weather events. Wildfire is another category of risk that is influenced, although not
solely driven by, climate change. In Idaho Power’s service area, climate-related risks are
evaluated in light of potential for storm severity, lightning, droughts, heat waves, fires, floods,
and snow loading. Policy-oriented risk with respect to climate change can be understood as
climate-oriented laws, rules, and regulations that could impact Idaho Power operations and
planned capital expenditure. These specific climate-oriented risks are examined in the
following sections.
Weather Risk
Changing and severe weather conditions, such as increased frequency and severity of storms,
lightning, droughts, heat waves, fires, floods, snow loading, and other extreme weather events
can adversely affect Idaho Power's operations. These events have the potential to damage
transmission, distribution, and generation facilities; cause service interruptions and extended
outages; increase costs and other operating and maintenance expenses—including emergency
response planning and preparedness expenses—and limit Idaho Power's ability to meet
customer energy demand.
Idaho Power’s Atmospheric Science group—in collaboration with Boise State University,
the Idaho National Laboratory (INL) and the Idaho Water Resources Board—worked together in
2020 to advance high-performance computing within Idaho. This public–private partnership
benefits Idaho Power customers by providing a cost-effective, high-performance computing
system to run complex weather models and conduct research to refine weather forecasting
capabilities. The company expects this system to help the company improve the integration of
renewable energy sources into the electrical grid, help Idaho Power manage the company’s
hydroelectric system and cloud-seeding operations, and better forecast severe weather
conditions.
Idaho Power modeled an Extreme Weather Scenario to capture the impacts of extreme and
changing weather conditions as part of the 2023 IRP analysis. The results can be reviewed in
Chapter 10.
Wildfire Risk
In recent years, the Western United States has experienced an increase in the frequency and
intensity of wildland fires (wildfires). Several factors have contributed in varying degrees to this
3. Clean Energy & Climate Change
2023 Integrated Resource Plan Page 39
trend including climate change, increased human encroachment in wildland areas, historical
land management practices, and changes in wildland and forest health, among other factors.
The risk of more extensive or worsening wildfires is linked to weather-related climate risk.
To manage wildfire-related risk, Idaho Power has developed a Fire Potential Index (FPI) tool
based on original work completed by San Diego Gas and Electric, the United States Forest
Service, and the National Interagency Fire Center and modified for Idaho Power’s service area
in Idaho and Oregon.
This tool is designed to support operational decision-making to reduce fire threats and risks.
The FPI converts environmental, statistical, and scientific data into an easily understood
forecast of the short-term fire threat that could exist for different geographical areas across
Idaho Power’s service area. The FPI is issued for a seven-day period during wildfire season to
provide for planning of upcoming events by Idaho Power personnel and contractors.
The FPI reflects key variables, such as the state of native vegetation across the service area,
fuels (ratio of dead fuel moisture component to live fuel moisture component), and weather
(sustained wind speed and dew point depression). Each of these variables is assigned a numeric
value, and those individual numeric values are summed to generate a Fire Potential value from
zero to 16. That final value indicates the degree of fire threat expected for each of the seven
days included in the forecast. Green, Yellow, or Red FPI scores reflect low, medium, and high
levels of weather-related risk, respectively. The FPI is discussed in greater detail, along with the
company’s full list of wildfire mitigation measures, in Idaho Power’s Wildfire Mitigation Plan
(WMP). The WMP is updated annually in advance of each fire season.21
Wildfires can cause a wide range of direct and indirect harms, from community damage to air
quality and wildlife degradation, reduced recreation access, and power outages. Idaho Power’s
attention to safety and reliability starts with the quality of its equipment, such as power lines,
poles, substations and transformers. The company designs and builds its equipment to meet or
exceed industry standards, monitors the ongoing equipment condition, and works hard to
maintain the company’s infrastructure.
With these goals in mind, Idaho Power has implemented an enhanced vegetation management
program to keep trees and other plants away from its lines. The company’s vegetation
management efforts are applied across its service area and its transmission corridors. This work
includes pruning and, if necessary, removing trees, with a higher level of attention in identified
zones where wildfire risk is highest. Additionally, in Idaho, a sterilant is applied around select
power poles to keep plants from growing nearby. These actions have proved successful in
saving poles and lines during wildfire events.

21 docs.idahopower.com/pdfs/Safety/2022Wildfire%20MitigationPlan.pdf
3. Clean Energy & Climate Change
Page 40 2023 Integrated Resource Plan
Water and Hydropower Generation Risk
Factors contributing to lower hydropower generation can increase power supply costs as the
company derives a significant portion of its power supply from its hydropower facilities.
Specific programs the company has implemented to responsibly manage water use include
working with federal and state government agencies to monitor key water supply indicators
(e.g., snow water equivalent, precipitation, temperature); conducting cloud seeding;
monitoring surface and groundwater flows; and producing short- and long-range streamflow
forecasts to inform the company’s water operations.
Water supply within the Snake River Basin is primarily snowpack driven. To increase the
amount of snow that falls in drainages that feed the Snake River—subsequently benefiting
hydropower generation, irrigation, recreation, water quality and other uses—Idaho Power
collaboratively conducts a successful cloud-seeding program in the Snake River Basin.
Another significant source of water for Idaho Power’s hydro system is the ESPA. This aquifer
covers approximately 10,800 square miles in southern Idaho and supports significant economic
activity in the agricultural sector as well as other beneficial uses. For much of the year, the ESPA
comprises the majority of the water supply from Milner Dam to Swan Falls Dam via springs that
discharge from the aquifer to the Snake River. On an annual basis, discharge from the ESPA
accounts for 40% of the water supply for the HCC. In dry years and during baseflow conditions
in the summer, the aquifer accounts for well over 50% of the water supply for Idaho Power’s
hydroelectric system. The aquifer has been in a state of general decline over the past several
decades. Climate change and other developments on the ESPA could increase demands on
groundwater resources, which could ultimately impact hydropower production on
Idaho Power’s system.
Idaho Power stays current on the rapidly developing climate change research in the Pacific
Northwest. The recently completed River Management Joint Operating Committee Second
Edition Long-Term Planning Study climate change study shows the natural hydrograph could
see lower summer base flows, an earlier shift of the peak runoff, higher winter baseflows,
and an overall increase in annual natural flow volume. For Idaho Power’s hydro system,
the findings support that upstream reservoir regulation significantly dampens the effects of this
shift in natural flow to Idaho Power’s system. Furthermore, the studies indicate Idaho Power
could see July–December regulated streamflow relatively unaffected and January–June
regulated streamflow increasing over the 20-year planning period.
Policy Risk
Changes in legislation, regulation, and government policy may have a material impact on
Idaho Power’s business in the future. Specific legislative and regulatory proposals and recently
enacted legislation that could have a material impact on Idaho Power include, but are not
3. Clean Energy & Climate Change
2023 Integrated Resource Plan Page 41
limited to, tax reform, utility regulation, carbon-reduction initiatives, infrastructure renewal
programs, environmental regulation, and modifications to accounting and public company
reporting requirements.
Policy-related risk is addressed in a number of ways in Idaho Power’s long-term planning.
For each IRP, the company models existing policies, including known expiration or sunset dates.
Idaho Power does not model specific policies to which it is not subject. For example, the Oregon
Legislature’s HB 2021 sets emissions reduction standards for electric utilities, but Idaho Power
is exempt because it has fewer than 25,000 retail customers in its Oregon service area. As a
result, the company did not model HB 2021 requirements for Idaho Power’s portfolio.
At the time of the 2023 IRP, state-level climate policies did not exist in Idaho and did not
apply to Idaho Power in Oregon. Similarly, federal climate legislation has not been passed
by Congress. However, the company believes that climate- and emissions-related policies
will emerge in future years. To account for this expected future, the company models
multiple scenarios with varying prices on carbon. These scenarios are detailed in Chapter 9 of
this report.
Modeling Climate Risks in the IRP
While the above referenced climate-related risks are addressed and accounted for in different
operational ways by Idaho Power, the company also extended climate-related risk assessment
to the 2023 IRP. Specifically, the company conducted additional scenarios to explore the impact
these events would have on Idaho Power’s system. These scenarios are summarized below and
detailed in Chapter 9—Portfolios.
The company conducted two Rapid Electrification scenarios at the request of IRPAC members.
These scenarios were developed to determine what kind of adjustments would need to be
made to accommodate a very rapid transition toward electrification. This rapid transition
includes increasing the electric vehicle forecast and the penetration of electric heat pumps
for building heating and cooling each by a factor of ten. This aggressive forecast assumes
1.3 million electric vehicles (compared to 180,000 in the planning forecast) as well as adoption
of an 80% penetration of heat pump technology at residences within the company’s service
area by 2043. New for the 2023 IRP, this scenario also includes a bifurcation to evaluate the
impact of heat pump adoption as predominantly air source or geothermal.
The Extreme Weather scenario includes an increased demand forecast associated with extreme
temperature events and a variable supply of water from year to year.
Idaho Power assessed the risk associated with carbon regulation in two ways. First, to model
risk associated with carbon regulation, Idaho Power developed “100% Clean by 2035” and
“100% Clean by 2045” scenarios, which assume a legislative mandate to move toward 100%
3. Clean Energy & Climate Change
Page 42 2023 Integrated Resource Plan
clean energy by the years 2035 and 2045, respectively. Additionally, the company developed
portfolios that alternately assume high and zero carbon price adders to compare them to the
portfolios built under the planning case.
By considering the above scenarios and varying assumptions, the 2023 IRP was able to assess
possible risk associated with both mitigation and adaptation to climate change.

4. Idaho Power Today
2023 Integrated Resource Plan Page 43
4. IDAHO POWER TODAY
Customer Load and Growth
Twenty-five years ago in 1998,
Idaho Power served approximately
372,000 customers in Idaho and Oregon.
In 2022, Idaho Power served nearly
618,000 customers. Firm peak-hour load
increased from 2,535 MW to 3,751 MW in
2021. On June 30, 2021, the peak-hour
load reached 3,751 MW—the system
peak-hour record.
Average firm load increased from
1,491 average MW (aMW) to 1,947 aMW
in 2022 (load calculations exclude the load
from the former special contract customer Astaris, or FMC). Additional details of Idaho Power’s
historical load and customer data are shown in Figure 4.1 and Table 4.1. The data in Table 4.1
suggests each new customer adds nearly 6 kW to the peak-hour load and over 3 average kW
(akW) to the average load.
Idaho Power anticipates adding approximately 11,400 customers each year throughout the
20-year planning period. The anticipated load forecast for the entire system predicts summer
peak-hour load requirements will grow approximately 80 MW per year, and the average-energy
requirement is forecast to grow about 50 aMW per year. More detailed customer and load
forecast information is presented in Chapter 8 and in Appendix A—Sales and Load Forecast.

Figure 4.1 Historical load and customer data
0
100,000
200,000
300,000
400,000
500,000
600,000
700,000
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
1998 2000 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020 2022
Cu
s
t
o
m
e
r
s
MW
Peak Firm Load (MW)Average Firm Load (aMW)Customers

Residential construction growth in southern Idaho.
4. Idaho Power Today
Page 44 2023 Integrated Resource Plan
Table 4.1 Historical load and customer data
Year Peak Firm Load (MW) Average Firm Load (aMW) Customers1
1998 2,535 1,491 372,464
1999 2,675 1,552 383,354
2000 2,765 1,654 393,095
2001 2,500 1,576 403,061
2002 2,963 1,623 414,062
2003 2,944 1,658 425,599
2004 2,843 1,671 438,912
2005 2,961 1,661 456,104
2006 3,084 1,747 470,950
2007 3,193 1,810 480,523
2008 3,214 1,816 486,048
2009 3,031 1,744 488,813
2010 2,930 1,680 491,368
2011 2,973 1,712 495,122
2012 3,245 1,746 500,731
2013 3,407 1,801 508,051
2014 3,184 1,739 515,262
2015 3,402 1,748 524,325
2016 3,299 1,750 533,935
2017 3,422 1,807 544,378
2018 3,392 1,810 556,926
2019 3,242 1,790 570,953
2020 3,392 1,809 586,565
2021 3,751 1,881 602,983
2022 3,568 1,947 617,243
1 Year-end residential, commercial, and industrial count plus the maximum number of active irrigation customers.
2022 Energy Sources
Idaho Power’s energy sources for 2022 are shown in Figure 3.1. Even in a drought year,
hydroelectric production from company-owned projects was the largest single source of energy
at about 31% of the total. Coal contributed about 20%, and natural gas generation contributed
about 13%. Renewable resources were 10% from wind, 4% from solar, and 2% from
geothermal, biomass, and other—which combined with hydroelectric—accounted for 47% of
total generation. Market purchases accounted for the remainder of the mix at roughly 20%.
4. Idaho Power Today
2023 Integrated Resource Plan Page 45
While Idaho Power receives production from PURPA and PPA projects, the company sells the
RECs it receives associated with the production.
Existing Supply-Side Resources
Table 4.2 shows all of Idaho Power’s existing company-owned resources, plant capacities,
and general locations.
Table 4.2 Existing resources
Resource Type Capacity* (MW) Location
American Falls Hydroelectric 92.3 Upper Snake
Bliss Hydroelectric 75.0 Mid-Snake
Brownlee Hydroelectric 675.0 Hells Canyon
C.J. Strike Hydroelectric 82.8 Mid-Snake
Cascade Hydroelectric 12.4 North Fork Payette
Clear Lake Hydroelectric 2.5 South Central Idaho
Hells Canyon Hydroelectric 391.5 Hells Canyon
Lower Malad Hydroelectric 13.5 South Central Idaho
Lower Salmon Hydroelectric 60.0 Mid-Snake
Milner Hydroelectric 59.4 Upper Snake
Oxbow Hydroelectric 190.0 Hells Canyon
Shoshone Falls Hydroelectric 14.7 Upper Snake
Swan Falls Hydroelectric 27.2 Mid-Snake
Thousand Springs Hydroelectric 6.8 South Central Idaho
Twin Falls Hydroelectric 52.9 Mid-Snake
Upper Malad Hydroelectric 8.3 South Central Idaho
Upper Salmon A & B Hydroelectric 34.5 Mid-Snake
Jim Bridger Coal 707.0 Southwest Wyoming
North Valmy Coal 134.0 North Central Nevada
Langley Gulch** Natural Gas—CCCT 299.0 Southwest Idaho
Bennett Mountain** Natural Gas—SCCT 176.0 Southwest Idaho
Danskin** Natural Gas—SCCT 241.0 Southwest Idaho
Salmon Diesel Diesel 5.5 Eastern Idaho
Hemingway BESS Battery Energy Storage 80.0 Southwest Idaho
Black Mesa BESS Battery Energy Storage 40.0 Southwest Idaho
Total existing plant capacity 3,481.3
*Capacity as reported in FAC-008 Normal Ratings
** Capacity (MW) at International Standards Organization (ISO) reference temperature of 59F
The following sections describe Idaho Power’s existing supply-side resources and long-term
power purchase contracts.
4. Idaho Power Today
Page 46 2023 Integrated Resource Plan
Hydroelectric Facilities
Idaho Power operates 17 hydroelectric projects on the Snake River and its tributaries. Together,
these hydroelectric facilities provide a total nameplate capacity of 1,798.8 MW and median
annual generation equal to approximately 820 aMW, or 7.2 million MWh (1991–2020).
Hells Canyon Complex
The backbone of Idaho Power’s hydroelectric system is the HCC in the Hells Canyon reach of the
Snake River. The HCC consists of Brownlee, Oxbow, and Hells Canyon dams and the associated
generation facilities. In a normal water year, the three plants provide approximately 70% of
Idaho Power’s annual hydroelectric generation and enough energy to meet over 30% of the
energy demand of retail customers. Water storage in Brownlee Reservoir also enables the HCC
projects to provide the major portion of Idaho Power’s peaking and load following capability.
Idaho Power operates the HCC to comply with the existing annual FERC license, as well as
voluntary arrangements to accommodate other interests, such as recreational use and
environmental resources. Among the arrangements is the Fall Chinook Program,
voluntarily adopted by Idaho Power in 1991 to protect the spawning and incubation of fall
Chinook salmon below Hells Canyon Dam. The fall Chinook salmon is currently listed as
threatened under the ESA.
Brownlee Reservoir is the main HCC reservoir and Idaho Power’s only reservoir with
significant active storage. Brownlee Reservoir has 101 vertical feet of active storage capacity,
which equates to approximately 1 million acre-feet of water. Both Oxbow and Hells Canyon
reservoirs have significantly smaller active storage capacities—approximately 0.5% and 1% of
Brownlee Reservoir’s volume, respectively.
Brownlee Reservoir is a year-round, multiple-use resource for Idaho Power and the Pacific
Northwest. Although its primary purpose is to provide a stable power source, Brownlee
Reservoir is also used for system flood risk management, recreation, and the benefit of fish and
wildlife resources.
Brownlee Dam is one of several Pacific Northwest dams coordinated to provide springtime
flood risk management on the lower Columbia River. Idaho Power operates the reservoir in
accordance with flood risk management guidance from the United States Army Corps of
Engineers as required in the existing FERC license.
After flood risk management requirements have been met in late spring, Idaho Power attempts
to refill the reservoir to meet peak summer electricity demands and provide suitable habitat for
spawning bass and crappie.
The United States Bureau of Reclamation releases water from its storage reservoirs in the Snake
River Basin above Brownlee Reservoir to augment flows in the lower Snake River to help
4. Idaho Power Today
2023 Integrated Resource Plan Page 47
anadromous fish migrate past the Federal Columbia River Power System (FCRPS) projects.
The releases are part of the flow augmentation implemented by the 2008 FCRPS biological
opinion. Much of the flow augmentation water travels through Idaho Power’s middle Snake
River (mid-Snake) projects, with all the flow augmentation eventually passing through the HCC
before reaching the FCRPS projects. Idaho Power works with federal and state partners and
other stakeholders to pass these federal flow augmentation releases without delay through
the HCC.
As part of a 2005 interim HCC relicensing agreement, Idaho Power agreed to provide up to
237,000 acre-feet of water from Brownlee Reservoir for flow augmentation, in addition to the
federal flow augmentation releases. Idaho Power uses its best efforts to hold Brownlee
Reservoir at or near full elevation (approximately 2,077 feet above mean sea level) through
June 20. Thereafter, Brownlee Reservoir is drafted to an elevation of 2,059 feet (releasing up to
237,000 acre-feet) by August 7. Although the portion of the 2005 interim agreement relating to
flow augmentation releases has expired, Idaho Power continues to provide these flow
augmentation releases annually. Idaho Power anticipates the Brownlee flow augmentation
targets to be included in the upcoming FERC license.
Brownlee Reservoir’s releases are managed to maintain operationally stable flows below Hells
Canyon Dam in the fall because of the Fall Chinook Program. The stable flow is set at a level to
protect fall Chinook spawning nests. During fall Chinook operations, Idaho Power attempts to
refill Brownlee Reservoir by the first week of December to meet winter loads. The Fall Chinook
Program spawning flows establish the minimum flow below Hells Canyon Dam throughout the
winter until the fall Chinook fry emerge in the spring.
Upper Snake and Mid-Snake Projects
Idaho Power’s hydroelectric facilities upstream from the HCC include the Cascade, Swan Falls,
C.J. Strike, Bliss, Upper and Lower Salmon, Upper and Lower Malad, Thousand Springs, Clear
Lake, Shoshone Falls, Twin Falls, Milner, and American Falls projects. Although the upstream
projects typically follow run-of-river (ROR) operations, a small amount of peaking and
load-following capability exists at the Lower Salmon, Bliss, C.J. Strike, and Swan Falls projects.
Water-Lease Agreements
Idaho Power views the rental of water for delivery through its hydroelectric system as a
potentially cost-effective power-supply alternative. Water leases that allow the company to
request delivery when the hydroelectric production is needed are especially beneficial.
Acquiring water through the Idaho Department of Water Resources’ Water Supply Bank22
also helps the company improve water-quality and temperature conditions in the Snake River

22 idwr.idaho.gov/iwrb/programs/water-supply-bank/.
4. Idaho Power Today
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as part of ongoing relicensing efforts associated with the HCC. The company does not currently
have any standing water lease agreements. However, single-year leases from the Upper Snake
Basin are occasionally available, and the company plans to continue to evaluate potential water
lease opportunities in the future.
Cloud Seeding
During the 2021 Idaho legislative session, HB 266, related
to cloud seeding activities throughout the state, was
passed. The legislation states that cloud seeding is in the
public interest and that augmenting water supplies
provides significant benefits in the areas of drought
mitigation, water rights protection, municipal and
business development, water quality, recreation, and fish
and wildlife. The legislation instructs the IWRB to
authorize cloud-seeding in basins throughout the state
that experience depleted or insufficient water supplies.
In addition, the legislation allows the IWRB to use state
funds to support cloud seeding programs within the state
where water supply is not sufficient. Following the
enactment of the new legislation, all cloud-seeding
programs in which Idaho Power is involved were granted
authorization by the IWRB.
Idaho Power has a long history of cloud-seeding beginning in 2003. The program originally
increased snowpack in the south and middle forks of the Payette River watershed.
The company then expanded this program to the Upper Snake River Basin above Milner Dam.
Idaho Power has continued to collaborate with the IWRB and water users in the Upper Snake,
Boise, and Wood River basins to expand the target area to include those watersheds.
Idaho Power seeds clouds by introducing silver iodide into winter storms. Cloud seeding
increases precipitation from passing winter storm systems. If a storm has abundant
supercooled liquid water vapor and appropriate temperatures and winds, conditions are
optimal for cloud seeding to increase precipitation. Idaho Power uses two methods to
seed clouds:
1. Remotely operated ground generators releasing silver iodide at high elevations
2. Modified aircraft burning flares containing silver iodide
Benefits of either method vary by storm, and the combination of both methods provides the
most flexibility to successfully introduce silver iodide into passing storms. Minute water

Cloud seeding ground generator.
4. Idaho Power Today
2023 Integrated Resource Plan Page 49
particles within the clouds freeze on contact with the silver iodide particles and eventually grow
and fall to the ground as snow downwind.
Silver iodide particles are very efficient ice nuclei, allowing minute quantities to have an
appreciable increase in precipitation. It has been used as a seeding agent in numerous western
states for decades.23 Analyses conducted by Idaho Power since 2003 indicate the annual
snowpack in the Payette River Basin increased between 1 and 22% annually, with an annual
average of 11.5%. Idaho Power estimates cloud seeding, on average, provides an additional
633,000 acre-feet in the Upper Snake River, 112,000 acre-feet in the Wood River Basin,
273,000 acre-feet in the Boise Basin, and 223,000 acre-feet in the Payette River Basin, for a
total average annual benefit of 1,240,000 acre-feet. At program build-out (including additional
aircraft and remote ground generators), Idaho Power estimates additional runoff, on average,
from the Payette, Boise, Wood, and Upper Snake projects will total approximately
1,650,000 acre-feet. The additional water from cloud seeding helps fuel the hydropower
system along the Snake River.
The program Seeded and Natural Orographic Wintertime Clouds: the Idaho Experiment
(SNOWIE) was a joint project between the National Science Foundation and Idaho Power.
As part of the SNOWIE project, researchers from the universities of Wyoming, Colorado,
and Illinois used Idaho Power’s operational cloud seeding project, meteorological tools,
and equipment to identify changes within wintertime precipitation after cloud seeding had
taken place. Multiple scientific papers have already been published,24 with more planned for
submission about the effects and benefits of cloud seeding.
Idaho Power continues to collaborate with the State of Idaho and water users to augment
water supplies with cloud seeding. The program in the central mountains (Payette, Boise,
and Wood River basins) includes 32 remote-controlled, ground-based generators and
two aircraft. The Upper Snake River Basin program includes 25 remote-controlled, ground-
based generators and one aircraft operated by Idaho Power targeting the Upper Snake and
Henry’s Fork, as well as 25 manual, ground-based generators operated by a coalition of
stakeholders in the Upper Snake.

23 dri.edu/making-it-snow/.
24 French, J. R., and Coauthors, 2018: Precipitation formation from orographic cloud seeding. Proc. Natl. Acad. Sci.
USA, 115, 1168–1173, doi.org/10.1073/pnas.1716995115.
Tessendorf, S.A., and Coauthors, 2019: Transformational approach to winter orographic weather modification
research: The SNOWIE Project. Bull. Amer. Meteor. Soc., 100, 71–92,
journals.ametsoc.org/doi/full/10.1175/BAMS-D-17-0152.1.
4. Idaho Power Today
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Coal Facilities
Jim Bridger
Idaho Power owns one-third, or 707 MW25 of net dependable capacity, of the Jim Bridger coal
power plant located near Rock Springs, Wyoming. The Jim Bridger plant consists of four
generating units. PacifiCorp has two-thirds ownership and is the operator of the Jim Bridger
facility. PacifiCorp and Idaho Power are in the process of converting units 1 and 2 from coal to
gas by spring 2024. For additional details on the Jim Bridger plant, refer to Chapter 5—
Future Supply-Side Generation and Storage Resources. For the 2023 IRP, Idaho Power used the
AURORA model’s capacity expansion capability to evaluate a range of exit dates and gas
conversion possibilities for the company’s participation in the Jim Bridger units 3 and 4.
North Valmy
Idaho Power and NV Energy are each 50% co-owners of the North Valmy coal power plant
located near Winnemucca, Nevada. NV Energy is the operator of the North Valmy facility.
Idaho Power’s participation in the coal operations of North Valmy Unit 1 ceased at year-end
2019. Idaho Power currently participates 50%, or 134 MW of net dependable capacity, in the
second generating unit at North Valmy.
In early 2023, NV Energy and Idaho Power began discussing a conversion of North Valmy units 1
and 2 to natural gas fired operation in 2026. As such, the 2023 IRP analysis encompasses the
conversion of these two units with the details contained in Chapter 5—Future Supply-Side
Generation and Storage Resources.
Natural Gas Facilities and Diesel Units
Bennett Mountain
Idaho Power owns and operates the Bennett Mountain plant, which consists of a 176-MW26
Siemens–Westinghouse 501F natural gas simple-cycle combustion turbine (SCCT) located east
of the Danskin plant in Mountain Home, Idaho.
Danskin
The Danskin facility is located northwest of Mountain Home, Idaho. Idaho Power owns and
operates one 163-MW27 Siemens 501F and two 39-MW27 Siemens–Westinghouse W251B12A
SCCTs at the facility. The two smaller turbines were installed in 2001, and the larger turbine was
installed in 2008. After an upgrade anticipated for fall 2023, Danskin’s larger unit will have an
increased capacity of 176 MW27.

25 MW nameplate = net dependable capacity.
26 Generating capacity (MW) at ISO reference temperature of 59 degrees Fahrenheit. Unit by unit capacity varies
with ambient conditions and is higher in the winter and lower at peak summer loads.
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2023 Integrated Resource Plan Page 51
Langley Gulch
Idaho Power owns and operates the Langley Gulch plant, which uses a nominal 299-MW27
natural gas combined-cycle combustion turbine (CCCT). The plant consists of one 186-MW27
Siemens STG-5000F4 combustion turbine and one 93-MW27 Siemens SST-700/SST-900 reheat
steam turbine. The plant also has duct burners that provide an additional 20 MW27 of
achievable capacity. The Langley Gulch plant, located south of New Plymouth in Payette
County, Idaho, became commercially available in June 2012.
Diesel
Idaho Power owns and operates two diesel generation units in Salmon, Idaho. The Salmon units
have a combined generator nameplate rating of 5.5 MW and are operated during emergency
conditions, primarily for voltage and load support.
Battery Energy Storage Systems
Utility-scale Battery Energy Storage Systems (BESS) have come to hold a critical role for
Idaho Power as the company continues to work to provide reliable and affordable energy in the
face of rapidly growing demand for electricity. Utility-scale BESS will also assist in forging
Idaho Power’s path to reach its established goal to provide 100% clean energy by 2045.
Hemingway BESS
In summer 2023, an 80-MW BESS was installed at the company’s Hemingway substation in
Owyhee County. The company’s BESS at Hemingway is designed to discharge stored energy at a
maximum discharge rate of 80 MW, and has a total energy storage capacity of 320 MWh.
In 2024, the company plans to install an additional 36-MW/144-MWh BESS. The total BESS
capacity at Hemingway will be 116 MW/464 MWh.
Black Mesa BESS
A 40-MW/160-MWh BESS is being built adjacent to the 40-MW Black Mesa Solar facility in
Elmore County and is expected to come online in September 2023.
Distribution-Connected Storage
Four different distribution-connected storage projects are scheduled to be online in fall 2023.
The distribution-connected storage projects serve a dual purpose. In addition to providing the
system with capacity, the project installations will assist in alleviating peak load as they are
located in stations where transformer upgrades can be deferred. The four projects are located
at the Filer, Weiser, Melba and Elmore substations for a combined capacity of 11 MW.
Franklin BESS
A 60-MW/240-MWh BESS is planned for installation adjacent to the upcoming 100-MW Franklin
Solar facility in Twin Falls County. The BESS project is scheduled to come online in 2024.
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Happy Valley BESS
A 77-MW/308-MWh MW BESS is planned for installation at the company’s Happy Valley
substation in Canyon County. The 77-MW BESS is scheduled to come online in 2025.
Customer Generation Service
Idaho Power’s on-site generation services allow customers to generate power on their property
and connect to Idaho Power’s system. For participating customers, the energy generated is first
consumed on the property itself, while excess energy flows on to the company’s grid.
Most customer generators use solar PV systems. As of August 2023, there were 16,570 solar PV
systems interconnected through the company’s customer generation tariffs with a total
capacity of 153.6 MW. At that time, the company had received completed applications for an
additional 986 solar PV systems, representing an incremental capacity of 12.9 MW. For further
details regarding customer-owned generation resources interconnected through the company’s
on-site generation and net metering services, see tables 4.3 and 4.4.
Table 4.3 Customer generation service customer count as of August 2023
Resource Type Active Active-Pending Expansion Application Received Grand Total
Idaho Total 16,354 47 966 17,367
Hydro 12 12
Other 3 3
Solar 16,312 47 966 17,325
Wind 27 27
Oregon Total 216 20 236
Solar 216 20 236
Grand Total 16,570 47 986 17,603

Table 4.4 Customer generation service generation capacity (MW) as of August 2023
Resource Type Active Active-Pending Expansion Application Received1 Grand Total
Idaho 150.4 0.3 12.7 163.4
Hydro 0.2 0.0 0.0 0.2
Other 0.6 0.0 0.0 0.6
Solar 149.5 0.3 12.7 162.5
Wind 0.1 0.0 0.0 0.1
Oregon 3.2 0.0 0.3 3.4
Solar 3.2 0.0 0.3 3.4
Grand Total 153.6 0.3 12.9 166.8
1Total may not sum due to rounding.
4. Idaho Power Today
2023 Integrated Resource Plan Page 53
Public Utility Regulatory Policies Act
As of January 1, 2023, Idaho Power had 133 PURPA contracts with independent developers for
approximately 1,211 MW of nameplate capacity. These PURPA contracts are for hydroelectric
projects, cogeneration projects, wind projects, solar projects, anaerobic digesters, landfill gas,
wood-burning facilities, and various other small, renewable-power generation facilities. Of the
133 contracts, 129 were online as of January 1, 2023, with a cumulative nameplate rating of
approximately 1,136 MW. Figure 4.2 shows the percentage of the total PURPA nameplate
capacity of each resource type under contract.

Figure 4.2 PURPA contracts by resource type
Idaho Power cannot predict the level of future PURPA development; therefore, only signed
contracts are accounted for in Idaho Power’s resource planning process. Details on signed
PURPA contracts, including capacity and contractual delivery dates, are included in
Appendix C—Technical Report.
Non-PURPA Power Purchase Agreements
Elkhorn Wind
In February 2007, the IPUC approved a PPA with Telocaset Wind Power Partners, LLC,
for 101 MW of nameplate wind generation from the Elkhorn Wind Project located in
northeastern Oregon. The Elkhorn Wind Project began commercial operations in
December 2007. Under the PPA, Idaho Power receives all the RECs from the project.
Idaho Power’s contract with Telocaset Wind Power Partners expires December 2027.
Biomass 2%CoGen 2%
Solar 28%
Hydro 13%
Wind 55%
4. Idaho Power Today
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Raft River Energy
In January 2008, the IPUC approved a PPA with Raft River Energy I, LLC, for approximately
13 MW of nameplate generation from the Raft River Geothermal Power Plant Unit 1 located in
southern Idaho. The Raft River project began commercial operations in October 2007 under a
PURPA contract with Idaho Power that was canceled when the new PPA was approved by the
IPUC. Idaho Power is entitled to 51% of all RECs generated by the project for the remaining
term of the agreement. Idaho Power’s contract with Raft River Energy I expires in April 2033.
Neal Hot Springs
In May 2010, the IPUC approved a PPA with USG Oregon, LLC, for approximately 27 MW of
nameplate generation from the Neal Hot Springs Unit 1 geothermal project located in eastern
Oregon. The Neal Hot Springs Unit 1 project achieved commercial operation in November 2012.
Under the PPA, Idaho Power receives all RECs from the project. Idaho Power’s contract with
USG Oregon expires in November 2037.
Jackpot Solar
In 2019, the IPUC approved a PPA with Jackpot Solar, LLC, for 120 MW of nameplate PV
generation located north of the Idaho–Nevada state line near Rogerson, Idaho. Under the
terms of the PPA, Idaho Power will receive all RECs from the project. Jackpot Solar began
commercial operations in December 2022.
Black Mesa Solar
In 2022, the IPUC approved a PPA with Black Mesa Energy, LLC, for the 40 MW Black Mesa Solar
facility, the output of which is dedicated for Micron’s renewable energy use under the
company’s CEYW program. Black Mesa Solar began commercial operations on June 1, 2023,
and is one of the first projects under Idaho Power’s CEYW—Construction offering, enabling
large customers to partner with Idaho Power on new, dedicated renewable energy resources to
meet business sustainability goals. The RECs generated by the project will be retired on
Micron’s behalf.
Franklin Solar
In January 2023, Idaho Power and Franklin Solar, LLC entered into a PPA for a 100 MW solar
project, Franklin Solar, to be located in Twin Falls County, Idaho. The Franklin Solar project is
scheduled to come online in 2024.
Kuna Storage
In April 2023, Idaho Power and Cedar Holdco, LLC entered into an agreement under which
Cedar Holdco, LLC will build, own, and maintain a 150-MW/600-MWh BESS facility in Kuna,
Idaho. Under the agreement, the BESS facility will provide 150 MW of capacity on
Idaho Power’s system for 20 years, and Idaho Power will have the exclusive right to charge and
4. Idaho Power Today
2023 Integrated Resource Plan Page 55
discharge the project in exchange for a monthly payment. The Kuna BESS is scheduled to come
online in 2025.
Clatskanie Energy Exchange
In September 2009, Idaho Power and the Clatskanie PUD in Oregon entered into an energy
exchange agreement. Under the agreement, Idaho Power receives the energy as it is generated
from the 19.5 MW nameplate capacity power plant at Arrowrock Dam on the Boise River;
in exchange, Idaho Power provides the Clatskanie PUD energy of an equivalent value
delivered seasonally, primarily during months when Idaho Power expects to have surplus
energy. The agreement extends through 2025. The Arrowrock project produces an average of
71,000 MWh annually.
Power Market Purchases and Sales
Idaho Power relies on regional power markets to supply a significant portion of energy and
capacity needs during certain times of the year. Idaho Power leverages the regional power
market to make purchases during peak-load periods. The existing transmission system is used
to import these power purchases. Regional power markets benefit Idaho Power customers
through decreased energy costs and increased reliability.
Transmission Import Rights
Idaho Power’s interconnected transmission system facilitates market purchases to access
resources to serve load. Five transmission paths connect Idaho Power to neighboring utilities:
1. Idaho–Northwest (Path 14)
2. Idaho–Nevada (Path 16)
3. Idaho–Montana (Path 18)
4. Idaho–Wyoming (Path 19)
5. Idaho–Utah (Path 20)
Idaho Power’s interconnected transmission facilities were all jointly developed with other
entities and act to meet the needs of the interconnecting participants. Idaho Power owns
various amounts of capacity across each transmission path. The paths and their associated
capacity are further described in Chapter 7—Transmission Planning. Idaho Power reserves
portions of its transmission capacity to import energy for load service (network set-aside).
Set-aside capacity, along with existing contractual obligations, consumes nearly all of
Idaho Power’s import capacity on all paths (see Table 7.1 in Chapter 7—Transmission Planning).
Idaho Power continually evaluates market opportunities to meet near-term needs. Idaho Power
currently has long-term wholesale energy market purchases for summer peak hours through
2024 for 151 MW.
5. Future Supply-Side Generation and Storage Resources
Page 56 2023 Integrated Resource Plan
5. FUTURE SUPPLY-SIDE GENERATION AND
STORAGE RESOURCES
Generation Resources
Supply-side resources include traditional
generation, renewable, and storage
resources. As discussed in Chapter 6,
demand-side programs are an essential
and valuable component of Idaho Power’s
resource strategy. The following sections
describe the supply-side resources and
energy-storage technologies considered
when Idaho Power developed and
analyzed the resource portfolios for the
2023 IRP. Not all supply-side resources
described in this section were included in the modeling, but every resource described
was considered.
The primary source of cost information for the 2023 IRP is the 2022 Annual Technology Baseline
report released by the National Renewable Energy Laboratory.27 Other information sources
were relied on or considered on a case-by-case basis depending on the credibility of the source
and the recency of the information. For a full list of the resources and cost information
modeled in the 2023 IRP, refer to Chapter 8.
Resource Contribution to Peak
In the 2021 IRP, Idaho Power adopted the ELCC methodology, a reliability-based metric used to
assess the capacity contribution of variable and energy-limited resources. The company has
since expanded and refined this analysis for the 2023 IRP using Idaho Power’s internally
developed RCAT. 28 The ELCC of a resource is first determined by calculating the perfect
generation unit size required to achieve a LOLE of 0.1 event-days per year. Then, the resource
being evaluated is added to the system, and the new perfect generation unit size required is
calculated. The ELCC of a given resource is equal to the difference in the size of the perfect
generator units divided by the resource’s nameplate.
To account for weather variations in the data, six different test years were used. The results
from each of the test years were then averaged to produce a singular contribution to peak for

27 atb.nrel.gov/.
28 Billinton, R. and R. Allan, ‘Power system reliability in perspective’, IEE J. Electronics Power.

Hemingway Storage.
5. Future Supply-Side Generation and Storage Resources
2023 Integrated Resource Plan Page 57
each specified variable and energy-limited resource. ELCC values for existing and future
resources, as well as more information regarding the methodologies and calculations used for
this analysis, can be found in the Loss of Load Expectation section of Appendix C—
Technical Report.
Renewable Resources
Renewable energy resources serve as the foundation of Idaho Power’s existing portfolio. The
company emphasizes a long and successful history of prudent renewable resource
development and operation, particularly related to its fleet of hydroelectric generators. In the
2023 IRP, a variety of renewable resources were included in all of the portfolios analyzed.
Renewable resources are discussed in general terms in the following sections.
Hydroelectric
Low-cost hydroelectric power is the foundation of Idaho Power’s electrical generation
fleet. Small-scale hydroelectric projects have been extensively developed in southern
Idaho on irrigation canals and other sites, many of which have PPAs with Idaho Power.
Because additional small-scale hydro resources are not expected to see significant further
development, they have not been included as a selectable resource in the LTCE modeling.
Solar
The primary types of solar generation technology are utility-scale PV and distributed PV
(primarily customer-owned). Solar PV converts sunlight directly into electrical energy.
Direct current energy passes through an inverter, converting it to alternating current that
can then be used on-site or sent to the grid.
For Idaho Power’s cost estimates, operating parameters, and ELCC calculations for utility-scale
PV resources, see the Supply-Side Resource and Loss of Load Expectation sections of
Appendix C—Technical Report.
Targeted Grid Storage
Since the 2021 IRP, Idaho Power has moved forward with the installation of four
distribution-connected storage projects with the intent to defer growth-driven transmission
and distribution (T&D) system investments. These projects are shown in Table 5.1
Table 5.1 Targeted grid storage projects
Location Season/Year Capacity (MW) Energy (MWh) Estimated Deferral Years
Filer Fall 2023 2 8 5
Weiser Fall 2023 3 12 10
Melba Fall 2023 2 8 4
Elmore Fall 2023 4 16 9

5. Future Supply-Side Generation and Storage Resources
Page 58 2023 Integrated Resource Plan
It is anticipated that a locational value of T&D deferral, estimated at 10% of the utility-scale
storage cost, may apply to an annual average of 5 MW of storage over the 20-year IRP forecast
for a total potential of 100 MW of distribution-connected storage. This resource option was
added to the AURORA LTCE model.
While solar can occasionally be used to offset T&D investment, the instances are infrequent.
Batteries can provide T&D deferral value and are a cost-effective addition to the system as load
continues to increase. Batteries are also more practical to defer T&D investment because the
land requirement is lower than that of solar or solar plus battery installations.
Geothermal
The basic principle of geothermal generation is that it converts heat from the earth into
electrical energy. Based on exploration to date in southern Idaho, geothermal development has
potential in Idaho Power’s service area; however, the potential for geothermal generation in
southern Idaho remains somewhat uncertain. The time required to discover and prove
geothermal resource sites is extensive; for this reason, Idaho Power has modeled the first
selectable date for geothermal as 2030.
For Idaho Power’s cost estimates and operating parameters for geothermal generation, see the
Supply-Side Resource section of Appendix C—Technical Report.
Wind
Wind turbines collect and transfer energy from high wind areas into electricity. A typical wind
development consists of numerous wind turbines, with each turbine ranging in size from 1 to
5 MW. Most potential wind sites in southern Idaho lie between the south-central and the
southeastern part of the state.
Upon comparison with other renewable energy alternatives, wind energy resources are well
suited for the Intermountain and Pacific Northwest regions, as demonstrated by the large
number of existing projects.
For Idaho Power’s cost estimates, operating parameters, and ELCC calculations for wind
resources, see the Supply-Side Resource and Loss of Load Expectation sections of Appendix C—
Technical Report.
Biomass
The 2023 IRP includes biomass generation as a resource option. There are currently small
quantities of biomass in Idaho Power’s service area, for example, multiple anaerobic digesters
have been built in southern Idaho due to the size and proximity of the dairy industry and the
large quantity of fuel available. Biomass in the 2023 IRP is modeled as fuel agnostic and not
5. Future Supply-Side Generation and Storage Resources
2023 Integrated Resource Plan Page 59
something specific like a horde of hamsters converting food waste pellets to mechanical energy
using small flywheel cages.
For Idaho Power’s cost estimates and operating parameters for a new biomass plant, see the
Supply-Side Resource section of Appendix C—Technical Report.
Thermal Resources
Conventional thermal generation resources are essential to providing dispatchable capacity,
which is critical in maintaining the reliability of a bulk-electrical power system and integrating
renewable energy into the grid. Conventional thermal generation technologies include natural
gas, hydrogen, nuclear, and coal resources.
Natural Gas Resources
Natural gas resources burn natural gas in a combustion turbine to generate electricity.
CCCTs are commonly used for baseload energy, while faster ramping but less-efficient SCCTs
are used to generate electricity during peak-load periods, or times of low variable resource
output. Additional details related to the characteristics of both types of natural gas resources
are presented in the following sections. CCCT and SCCT resources are typically sited near
existing natural gas transmission pipelines. All of Idaho Power’s existing natural gas generators
are located adjacent to major natural gas pipelines. All new natural gas resources are
hydrogen convertible.
Simple-Cycle Combustion Turbines
SCCT natural gas technology involves pressurizing air that is then heated by burning gas in fuel
combustors. The hot, pressurized air expands through the blades of the turbine that connects
by a shaft to the electric generator. Designs range from larger industrial machines at 80 to
200 MW to smaller machines derived from aircraft technology. SCCTs have a lower thermal
efficiency than CCCT resources and are typically less economical on a per-MWh basis. However,
SCCTs can respond more quickly to grid fluctuations.
SCCT generating resources remain a viable option to meet demand during critical periods.
The SCCT plants may also be dispatched based on economics during times when regional
energy prices peak due to weather, fuel supply shortages, or other external grid influences.
For Idaho Power’s cost estimates and operating parameters for a SCCT unit, see the Supply-Side
Resource section of Appendix C—Technical Report.
Combined-Cycle Combustion Turbines
CCCT technology benefits from a relatively low initial capital cost compared to other baseload
resources; has high thermal efficiencies; is highly reliable; provides significant operating
flexibility; and when compared to coal, emits fewer emissions and requires fewer pollution
5. Future Supply-Side Generation and Storage Resources
Page 60 2023 Integrated Resource Plan
controls. Modern CCCT facilities are highly efficient and can achieve efficiencies of
approximately 60% under ideal conditions.
A traditional CCCT plant consists of a natural gas turbine/generator equipped with a heat
recovery steam generator to capture waste heat from the turbine exhaust. The heat recovery
steam generator uses waste heat from the combustion turbine to drive a steam turbine
generator to produce additional electricity. In a CCCT plant, heat that would otherwise be
wasted to the atmosphere is reclaimed and used to produce additional power beyond that
typically produced by an SCCT. New CCCT plants can be constructed, or existing SCCT plants can
be converted to combined cycle units by adding a heat recovery steam turbine/generator.
For Idaho Power’s cost estimates and operating parameters for a CCCT resource, see the
Supply-Side Resource section of Appendix C—Technical Report.
Reciprocating Internal Combustion Engines
Reciprocating internal combustion engine generation sets are typically multi-fuel engines
connected to a generator through a flywheel and coupling. They are typically capable of
burning natural gas or other liquid petroleum products. They are mounted on a common base
frame, resulting in the ability for an entire unit to be assembled, tuned, and tested in the
factory prior to delivery to the power plant location. This production efficiency minimizes
capital costs. Operationally, reciprocating engines are typically installed in configurations with
multiple identical units, allowing each engine to be operated at its highest efficiency level once
started. As demand for grid generation increases, additional units can be started sequentially or
simultaneously. This configuration also allows for relatively inexpensive future expansion of the
plant capacity. Reciprocating engines provide unique benefits to the electrical grid. They are
extremely flexible because they can provide ancillary services to the grid in just a few minutes.
Engines can go from a cold start to full load in 10 minutes. Given the large overlap of
capabilities with SCCTs, reciprocating engines were considered for, but not part of, the LTCE
modeling in the 2023 IRP.
Combined Heat and Power
Combined heat and power (CHP), or cogeneration, typically refers to simultaneous production
of both electricity and useful heat from a single plant. CHP plants are typically located at,
or near, commercial or industrial facilities capable of using the heat generated in the process.
These facilities are sometimes referred to as the steam host. Generation technologies
frequently used in CHP projects are gas turbines or reciprocating engines with a
heat-recovery unit.
The main advantage of CHP is the higher overall efficiencies that can be obtained because the
steam host can use a large portion of the waste heat that would otherwise be lost in a typical
5. Future Supply-Side Generation and Storage Resources
2023 Integrated Resource Plan Page 61
generation process. Because CHP resources are typically located near load centers, investment
in additional transmission capacity can also often be avoided.
In the evaluation of CHP resources, it became evident that CHP could be a relatively high-cost
addition to Idaho Power’s resource portfolio if the steam host’s need for steam forced the
electrical portion of the project to run at times when electricity market prices were below the
dispatch cost of the plant. To find ways to make CHP more economical, Idaho Power is
committed to working with individual customers to design operating schemes that allow power
to be produced when it is most valuable, while still meeting the needs of the steam host’s
production process. This would be difficult to model for the IRP because each potential CHP
opportunity could be substantially different. While not expressly analyzed in the 2023 IRP,
Idaho Power will continue to evaluate CHP projects on an individual basis as they are proposed
to the company.
Coal Conversion to Natural Gas
There are two primary methods to convert an existing coal power plant to natural gas. The first,
less-common method is to fully retire the existing coal facility and replace it with either a CCCT
or SCCT natural gas facility. This method removes the existing coal boiler, turbine, generator,
and all coal support equipment, but uses the already existing transmission and interconnection
infrastructure. The second, more-common method is to convert the existing steam boiler to use
natural gas instead of coal.29 In either case, the conversion process can create numerous
benefits, including reduced emissions, reduced plant Operations and Maintenance (O&M)
expenses, reduced capital costs, and increased flexibility. For purposes of the 2023 IRP,
Idaho Power has modeled only the second method in which a specific coal facility’s existing
steam boiler is converted to use natural gas instead of coal.
Jim Bridger Coal to Natural Gas Conversion
Jim Bridger units 1 and 2 will be converted to natural gas in 2024, as determined in the
2021 IRP. Units 3 and 4 continue to operate on coal with the currently installed Selective
Catalytic Reduction (SCR).
For the 2023 IRP, Idaho Power used AURORA’s LTCE model to determine the best Bridger
operating option specific to Idaho Power’s system, subject to the following constraints:
• Units 1 and 2—Convert to natural gas in 2024 and operate through 2037
• Unit 3—

29 eia.gov/todayinenergy/detail.php?id=44636.
5. Future Supply-Side Generation and Storage Resources
Page 62 2023 Integrated Resource Plan
o Operate on coal through 2029, convert to natural gas in 2030, and operate
through 2037
o Do not convert to natural gas and exit the unit at the end of 2029, or no earlier
than the end of 2025
• Unit 4—
o Operate on coal through 2029, convert to natural gas in 2030, and operate
through 2037
o Do not convert to natural gas and exit the unit at the end of 2029, or no earlier
than the end of 2025
Costs associated with continued capital investments and early exit or conversion were included
in the analysis. If the units were converted to natural gas, changes to the fuel costs and
operating expenses were modeled to accurately capture the change in fuel. For those scenarios
where units 3 and 4 convert to natural gas, they are assumed to operate through their useful
life and are exited in 2037.
The Jim Bridger units provide system reliability benefits, particularly related to the company’s
flexible ramping capacity needs for EIM participation and reliable system operations. The need
for flexible ramping is simulated in the AURORA modeling.
North Valmy Coal to Natural Gas Conversion
As co-owners of the North Valmy Generating Station, NV Energy and Idaho Power aligned on
2026 as the year to evaluate the coal to gas conversion for units 1 and 2.
For the 2023 IRP, Idaho Power used AURORA’s LTCE model to determine the best North Valmy
operating option specific to the company’s system, subject to the following constraints:
• Allow for the exit of Unit 2 at the end of 2025 or the conversion to natural gas with SCR
in 2026.
• If the conversion of Unit 2 to natural gas is selected, then the conversion of Unit 1 with
SCR becomes available to the model and it can either select to remain out of Unit 1 or to
convert it to natural gas operation.
In the event that the model selects any conversion to natural gas option, the company also
evaluated early retirement dates.
Green Hydrogen
Green hydrogen is created from renewable electricity and water by electrolysis and has no
carbon emissions.
5. Future Supply-Side Generation and Storage Resources
2023 Integrated Resource Plan Page 63
Since the 2021 IRP, Idaho Power has continued to monitor hydrogen-based generation
and believes technological progress warrants its inclusion in the 2023 IRP. Based on
technology-specific research and studies, as well as input from IRPAC, the company allowed the
model to select hydrogen generation beginning in 2037. While Idaho Power does not know
which hydrogen technology may become commercially dominant, the company needed to
select a technology profile to model within AURORA and, informed by available technology
research, chose to model hydrogen as a SCCT with similar operating characteristics to natural
gas units except for the fuel they burn and the emissions they produce. To be clear,
Idaho Power modeled hydrogen as a resource with no carbon emissions.
The 2023 IRP is the first resource plan in which hydrogen-specific resources have been
modeled; the company anticipates additional advancements associated with hydrogen and,
as such, expects that ultimate development of the technology may differ from the current
modeling approach. Idaho Power will continue to monitor advancements in hydrogen resources
and refine its modeling assumptions in future long-term plans.
Nuclear Resources
The nuclear power industry has been working to develop and improve reactor technology for
many years, and Idaho Power continues to evaluate various nuclear technologies in the IRP
process. Considering the location of the INL within Idaho Power’s service area in eastern Idaho,
the company’s long-term planning has typically assumed that an advanced-design small
modular reactor (SMR) could be built on the INL site.
For the 2023 IRP, a 100 MW SMR was modeled as a selectable resource beginning in 2030—
a timeline the company considered reasonable given the current state of the technology and
the federal regulatory approval process. Compared to typical reactor designs, SMRs offer
potential benefits, including smaller physical footprints, reduced capital investment, plant size
scalability, and greatly enhanced flexibility. Although current operating parameters are not
available, Idaho Power has modeled the operational characteristics of an SMR plant similar to a
combined cycle plant. Grid services provided by the SMR include baseload energy, peaking
capacity, and flexible capacity.
For Idaho Power’s cost estimates and operating parameters for an advanced SMR nuclear
resource, see the Supply-Side Resource section of Appendix C—Technical Report.
Coal Resources
Conventional coal generation resources have been part of Idaho Power’s generation portfolio
since the early 1970s. Growing concerns over emissions and climate change coupled with
regulatory uncertainty have made it imprudent to consider building new conventional coal
generation resources. No new coal-based energy resources were modeled as part of the
2023 IRP.
5. Future Supply-Side Generation and Storage Resources
Page 64 2023 Integrated Resource Plan
Storage Resources
As increasing amounts of VERs are built within the region, the value of energy storage
increases. There are many energy storage technologies at various stages of development,
such as battery storage, hydrogen storage, compressed air, flywheels, pumped hydro storage,
iron-air storage, and others. The 2023 IRP considered a variety of energy-storage technologies
and modeled battery storage based on lithium ion (Li-ion) technology, longer-duration battery
storage based on iron-air technology, and pumped hydro storage.
Energy storage can provide numerous grid services in various durations. Short-term services
include ancillary services like frequency regulation, spinning reserve, and reactive power
support. In the medium duration, storage today can provide peak shaving, arbitrage,
T&D deferral, and firming for VERs. Long duration storage can shift energy between seasons.
Battery Storage
There are many types of battery-storage technologies at various stages of development.
The dominant chemistry used in the market today is Li-ion, which provides significant
advantages over other commercially available battery-storage technologies. Those advantages
include high cycle efficiency, high cycle life, fast response times, and high energy density.
Idaho Power modeled Li-ion storage over other technologies in the 2023 IRP for short and
medium duration storage. Idaho Power will continue to observe and evaluate the changing
storage technology landscape.
Prior to the passage of the IRA, storage resources were typically paired with solar facilities to
maximize tax credits that would otherwise not be available to standalone storage facilities.
Post-passage of the IRA, ITCs are available to standalone storage facilities. As a result, the 2023
IRP modeled standalone storage facilities only. This option creates more flexibility for storage
selection within the model, as AURORA will make cost-effective selections for storage that may
(or may not) be paired with solar or other resources based on need and cost-effectiveness.
For Idaho Power’s cost estimates, operating parameters, and ELCC calculations, see the
Supply-Side Resource and Loss of Load Expectation sections of Appendix C—Technical Report.
Pumped Hydro Storage
Pumped hydro storage is a type of hydroelectric power that stores potential energy by pumping
water from a lower to a higher elevation. Energy is generated when the water flows from the
higher reservoir like a normal hydroelectric facility.
Pumped hydro storage projects are often large and become more feasible when large amounts
of storage are identified as a system need.
5. Future Supply-Side Generation and Storage Resources
2023 Integrated Resource Plan Page 65
For Idaho Power’s cost estimates and operating parameters for pumped-hydro storage, see the
Supply-Side Resource section of the Appendix C—Technical Report.
Multi-Day Storage
Idaho Power added a new storage technology in the 2023 IRP: multi-day duration, 100-hour
storage, in the form of iron-air batteries. Generally, these resources charge during periods of
low demand and high renewable output in the spring and fall and discharge during periods of
high demand in the summer and winter. The downside of this storage technology compared to
other storage options is lower round-trip efficiency, which is expected to be less than half that
of Li-ion batteries. Given these operating characteristics, this technology is best suited for
inter-seasonal demand shaping and absorbing VER overproduction when they might otherwise
be curtailed. As a technology that could serve a critical future need, Idaho Power will continue
to monitor and model long-duration storage.
For Idaho Power’s cost estimates and operating parameters for multi-day duration 100-hour
storage, see the Supply-Side Resource section of the Appendix C—Technical Report.

6. Demand-Side Resources
Page 66 2023 Integrated Resource Plan
6. DEMAND-SIDE RESOURCES
Demand-Side Management Program Overview
DSM resources offset future energy loads by reducing
energy demand through either efficient equipment
upgrades (energy efficiency) or peak-system demand
reduction (demand response). Energy efficiency has
been a critical resource in IRPs since 2004,
providing average cumulative system load reductions of
over 324 aMW by year-end 2022 while demand
response programs provided 312 MW of available
capacity to reduce system demand in 2022.
Energy efficiency potential resources are
screened for cost-effectiveness, then all achievable
cost-effective energy efficiency potential resources are
included in the IRP as a decrement to the load forecast
before considering new supply-side resources.
In addition, all achievable energy efficiency potential
resources that were determined to not meet cost
effective thresholds were grouped (bundled) according
to price and season. These bundles were made available for selection by the AURORA model.
Accumulated energy efficiency is estimated to reduce energy demand at the time of the system
peak by 360 MW. Also included in the Preferred Portfolio is 320 MW of nameplate summer
peak demand reduction from existing demand response plus an additional 160 MW of demand
response by the end of the planning timeframe.
Energy Efficiency Forecasting—Energy Efficiency
Potential Assessment
For the 2023 IRP, Idaho Power’s third-party contractor, Applied Energy Group (AEG), provided a
20-year forecast of Idaho Power’s energy efficiency potential from a utility cost test (UCT)
perspective. The contractor also provided additional bundles of energy efficiency and their
associated costs beyond the achievable economic potential for analysis in the 2023 IRP.
For the initial study, the contractor developed three levels of energy efficiency potential:
technical, economic, and achievable. The three levels of potential are described below.
1. Technical—Technical potential is defined as the theoretical upper limit of energy
efficiency potential. Technical potential assumes customers adopt all feasible measures
regardless of cost. In new construction, customers and developers are assumed to

Idaho Power’s Irrigation Peak Rewards
program helps offset energy use on
high-use days.
6. Demand-Side Resources
2023 Integrated Resource Plan Page 67
choose the most efficient equipment available. Technical potential also assumes the
adoption of every applicable measure available. The retrofit measures are phased in
over several years.
2. Economic—Economic potential represents the adoption of all cost-effective energy
efficiency measures. In the energy efficiency potential study, the contractor applied the
UCT for cost-effectiveness, which compares lifetime energy and capacity benefits to the
cost of the program. Economic potential assumes customers purchase the most cost-
effective option at the time of equipment failure and adopt every cost-effective and
applicable measure.
3. Achievable—Achievable potential considers market adoption, customer preferences for
energy-efficient technologies, and expected program participation. Achievable potential
estimates a realistic target for the energy efficiency savings a utility can achieve through
its programs. It is determined by applying a series of annual market-adoption factors to
the cost-effective potential for each energy efficiency measure. These factors represent
the ramp rates at which technologies will penetrate the market.
The load forecast entered into AURORA includes the reduction to customer sales of all future
achievable economic energy efficiency potential. Treatment of energy efficiency that could
contribute beyond the decrement to the load forecast is discussed below.
Energy Efficiency Modeling
In addition to the baseline energy efficiency potential study that assessed technical, economic,
and achievable potential in a manner consistent with past IRPs, the company modeled
additional bundles of technically achievable energy efficiency and their costs in the AURORA
model in the 2023 IRP.
Technically Achievable Supply Curve Bundling
In collaboration with AEG, an approach was established to allow technically achievable energy
efficiency potential beyond the achievable economic potential, to be input into the AURORA
model for possible selection. These bundles include measures that did not pass economic
screening given current economic parameters but were made available for selection depending
on various scenarios determined by the model. Technically achievable potential differs from the
broader technical potential category, as AEG applies a market adoption factor intended to
estimate those customers likely to participate in programs incentivizing more efficient
processes or equipment, similar to the approach used when forecasting achievable potential.
Five bundles of energy efficiency measures were created that were grouped by summer or
winter measures, and summer was spilt into a low, mid, and high-cost; and winter was split into
low and high-cost bundles. Whether a measure belonged in the summer or winter groups
6.Demand-Side Resources
Page 68 2023 Integrated Resource Plan
depended on the ratio of peak winter to summer capacity determined by the measure’s load
shapes at the hour of seasonal peak need. The bundles were sized to be large enough for
AURORA to recognize them as operationally viable resources, but small enough to keep the
average levelized cost reflective of the costs of the associated measures.
The bundles were then loaded into the AURORA software with a ‘nameplate’ capacity
(peak kW), levelized cost, and an 8,760-hour load shape that contained the percentage of peak
demand for each hour of the year. Table 6.1 lists the average annual resource potential and
average levelized cost for the bundles.
Table 6.1 Energy efficiency bundles average annual resource potential and average levelized cost
Bundle 20-Year Average Annual Potential (aMW) 20-Year Average Real Cost ($/MWh)
Summer Low-Cost 8.4 $96
Summer Mid-Cost 5.3 $297
Summer High-Cost 34.2 $663
Winter Low-Cost 10.5 $68
Winter High-Cost 10.3 $371
DSM Program Performance and Reliability
Energy Efficiency Performance
Energy efficiency investments since 2002 have resulted in a cumulative annual reduction of
324 aMW in 2022. Figure 6.1 shows the cumulative annual growth in energy efficiency savings
from 2002 through 2022, along with the associated IRP targets developed as part of the IRP
process since 2004.
*IPC Savings include Northwest Energy Efficiency Alliance non-code/federal standards savings
Figure 6.1 Cumulative annual growth in energy efficiency compared with IRP targets
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2002 2003 200420052006 200720082009 2010 20112012 2013 201420152016 201720182019 2020 20212022
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6.Demand-Side Resources
2023 Integrated Resource Plan Page 69
Idaho Power’s energy efficiency portfolio is currently a cost-effective resource. Table 6.2 shows
the 2022 year-end program results, expenses, and corresponding benefit-cost ratios.
Table 6.2 Total energy efficiency portfolio cost-effectiveness summary, 2022 program performance
Customer Class
2022 Savings
(MWh) UCT ($000s)
Total Utility Benefits
($000s) (NPV*)
UCT: Benefit/
Cost Ratio
UCT Levelized Costs
(cents/kWh)
Residential 28,525 $5,455 $4,585 0.8 4.3
Industrial/commercial 109,960 $17,940 $48,619 2.7 1.8
Irrigation 6,955 $2,080 $5,602 2.7 2.6
Total** 145,440 $30,321 $58,806 1.9 2.1
* NPV=Net Present Value
** Total UCT dollars, benefit/cost ratio and levelized costs include indirect program expenses included in the portfolio level but not in the
customer class level
Note: Values may not add to 100% due to rounding. Excludes market transformation program savings
Energy Efficiency Performance
The company works with third-party contractors to conduct energy-efficiency program impact
evaluations to verify energy savings and process evaluations to assess operational efficiency on
a scheduled and as-required basis.
Idaho Power uses industry-standard protocols for its internal and external evaluation efforts,
including the National Action Plan for Energy Efficiency—Model Energy Efficiency Program
Impact Evaluation Guide, the California Evaluation Framework, the International Performance
Measurement and Verification Protocol, the Database for Energy Efficiency Resources, and the
Regional Technical Forum’s evaluation protocols.
The timing of impact evaluations is based on protocols from these industry standards,
with large-portfolio contributors being evaluated more often and with more rigor.
Smaller portfolio contributors are evaluated less often and require less analysis as most of the
program measure savings are deemed savings from the Regional Technical Forum or other
sources. Evaluated savings are expressed through a realization rate (reported savings divided
by evaluated savings). Realized savings of programs evaluated over the past four years
(2019–2022) ranged between 44 and 110%. The realized weighted savings average over the
same period is 100%.
Demand Response Performance
Demand response resources have been part of the demand-side portfolio since the 2004 IRP.
The current demand response portfolio is comprised of three programs. Table 6.3 lists the three
programs that make up the current demand response portfolio, along with the different
program characteristics. The Irrigation Peak Rewards program represents the largest percent of
potential demand reduction and during the 2022 summer season, this program contributed
82% of the total potential demand-reduction capacity, or 255 MW. More details on
6.Demand-Side Resources
Page 70 2023 Integrated Resource Plan
Idaho Power’s demand response programs can be found in Appendix B—Demand-Side
Management 2022 Annual Report.
Table 6.3 2022 demand response program capacity
Program Customer Class
Reduction
Technology
2022 Total Demand
Response Capacity (MW)
Percent of Total
2022 Capacity*
A/C Cool Credit Residential Central A/C 26.8 9%
Flex Peak Programs Commercial/Industrial Various 30 10%
Irrigation Peak Rewards Irrigation Pumps 255.6 82%
Total 312.4 100%
* Values may not add to 100% due to rounding
Figure 6.2 shows the historical annual demand response program capacity between 2004 and
2022. The demand-response capacity was lower in 2013 because of the one-year suspension of
both the irrigation and residential programs. The temporary program suspension was due to a
lack of near-term capacity deficits being identified in the 2013 IRP.
Figure 6.2 Historic annual demand response program performance
Demand Response Resource Potential
In the 2023 IRP, demand response from all existing programs was committed to provide
320 MW of peak capacity during June and July throughout the IRP planning period, with a
reduced amount of program potential available during August and September. Because the
total potential from demand response is dependent on anticipated load from program
participants, the reduced amount of potential available during August and September is a result
of irrigation load reducing over the demand response program season.
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2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022Pe
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Available capacity
6. Demand-Side Resources
2023 Integrated Resource Plan Page 71
As part of the 2023 IRP’s examination of the potential for expanded demand response,
Idaho Power contracted with AEG to provide a 20-year forecast of Idaho Power’s demand
response program potential to estimate what may be available in Idaho Power’s service area.
Based on this study, Idaho Power grouped expansion of its current programs and other
potential programs into similar price and characteristic buckets for analysis within the
AURORA model.
The DR potential study also included a potential associated with pricing programs, notably
time-of-use (TOU) and to a lesser degree, critical peak pricing (CPP). The company has existing
TOU offerings in both Idaho and Oregon. The company’s Idaho offering was initially developed
in 2005, and now has approximately 1,000 customers enrolled. The company implemented TOU
in Oregon in 2018 and has less than five customers enrolled. In Order No. 21-184, the OPUC
requested the company report on the number of participants, the total cost of the program to
date, and the peak capacity reduction by season. With the level of customer participation data
in the Oregon TOU rate, the sample used to develop a comprehensive and reliable assessment
of residential peak shifting would be outside an acceptable margin of error tolerance limit at
approximately +/- 60%. As such, circumstantial behavioral changes could misrepresent peak
shifting impacts when expanded to the full residential customer class. To date, the costs of
administering the program have been limited to initial marketing efforts and are not materially
significant. Finally, the OPUC requested that the company propose a venue to report TOU
performance. The company suggests reporting ongoing TOU pilot performance and any
changes to the offering in its annual distribution system planning (DSP) report, beginning with
the summer 2022 report.
DR was evaluated in the 2023 IRP modeling process by using 180 MW of new DR potential
identified from the 2022 DR potential study. The additional DR capacity was bucketed by like
characteristics and price, then made available for selection in AURORA. This additional DR
potential was represented by three separate buckets: 100 MW of existing program expansion,
60 MW of storage programs (for example, water heater or customer battery programs),
and 20 MW associated with pricing programs. DR was available for selection in the AURORA
model in 20 MW amounts, selectable each year, when analyzing the future load and resource
buildout. Idaho Power will continue to evaluate DR expansion in its service area with each IRP
planning cycle.
T&D Deferral Benefits
Energy Efficiency
For the 2023 IRP, Idaho Power determined the T&D deferral benefits associated with energy
efficiency by performing an analysis to determine how effective energy efficiency is at deferring
transmission, substation, and distribution projects. To perform the analysis, the company used
6. Demand-Side Resources
Page 72 2023 Integrated Resource Plan
historical and projected investments over a 20-year period from 2007 to 2026. Transmission,
substation, and distribution projects at various locations across the company’s system were
represented. The limiting capacity (determined by distribution circuit, transformer,
or transmission line) was identified for each project, along with the anticipated in-service date,
projected cost, peak load, and projected growth rate.
Energy efficiency measures were assumed to have a lifespan equaling the average of existing
measures—12 years. The cumulative energy efficiency from all cost-effective measures was
included in the analysis.
Varying amounts of incremental energy efficiency were used and spread evenly across
customer classes on all distribution circuits, based on the energy efficiency forecast.
Peak demand reduction was calculated and applied to summer and winter peaks for the
distribution circuits and substation transformers. If the adjusted forecast was below the limiting
capacity, it was assumed an associated project—the distribution circuit, substation transformer,
or transmission line—could be deferred. The financial savings of deferring the project were
then calculated.
The total savings from all deferrable projects were divided by the total annual energy efficiency
reduction required to obtain the deferral savings over the service area.
Idaho Power calculated the corresponding T&D deferral value as an average of the 20-year
forecast of achievable energy efficiency. The 20-year average was $8.33 per kW-year. This value
was then used in the calculation of energy efficiency cost-effectiveness in the 2022 energy
efficiency potential study.
Distribution System Planning
In March 2019, the OPUC initiated an investigation into DSP in docket UM 2005 with the stated
objective of directing electric utilities to “develop a transparent, robust, holistic regulatory
planning process for electric utility distribution system operations and investments.”30
Over nearly two years, OPUC staff, stakeholders, and utilities have engaged in workshops and
seminars to discuss DSP possibilities, best practices, and lessons learned from other
jurisdictions. These efforts culminated in DSP guidelines from OPUC staff, which were
subsequently adopted by the OPUC in Order 20-485 on December 23, 2020. The adopted DSP
guidelines identify specific efforts that utilities must conduct, analyze, and compile into reports
filed every two years. The initial report was split into two parts.31 Within these reports,

30 See OPUC UM 2005, Order No. 19-104.
31 idahopower.com/energy-environment/energy/planning-and-electrical-projects/oregon-distribution-system-
plan/.
6.Demand-Side Resources
2023 Integrated Resource Plan Page 73
the company identified how the DSP and resource planning processes can inform or impact
each respective plan.
One of the clear relationships between DSP and integrated resource planning is the ability to
consider avoided or deferred distribution investments as a cost offset to potential resource
investments. The value of such T&D deferral will be evaluated closely in the DSP process,
as well as in the company’s IRP. DSP affects the calculation of the T&D deferral value included
in the IRP’s energy efficiency cost-effectiveness test and the T&D deferral value of distribution-
connected resources in the IRP resource stack. To the extent IRP’s resources impact the
distribution system, local load forecasts and the distribution plan would be adjusted based on
the anticipated resources.
There are differences between the IRP and DSP processes. The IRP analyzes several long-term
peak forecast scenarios focused on long-term resource needs. The DSP, on the other hand,
analyzes near-term loading scenarios that can stress the local area capacity or operating
constraints that may occur at peak or light loads. Further, most resources identified in the IRP
do not specify location. The DSP is needed to inform the locational value (or cost) of
distribution-connected resources on Idaho Power’s system.
7.Transmission Planning
Page 74 2023 Integrated Resource Plan
7.TRANSMISSION PLANNING
Past and Present Transmission
High-voltage transmission lines are vital to the
development of energy resources for Idaho Power
customers. Transmission lines made it possible to
develop a network of hydroelectric projects in the
Snake River system, supplying reliable, low-cost
energy. In the 1950s and 1960s, regional
transmission lines stretching from the Pacific
Northwest to the HCC and to the Treasure Valley
were central to the development of the HCC
projects. In the 1970s and 1980s, transmission lines
allowed partnerships in three power plants in
neighboring states to deliver energy to
Idaho Power customers. Today, transmission lines
connect Idaho Power to wholesale energy markets
and help economically and reliably mitigate the variability of VERs. They also allow Idaho Power
to import clean energy from other regions and are consequently critical to Idaho Power
achieving its goal to provide 100% clean energy by 2045.
Idaho Power’s transmission interconnections provide economic benefits and improve reliability
by transferring electricity between utilities to serve load and share operating reserves.
Historically, Idaho Power experiences its peak load at different times of the year than most
Pacific Northwest utilities; as a result, Idaho Power can purchase energy from the Mid-C energy
trading market during its peak load and sell excess energy to Pacific Northwest utilities during
their peak. Additional regional transmission connections to the Pacific Northwest would benefit
Idaho Power customers in the following ways:
•Delay or avoid construction of additional resources to serve peak demand
•Increase revenue from off-system sales during the winter and spring, which would then
be credited to customers through the Power Cost Adjustment (PCA)
•Increase revenue from sales of transmission system capacity, which would then be
credited to Idaho Power customers
•Increase system reliability
•Increase the ability to integrate VERs, such as wind and solar
500-kilovolt (kV) transmission line near
Melba, Idaho.
7.Transmission Planning
2023 Integrated Resource Plan Page 75
•Improve the ability to implement advanced market tools more efficiently, such as
the EIM
Transmission Planning Process
FERC mandates several aspects of the transmission planning process. FERC Order No. 1000
requires Idaho Power to participate in transmission planning on a local, regional,
and interregional basis, as described in Attachment K of the Idaho Power Open-Access
Transmission Tariff and summarized in the following sections.
Local Transmission Planning
Idaho Power uses a biennial process to create a local transmission plan identifying needed
transmission system additions. The local transmission plan is a 20-year plan that incorporates
planned supply-side resources identified in the IRP process, transmission upgrades identified
in the local-area transmission advisory process, forecasted network customer load
(e.g., Bonneville Power Administration [BPA] customers in eastern Oregon and southern Idaho),
Idaho Power’s retail customer load, and third-party transmission customer requirements.
By evaluating these inputs, required transmission system enhancements are identified that will
ensure safety and reliability. The local transmission plan is shared with the regional
transmission planning process.
A local-area transmission advisory process is performed every 10 years for each of the load
centers identified, using unique community advisory committees to develop local-area plans.
The community advisory committees include jurisdictional planners, mayors, city council
members, county commissioners, representatives from large industry, commercial, residential,
and environmental groups. Plans identify transmission and substation infrastructure needed for
full development of the local area, accounting for land-use limits, with estimated in service
dates for projects. Local-area plans are created for the following load centers:
1.Eastern Idaho
2.Magic Valley
3.Wood River Valley
4.Eastern Treasure Valley
5.Western Treasure Valley (this load-area includes eastern Oregon)
6.West Central Mountains
7.Transmission Planning
Page 76 2023 Integrated Resource Plan
Regional Transmission Planning
Idaho Power is active in NorthernGrid, a regional transmission planning association of
13 member utilities. The NorthernGrid was formed in early 2020. Previously, dating back to
2007, Idaho Power was a member of the Northern Tier Transmission Group.
NorthernGrid membership includes Avista, Berkshire Hathaway Energy U.S. Transmission, BPA,
Chelan County PUD, Idaho Power, NV Energy, NorthWestern Energy, PacifiCorp (Rocky
Mountain Power and Pacific Power), Portland General Electric, Puget Sound Energy, Seattle City
Light, Snohomish County PUD, and Tacoma Power. Biennially, NorthernGrid will develop a
regional transmission plan using a public stakeholder process to evaluate transmission needs
resulting from members’ load forecasts, local transmission plans, IRPs, generation
interconnection queues, other proposed resource development, and forecast uses of the
transmission system by wholesale transmission customers. The 2020–2021 regional
transmission plan was published in December 2021 and can be found on the NorthernGrid
website: northerngrid.net. That plan identifies B2H and Gateway West (segments across
southern Idaho as needed regional transmission additions. Similarly, the draft 2022–2023
regional transmission plan concludes that B2H and Gateway West segments continue to be
needed by the region.
Existing Transmission System
Idaho Power’s transmission system extends from eastern Oregon through southern Idaho to
western Wyoming and is composed of 115-, 138-, 161-, 230-, 345-, and 500-kV transmission
facilities. Sets of lines that transmit power from one geographic area to another are known as
transmission paths. Transmission paths are evaluated by the Western Electricity Coordinating
Council (WECC) utilities to obtain an approved power transfer rating. Idaho Power has defined
transmission paths to all neighboring states and between specific southern Idaho load centers
as shown in Figure 7.1.
7.Transmission Planning
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Figure 7.1 Idaho Power transmission system map
The transmission paths identified on the map are described in the following sections, along with
the conditions that result in capacity limitations.
Idaho to Northwest Path
The Idaho to Northwest transmission path (WECC Path 14) consists of the 500-kV Hemingway–
Summer Lake line, the three 230-kV lines between the HCC and the Pacific Northwest, and the
115-kV interconnection at Harney substation near Burns, Oregon. The Idaho to Northwest path
is capacity-limited during summer months due to energy imports from the Pacific Northwest to
serve Idaho Power retail load and transmission-wheeling obligations for the BPA load in eastern
Oregon and southern Idaho. Additional transmission capacity is required to facilitate
incremental market purchases from northwest entities to serve Idaho Power’s growing
customer base.
Operationally since 2020, Idaho Power has seen increased third-party demand for west-to-east
or north-to-south firm transmission from the Pacific Northwest to the Desert Southwest
or California.
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Brownlee East Path
The Brownlee East transmission path (WECC Path 55) is on the east side of the Idaho to
Northwest path shown in Figure 7.1. Brownlee East comprises the 230-kV and 138-kV lines east
of the HCC and Quartz substation near Baker City, Oregon. When the Hemingway–Summer Lake
500-kV line is included with the Brownlee East path, the path is typically referred to as the Total
Brownlee East path (WECC Path 82).
The Brownlee East path is capacity-limited during the summer months due to a combination of
HCC hydroelectric generation flowing east into the Treasure Valley concurrent with
transmission-wheeling obligations for BPA southern Idaho load and Idaho Power energy
imports from the Pacific Northwest. Capacity limitations on the Brownlee East path limit the
amount of energy Idaho Power can transfer from the HCC, as well as energy imports from the
Pacific Northwest. If new resources, including market purchases, are located west of the path,
additional transmission capacity will be required to deliver the energy to the Treasure Valley
load center.
Idaho–Montana Path
The Idaho–Montana transmission path (officially Montana–Idaho WECC Path 18) consists of the
Brady–Mill Creek 230-kV and Big Grassy–Dillon 161-kV transmission lines. The Idaho–Montana
path is also capacity-limited during the summer months as Idaho Power, BPA, PacifiCorp,
and others move energy north-to-south from Montana into Idaho. In the north-to-south
direction, Idaho Power has 167 MW of capacity on the path.
Borah West Path
The Borah West transmission path (WECC Path 17) is internal to Idaho Power’s system and is
jointly owned between Idaho Power and PacifiCorp. In the predominate east-to-west direction,
Idaho Power owns 1,467 MW of the path, and PacifiCorp owns 1,090 MW of the path. The path
includes 345-kV, 230-kV, and 138-kV transmission lines west of the Borah substation located
near American Falls, Idaho. Idaho Power’s one-third share of energy from the Jim Bridger plant
flows over this path, as well as energy from east-side resources and imports from Montana,
Wyoming, and Utah. Heavy path flows are likely to exist during low hydro operating conditions
when power from the south is flowing to Idaho and the Pacific Northwest. This can occur daily,
during peak solar production, or seasonally, when southern and eastern thermal and wind
production moves west across the system to the Pacific Northwest. Additional transmission
capacity will likely be required if new resources or market purchases are located east of the
Borah West path.
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Midpoint West Path
The Midpoint West transmission path is internal to Idaho Power’s system and is a jointly owned
path between Idaho Power and PacifiCorp. In the predominate east-to-west direction,
Idaho Power owns 1,710 MW of the path while PacifiCorp owns 1,090 MW of the path.
The path is composed of 500-kV, 230-kV, and 138-kV transmission lines west of Midpoint
substation located near Jerome, Idaho. The heaviest east-to-west path flows on Midpoint West
are likely to correlate with Borah West. Additional transmission capacity will likely be required if
new resources or market purchases are located east of the Midpoint West path.
Idaho–Nevada Path
The Idaho–Nevada transmission path (officially Idaho–Sierra WECC Path 16) is the 345-kV
Rogerson–Humboldt line. Idaho Power and NV Energy are co-owners of the line, which was
developed at the same time the North Valmy Power Plant was built in northern Nevada.
Idaho Power is allocated 100% of the northbound capacity, while NV Energy is allocated 100%
of the southbound capacity. The import, or northbound, capacity on the transmission path is
360 MW, of which Valmy Unit 2 uses approximately 130 MW.
Idaho–Wyoming Path
The Idaho–Wyoming path, referred to as Bridger West (WECC Path 19), is made up of three
345-kV transmission lines between the Jim Bridger generation plant and southeastern Idaho.
Idaho Power owns 800 MW of the 2,400-MW east-to-west capacity. PacifiCorp owns the
remaining capacity. The Bridger West path effectively feeds into the Borah West path when
power is moving east-to-west from Jim Bridger; consequently, the import capability of the
Bridger West path into the Idaho Power area can be limited by Borah West path
capacity constraints.
Idaho–Utah Path
The Idaho–Utah path, referred to as Path C (WECC Path 20), comprises 345-, 230-, 161-,
and 138-kV transmission lines between southeastern Idaho and northern Utah. PacifiCorp is
the path owner and operator of all the transmission lines. The path effectively feeds into
Idaho Power’s Borah West path when power is moving from south to north; consequently,
the import capability of Path C into the Idaho Power area can be limited by Borah West path
capacity constraints.
Table 7.1 summarizes the import capability for paths impacting Idaho Power operations and
lists their total capacity and available transfer capacity (ATC); most of the paths are completely
allocated with no capacity remaining.
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Table 7.1 Transmission import capacity
Transmission Path Import Direction Capacity (MW) ATC (MW)*
Idaho to Northwest West-to-east 1,200–1,340 Varies by Month
Idaho–Nevada South-to-north 360 Varies by Month
Idaho–Montana North-to-south 383 Varies by Month
Brownlee East West-to-east 1,915 Internal Path
Midpoint West East-to-west 2,800 Internal Path
Borah West East-to-west 2,557 Internal Path
Idaho–Wyoming (Bridger West) East-to-west 2,400 86 (Idaho Power Share)
Idaho–Utah (Path C) South-to-north 1,250 PacifiCorp Path
* The ATC of a specific path may change based on changes in the transmission service and generation interconnection request queue
(i.e., the end of a transmission service, granting of transmission service, or cancelation of generation projects that have granted future
transmission capacity)
Existing Transmission Capacity for Firm Market Imports
The Idaho to Northwest, Idaho–Montana, and Idaho–Utah paths provide Idaho Power
connections to market hubs in the west. Idaho Power’s connections to market hubs are
leveraged by the company as an equivalent to a resource for capacity position purposes.
The quantity that each path provides toward the annual capacity position varies by season and
year within the planning horizon.
Idaho to Northwest and Idaho-Montana Path Firm Market Imports
Idaho Power owns 1,280 MW of transmission capacity between the Pacific Northwest
transmission system and Idaho Power’s transmission system. Of this capacity, 1,200 MW is on
the Idaho to Northwest path, and 80 MW is on the Idaho–Montana path.
Table 7.2 details a typical summer season transmission capacity utilization, which includes
Capacity Benefit Margin (CBM) and Transmission Reliability Margin (TRM) capacity. CBM can
only be accessed as firm capacity if Idaho Power is in an energy emergency. TRM is transmission
capacity that Idaho Power sets aside as unavailable for firm use on the Idaho to Northwest
path for the purposes of grid reliability to ensure a safe and reliable transmission system.
An additional discussion of CBM and TRM takes place later in the chapter.
Table 7.2 Pacific Northwest to Idaho Power west-to-east transmission capacity
Firm Transmission Usage (Pacific Northwest to Idaho Power) Capacity (MW)
BPA Load Service (Network Customer) 330
TRM 283
CBM 330
Subtotal 943
Pacific Northwest Purchase (Idaho Power Load Service) 337
Total 1,280
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Idaho to Northwest Path Utilization
To utilize Idaho to Northwest transmission capacity for imports, Idaho Power must purchase
transmission service from another party between the Mid-C market hub (or a direct entity in
the Pacific Northwest) and the Idaho Power transmission system, and then use its transmission
to deliver energy to the ultimate load. Typically, the company will reserve transmission with
one of the other Idaho to Northwest path owners—Avista, BPA, or PacifiCorp—between Mid-C
and the Idaho Power border. Table 7.3 details the summer allocation of the maximum amount
that Idaho Power can reserve transmission with each entity to access resources from Mid-C to
cross the Idaho to Northwest path.
Table 7.3 The Idaho to Northwest Path (WECC Path 14) summer allocation
Transmission Provider Idaho to Northwest Allocation
(Summer West-to-East) (MW)
Avista (to Idaho Power) 340
BPA (to Idaho Power) 350
PAC (to Idaho Power) 510
Total Capability to Idaho Power 1,200*
* During times of very low generation at Brownlee, Oxbow, and Hells Canyon hydro plants, the Idaho to Northwest path total capability can
increase to as much as 1,340 MW; low generation at these power plants does not correspond with Idaho Power’s system peak
Idaho—Montana Path Utilization
Idaho Power’s share of the Idaho–Montana path includes an 80 MW connection to either
Avista, BPA, or Northwestern Energy across the Brady–Mill Creek 230-kV line, and a direct
connection to Northwestern Energy across the Big Grassy–Dillon 161-kV line, which is not
included in the total Pacific Northwest to Idaho Power import capacity due to commercial
constraints beyond the Idaho Power border.
Like the Idaho to Northwest transmission path, to utilize the Idaho–Montana path capacity for
imports, Idaho Power must purchase transmission service from another party between the
purchased resource, such as the Mid-C market hub, and the Idaho Power transmission system.
Idaho—Utah Path Utilization
PacifiCorp is the owner and operator of the Idaho–Utah path. Idaho Power has secured 50 MW
of transmission capacity, for firm resource imports to access the Desert Southwest market,
between the months of June and October.
Existing Transmission Modeling in the 2023 IRP
Table 7.4 details the amount that Idaho Power leverages transmission connections, by market,
season, and year, to meet peak demand. The company can use its existing transmission
connections to provide 380 MW of firm summer capacity plus 200 MW of emergency summer
capacity via CBM. The company can use its existing transmission connections to provide
330 MW of firm winter capacity through 2028. After 2028, the company assumes the firm
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winter capacity decreases from 330 MW to 100 MW by 2030. The reason for this modeled
reduction is to conservatively move away from relying on the Pacific Northwest to provide the
company with winter capacity because the Pacific Northwest is a winter peaking region.
The company anticipates it will be more difficult for the Pacific Northwest to meet its winter
peak obligations in the late-2020s.
Table 7.4 Third-party secured import transmission capacity for existing transmission
Third-Party
Provider Market
Summer
Capacity (MW)
Winter Capacity
2024–2028 (MW)
Winter Capacity
2028–2029 (MW)
Winter Capacity
2029–2043 (MW)
Avista via Lolo Pacific Northwest 200 200 165 50
PAC via Walla Walla Pacific Northwest 80 80 0 0
BPA via La Grande Pacific Northwest 50 50 50 50
PAC via Red Butte
(Utah–Nevada border)
Desert Southwest 50 0 0 0
Subtotal 380 330 215 100
Emergency
Transmission (CBM)
Pacific Northwest 200 0 0 0
Total 580 330 215 100
Capacity Benefit Margin Details
CBM is transmission capacity Idaho Power sets aside on the company’s transmission system,
as unavailable for firm use, for the purposes of accessing reserve energy to recover from severe
conditions such as unplanned generation outages or energy emergencies. An energy emergency
must be declared by Idaho Power before the CBM transmission capacity becomes firm.
The company holds 330 MW of import transmission capacity aside on the Idaho to Northwest
path for CBM. For the 2023 IRP, Idaho Power has reduced the contribution of CBM toward the
annual capacity position from 330 MW for all seasons to 200 MW in the summer and 0 MW in
the winter. For operational purposes, Idaho Power continues to set aside 330 MW on the
transmission system. The reduction of capacity credit to 200 MW in the summer is in response
to continued transmission market limitations beyond the Idaho Power border because CBM
capacity does not have corresponding third-party transmission reservations to the Mid-C
market. The reduction of winter season CBM capacity to 0 MW is in response to winter
wholesale energy market depth concerns from the Pacific Northwest. Idaho Power will
continue to evaluate CBM in the future to determine whether the capacity credit accurately
reflects Idaho Power’s ability to utilize the transmission outside of Idaho Power’s border.
Transmission Reliability Margin Details
TRM is transmission capacity that Idaho Power sets aside as unavailable for firm use on the
Idaho to Northwest path for the purposes of grid reliability to ensure a safe and reliable
transmission system. Idaho Power’s TRM methodology, approved by the FERC in 2002,
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requires Idaho Power to set aside transmission capacity based on the average adverse
unscheduled flow on the Idaho to Northwest path.
In the west, electrical power is scheduled through a contract-path methodology, which means if
100 MW is purchased and scheduled over a path, that 100 MW is decremented from the path’s
total availability. However, physics dictates the actual power flow over the path based on the
path of least resistance, so actual flows don’t equal contract path schedules. The difference
between scheduled and actual flow is referred to as unscheduled flow.
Boardman to Hemingway
In the 2006 IRP, Idaho Power identified the need for a transmission line to the Pacific
Northwest electric market. At that time, a 230-kV line interconnecting at the McNary substation
to the greater Boise area was included in IRP portfolios. Since its initial identification,
the project has been refined and developed, including evaluating upgrade options of existing
transmission lines, evaluating terminus locations, and sizing the project to economically meet
the needs of Idaho Power and other regional participants. The project has evolved into what is
now B2H. The project, which is expected to provide a total of 2,050 MW of capacity32,
involves permitting, constructing, operating, and maintaining a new, single-circuit 500-kV
transmission line approximately 300 miles long between the proposed Longhorn substation
near Boardman, Oregon, and the existing Hemingway substation in southwest Idaho. The new
line will provide many benefits for Idaho Power, including the following:
•Greater access to the Pacific Northwest electric market to economically serve homes,
farms, and businesses in Idaho Power’s service area
•Improved system reliability and resiliency
•Reduced capacity limitations on the regional transmission system as demands on the
system continue to grow
The benefits of B2H in aggregate reflect its importance to the achievement of Idaho Power’s
goal to provide 100% clean energy by 2045 without compromising the company’s commitment
to reliability and affordability.
The B2H project has been identified as a preferred resource in IRPs since 2009 and ongoing
permitting activities have been acknowledged in every IRP Near-Term Action Plan thereafter.
The 2017 IRP, 2019 IRP, and 2021 IRP Near-Term Action Plans, including B2H construction
related activities mentioned within, were acknowledged by both the Idaho and Oregon PUCs.
32 B2H is expected to provide 1,050 MW of capacity in the west-to-east direction, and 1,000 MW of capacity in the
east-to-west direction.
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B2H is a regionally significant project; it was identified as a key transmission component of each
Northern Tier Transmission Group biennial regional transmission plan for 10 years 2010–2019.
The B2H project is similarly a major component of the 2020–2021 NorthernGrid regional
transmission plan. Further, the draft 2022–2023 NorthernGrid regional transmission plan
includes the B2H project as a major component.
B2H Value
Idaho Power received acknowledgment of B2H in the 2021 IRP based on the company owning
45% of the project. Under the current ownership structure, which was modified in 2023,
Idaho Power absorbed BPA’s previously assumed ownership share in exchange for BPA entering
into a transmission service agreement with Idaho Power.
The Preferred Portfolio, which includes B2H, is significantly more cost-effective than the best
alternative resource portfolio that did not include B2H:
•Planning Conditions Preferred Portfolio NPV—$9,746 million
•Planning Conditions without B2H Portfolio NPV—$10,582 million
•B2H NPV Cost Effectiveness Differential—$836 million
Under planning conditions, the Preferred Portfolio is approximately $836 million more cost
effective than the portfolio that did not include B2H. For comparison, the cost effectiveness of
the 2023 IRP’s Preferred Portfolio (with B2H) is more than triple the cost effectiveness of the
Preferred Portfolio (with B2H) in the 2021 IRP; the 2021 IRP Preferred Portfolio with B2H was
$266 million more cost effective than the non-B2H alternative. Detailed portfolio costs can be
found in Chapter 10.
There are four primary reasons for the increased benefits associated with B2H:
1.Competing IRP resources have also experienced cost increase pressures.
2.In the 2021 IRP, the company modeled the termination of 510 MW of
transmission-service-related revenue upon the completion of B2H. In the 2023 IRP,
following discussions with the transmission customer, Idaho Power is no longer
assuming termination of this service. This change resulted in the addition of wheeling
revenue related to this service and the adjustment of Midpoint West available
transmission capacity for determining the GWW transmission trigger levels from
resource additions.
3.The company’s summer load growth has grown in the years directly following B2H
in-service date, further increasing the cost effectiveness of the project by avoiding a
significant amount of new generation resources that would be required to meet
demand in a non-B2H environment.
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2023 Integrated Resource Plan Page 85
4.The company’s winter needs, which were not a major consideration in the 2021 IRP,
have accelerated due to industrial load growth. The company’s B2H related asset
exchange with PacifiCorp enables 200 MW of additional winter connectivity.
Project Participants
For the 2023 IRP, Idaho Power modeled the anticipated B2H capacity allocation shown in
Table 7.5. The Idaho Power capacity allocation accommodates Idaho Power’s capacity needs for
load service and for the anticipated new network transmission service BPA will be taking across
the Idaho Power system to reach their southeast Idaho customers.
Table 7.5 B2H capacity allocation
Idaho Power PacifiCorp
Capacity (MW) west-to-east 750 300
(MW) east-to-west 182 818
allocation 45% 55%
Figure 7.2 shows the transmission line route submitted to the ODOE in 2017.
Figure 7.2 B2H route submitted in 2017 Oregon Energy Facility Siting Council Application for Site Certificate
7.Transmission Planning
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B2H Related Asset Exchange—Four Corners Capacity
As part of the broader B2H transaction with PacifiCorp, Idaho Power has executed agreements
to acquire PacifiCorp transmission assets and their related capacity sufficient to enable
Idaho Power to use 200 MW of bidirectional transmission capacity between the Idaho Power
system (Populus substation) and Four Corners, through Mona. Four Corners is a Desert
Southwest market hub with eight entities having transmission connectivity. Idaho Power will
also have a connection to entities at Mona in central Utah.
Table 7.6 List of transmission entities at Four Corners and Mona
with Transmission at Mona
Arizona Public Service
acifiCorp

ublic Service New Mexico

acifiCorp
Idaho Power believes the acquired Four Corners capacity will provide the company with
long-term strategic value diverse from the Pacific Northwest value provided directly by B2H.
The Desert Southwest is rich with solar potential which is expected to continue its growth in the
future. New Mexico has high wind potential, and the number of Desert Southwest entities with
a presence at this market hub presents market diversity opportunities.
Through the direct B2H project, and the companion B2H enabled asset exchange with
PacifiCorp, the B2H project is enabling two diverse connections to two major western
market hubs.
Permitting Update
Permitting of the B2H project is subject to review and approval by, among other government
entities, the Bureau of Land Management (BLM), United States Forest Service, United States
Navy, and the Oregon Energy Facility Siting Council (EFSC). The federal permitting process is
dictated primarily by the Federal Land Policy Management Act and National Forest
Management Act and is subject to NEPA review. The BLM is the lead agency in administering
the NEPA process for the B2H project. On November 25, 2016, BLM published the Final EIS,
and the BLM issued a record of decision (ROD) on November 17, 2017, approving a right-of-way
grant for the project on BLM-administered lands.
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The United States Forest Service issued a separate ROD on November 13, 2018, approving the
issuance of a special-use authorization for a portion of the project that crosses the Wallowa–
Whitman National Forest.
The Department of Defense issued its ROD on September 25, 2019, approving a right-of-way
easement for a portion of the project that crosses the Naval Weapons System Training Facility
in Boardman, Oregon.
On August 4, 2021, a federal district court in Oregon issued an order granting Idaho Power and
the federal defendants’ motions for summary judgment, dismissing the Stop B2H Coalition’s
challenge to the BLM and Forest Service’s issuance of the rights-of-way. That order was not
appealed to the Ninth Circuit Court of Appeals within the requisite timeframe, and thus the
district court’s decision upholding the federal rights-of-way is not subject to appeal.
For the State of Oregon permitting process, Idaho Power submitted the preliminary Application
for Site Certificate to EFSC in February 2013 and submitted an amended preliminary Application
for Site Certificate in summer 2017. The amended preliminary Application for Site Certificate
was deemed complete by ODOE in September 2018. The ODOE reviewed Idaho Power’s
application for compliance with EFSC siting standards and released a Draft Proposed Order
(DPO) for B2H on May 22, 2019. Public comment on the DPO findings were taken by ODOE and
EFSC, and—based on those comments—ODOE issued a Proposed Order on July 2, 2020.
A contested case on the Proposed Order was initiated and was presided over by an
EFSC-appointed Administrative Law judge. The EFSC completed the contested case proceeding
in 2022. In late September, the Oregon EFSC held its final hearing and its final vote on
Idaho Power’s application for a site certificate for B2H. The EFSC approved the site certificate by
a unanimous vote. Three limited parties filed appeals to the Oregon Supreme Court asking
them to overturn EFSC’s approval of the B2H site certificate. The Oregon Supreme Court issued
its decision on March 9, 2023, affirming the B2H site certificate.
Idaho Power has filed two Requests for Amendment (RFA) to the B2H site certificate. The RFAs
are intended to provide additional flexibility during construction and to accommodate
landowner requests where practicable. The first RFA (RFA1) was filed on December 7, 2022,
and a Proposed Order was issued on August 7, 2023. Idaho Power expects a Final Order on
RFA1 in fall 2023. The second RFA (RFA2) was filed on June 30, 2023, and is currently under
review by EFSC.
Idaho Power also obtained Certificates of Public Convenience and Necessity from the IPUC and
OPUC in June 2023.
The permit process in Idaho will consist of Conditional Use Permits issued by Owyhee County.
Although Idaho Power has non-appealable right-of-way grants from the BLM and the site
certificate from ODOE, both entities require additional steps prior to authorizing construction.
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Idaho Power is working through the BLM’s process to secure Notice(s) To Proceed approvals
and with the ODOE to obtain Pre-Construction Compliance Determinations. Idaho Power
expects these authorizations to be granted in phases between the first quarter of 2023 and
third quarter of 2024. Additionally, Idaho Power is in the process of securing bids and awarding
contracts for the various aspects of the project to move into the construction phase.
Idaho Power expects construction to begin in 2023, with the line in service in 2026.
Construction Update Next Steps
B2H began pre-construction activities in 2021. These activities included, but are not limited to,
the following:
•Geotechnical surveys
•Detailed ground surveys (light detection and ranging [LiDAR] surveys)
•Final environmental and cultural resource surveys
•Right-of-way activities
•Detailed design
•Constructability analysis
•Construction bid package development
•Long-lead material acquisition
At this time, the B2H project is preparing to commence construction activities in fall 2023.
Construction activities include, but are not limited to, the following:
•Award of construction and material contracts
•Right-of-way clearing and access road construction
•Transmission line construction
•Substation construction or upgrades
Additional project information is available at idahopower.com/b2h.
B2H Modeling in the IRP
The B2H transmission project provides capacity associated with 1) the B2H transmission line
directly and 2) the B2H enabled asset exchange.
B2H will add 1,050 MW of west-to-east capacity, and 1,000 MW of east-to-west capacity to the
Idaho to Northwest path. Idaho Power will own 45% of the capacity in the form of 750 MW in
the west-to-east direction, and 182 MW in the east-to-west direction. PacifiCorp will own the
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balance. The full B2H capacity is modeled in the transmission portion of AURORA, with separate
transmission links modeled for Idaho Power’s share and PacifiCorp’s share. The company
treats approximately 500 MW of B2H’s summer capacity as equivalent to a summer resource.
B2H west-to-east capacity will also be utilized by the company to provide transmission service
to BPA.
The B2H asset exchange related capacity is modeled in the AURORA transmission links model
as a 200 MW bi-directional connection between Idaho Power and Arizona Public Service.
The company treats 200 MW of winter import capacity as equivalent to a winter resource.
B2H Cost Treatment in the IRP
In general, for new supply-side resources modeled in the IRP process, surplus sales of
generation are included as a cost offset in the AURORA portfolio modeling. Transmission
wheeling revenues, however, are not included in AURORA calculations. To remedy this
inconsistency, starting in the 2019 IRP, Idaho Power modeled incremental transmission
wheeling revenue from non-native load customers as an annual revenue credit for B2H
portfolios. In the 2023 IRP, Idaho Power continued to model expected incremental third-party
wheeling revenues as a reduction in costs ultimately benefiting retail customers.
Idaho Power’s transmission assets are funded by native load customers, network customers,
and point-to-point transmission wheeling customers based on a ratio of each party’s usage of
the transmission system. For the 2023 IRP, Idaho Power modeled B2H with the company’s
45% ownership interest. A portion of this 45% ownership interest is providing transmission
service to BPA, with BPA transmission wheeling payments acting as a cost-offset to the overall
B2H project costs. Additionally, portfolios involving B2H result in a higher FERC transmission
rate than portfolios without B2H. Although B2H provides significant incremental capacity,
and will likely result in increased transmission sales, Idaho Power assumed flat transmission
sales volume as a conservative assumption (other than increased volumes associated with
transmission network customers such as BPA). The flat sales volume, applied to the higher FERC
transmission rate, results in a cost offset for IRP portfolios with B2H.
In 2023 IRP modeling, Idaho Power assumed its 45% share of the direct expenses of B2H,
plus an Allowance for Funds Used During Construction (AFUDC) cost, plus a project contingency
amount. Total Cost Estimate: $823 million, which includes $47 million in local
interconnection upgrades. These values are from the September 2023 B2H project estimate
based on actual bids received for materials and construction.
Gateway West
The Gateway West transmission line project is a joint project between Idaho Power and
PacifiCorp to build and operate approximately 1,000 miles of new transmission lines from the
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planned Windstar substation near Glenrock, Wyoming, to the Hemingway substation near
Melba, Idaho. PacifiCorp is currently the project manager for Gateway West, with Idaho Power
providing a supporting role.
Figure 7.3 shows a map of the project identifying the authorized routes in the federal
permitting process based on the BLM’s November 2013 ROD for segments 1 through 7 and 10.
Segments 8 and 9 were further considered through a Supplemental EIS by the BLM. The BLM
issued a ROD for segments 8 and 9 on January 19, 2017. In March 2017, this ROD was rescinded
by the BLM for further consideration. On May 5, 2017, the Morley Nelson Snake River Birds of
Prey National Conservation Area Boundary Modification Act of 2017 (H.R. 2104) was enacted.
H.R. 2104 authorized the Gateway West route through the Birds of Prey area that was
proposed by Idaho Power and PacifiCorp and supported by the Idaho Governor’s Office,
Owyhee County and certain other constituents. On April 18, 2018, the BLM released the
decision record granting approval of a right-of-way for Idaho Power’s proposed routes for
segments 8 and 9.
In its 2017 IRP, PacifiCorp announced plans to construct a portion of the Gateway West
Transmission Line in Wyoming. PacifiCorp has subsequently constructed the 140-mile segment
between the Aeolus substation near Medicine Bow, Wyoming, and the Jim Bridger power plant
near Point of Rocks, Wyoming. The Aeolus to Anticline 500-kV line segment was energized in
November 2020. In PacifiCorp’s 2023 IRP, they selected the Anticline to Populus 500-kV to
increase transmission for additional resource development within Wyoming.
Idaho Power has a one-third permitting interest in the segments between Midpoint and
Hemingway (segment 8), Cedar Hill and Hemingway (segment 9), and Cedar Hill and Midpoint
(segment 10). Further, Idaho Power has interest in the segment between Borah and Midpoint
(segment 6), which is an existing transmission line operated at 345 kV but constructed at
500 kV.
7.Transmission Planning
2023 Integrated Resource Plan Page 91
Figure 7.3 Gateway West map
Gateway West will provide many benefits to Idaho Power customers, including the following:
•Relieve Idaho Power’s constrained transmission system between the Magic Valley
(Midpoint) and the Treasure Valley (Hemingway). Transmission connecting the
Magic Valley and Treasure Valley is part of Idaho Power’s core transmission system,
connecting two major Idaho Power load centers.
•Provide the option to locate future generation resources east of the Treasure Valley
•Provide future load-service capacity to the Magic Valley from the Cedar Hill substation
•Help meet the transmission needs of the future, including transmission needs
associated with VERs
The completed Gateway West project, as currently permitted, would provide approximately
4,000 MW of additional Midpoint West path transfer capacity between the Magic Valley and
Treasure Valley. As detailed previously, Idaho Power has a one-third interest in the capacity
additions between Midpoint and Hemingway. Along with the B2H project, Gateway West was a
major component of the 2020–2021 NorthernGrid regional transmission plan. The draft
2022–2023 NorthernGrid regional transmission plan includes the B2H project and Gateway
West segments 8 and 10. The Gateway West and B2H projects are complementary and will
provide upgraded transmission paths from the Pacific Northwest across Idaho and into eastern
Wyoming. Regional transmission plans produce a more efficient or cost-effective plan for
7.Transmission Planning
Page 92 2023 Integrated Resource Plan
meeting the transmission requirements associated with the load and resource needs of the
regional footprint.
Gateway West—Segment 8 and Mayfield Substation
Gateway West segment 8 is the Midpoint–Hemingway #2 line segment of Gateway West.
This line segment would be a new 500-kV line from the existing Midpoint substation near
Shoshone, Idaho to Hemingway substation near Melba, Idaho. The earliest possible in-service
date for this segment is end-of-year 2028. This segment of Gateway West will increase the
Midpoint West and Boise East path capabilities by approximately 2,000 MW. As described
earlier, Idaho Power has a one-third permitting interest in this segment, with PacifiCorp
having the remaining majority interest. Idaho Power’s capacity in this segment is anticipated to
be 667 MW.
Along with the addition of Midpoint–Hemingway #2 line, a new Mayfield substation, located
southeast of Boise, is anticipated to be required to integrate the 500-kV line and associated
new resources into the Treasure Valley 230-kV system. The new Midpoint–Hemingway #2 line is
anticipated to wrap into the Mayfield substation.
Gateway West—Segment 9 and Cedar Hills Substation
Gateway West segment 9 is the Cedar Hill–Hemingway 500-kV line segment of Gateway West.
The Cedar Hill–Hemingway 500-kV line connects between the planned Cedar Hill substation
near Murtagh, Idaho, and the Hemingway substation near Melba, Idaho. Together,
the Midpoint–Cedar Hill (segment 10) and Cedar Hill–Hemingway 500-kV lines create a second
new Gateway West 500-kV path for the company between the Magic Valley and Treasure
Valley areas. Similar to Midpoint–Hemingway #2 500-kV, Cedar Hill–Hemingway 500-kV is
expected to increase the Midpoint West and Boise East path capabilities by approximately
2,000 MW. The earliest possible in-service date is end-of-year 2030. Idaho Power has a
one-third permitting interest in Cedar Hill–Hemingway 500-kV, with PacifiCorp maintaining the
remaining majority interest. Idaho Power’s capacity in this segment is anticipated to be
667 MW. The following is a map of the described Magic Valley to Treasure Valley Gateway
West segments.
Gateway West—Segment 10
Gateway West segment 10 is the Midpoint–Cedar Hill line segment of Gateway West.
The Midpoint–Cedar Hill 500-kV line will provide connectivity between the existing Midpoint
substation and a future Cedar Hill substation, and likely the future Populus–Cedar Hill 500-kV
line, prior to Cedar Hill substation being constructed. The Midpoint–Cedar Hill 500-kV segment
is necessary to pair with PacifiCorp’s Populus–Cedar Hill 500-kV segment to enable PacifiCorp to
use its capacity gained via participation in the Midpoint–Hemingway #2 500-kV line. Therefore,
7.Transmission Planning
2023 Integrated Resource Plan Page 93
the company assumes Midpoint–Cedar Hill will necessarily correspond with the construction of
Midpoint–Hemingway #2.
Gateway West Cost Treatment and Modeling in the 2023 IRP
Similar to the B2H project, Idaho Power is working with
PacifiCorp to develop the Gateway West transmission
project, which is made up of several distinct phases listed
in Table 7.7. While B2H provides Idaho Power additional
access to the liquid Mid-C market hub, and therefore acts
as a stand-alone resource, the Gateway West project
serves a different function. Gateway West enables
additional resources to be interconnected onto the Idaho
Power transmission system east of the Treasure Valley.
Without Gateway West the quantity of incremental
resources is constrained.
The transmission capacity associated with Gateway West
can relieve three primary transmission constraints: 1) transmission capacity between eastern
Idaho and the Magic Valley (Borah West); 2) transmission capacity between the Magic Valley
and the Treasure Valley (Midpoint West); and 3) transmission capacity between the Mountain
Home area and the Treasure Valley (Boise East). The primary transmission constraints for
adding new resources east of the Treasure Valley are the Midpoint West and Boise East paths.
The Gateway West segment 8, segment 9, and segment 10 projects increase the transfer
capability for both the Midpoint West and Boise East paths.
For the 2023 IRP, the company allowed 1,725 MW of incremental wind and solar resources to
be interconnected to the existing grid, between 2024 and 2028, prior to the need to construct
the first phase of Gateway West. Beyond 1,725 MW of incremental wind and solar, the analysis
modeled each subsequent Gateway West addition as enabling 1,000 MW of incremental
resources onto the system. This 1,000 MW level was chosen above the anticipated 667 MW
capacity increase for each addition due to anticipated diversity among network generation
resources (all resources likely will not be at maximum output) and the opportunity to use other
methods, such as remedial action schemes or dynamic line ratings, to further optimize
transmission flow and resource interconnections.
After the two permitted Gateway West projects, the 2023 IRP modeled a future not yet
permitted transmission addition, Midpoint–Mayfield 500-kV. The IRP analysis modeled the
earliest possible in-service date as end-of-year 2039. The Midpoint–Mayfield 500-kV line
allowed for 2,000 MW of additional wind and solar resources. The company expects that the
Midpoint–Mayfield 500-kV line could be a rebuild of an existing 230-kV line. The company has
Gateway West map–Magic Valley to
Treasure Valley segments 8, 9, and 10.
7.Transmission Planning
Page 94 2023 Integrated Resource Plan
not begun permitting this line and expects to own all the capacity associated with the
upgraded line.
The Gateway West phase 2023 IRP modeling costs and assumptions are listed in Table 7.7.
Table 7.7 Gateway West phase modeling
Phase
In-Service
Date*
Incremental Resource
Capacity Enabled
Cost
(Levelized per year)**
Midpoint–Hemingway #2 500-kV (Segment 8),
and Midpoint–Cedar Hill 500-kV (Segment 10),
and Mayfield substation
12/2028* 1,000 $42.3 million
Cedar Hill–Hemingway 500-kV (Segment 9) and Cedar Hill substation 12/2030* 1,000 $25.2 million
Future non permitted phase: Midpoint–Mayfield 500-kV 12/2039 2,000 $21.7 million
*Idaho Power will continue to work with PacifiCorp on the timing and need for these Gateway West segments.
**The levelized costs in this table do not reflect offsetting transmission revenues from Idaho Power transmission customers.
To determine a cost-estimate for each phase, the company used costs associated with
its Gateway West federal permit, transmission cost-per-mile estimates for B2H,
and 500-kV substation estimates.
Southwest Intertie Project-North
Southwest Intertie Project-North (SWIP-N) is a proposed 285-mile 500-kV transmission line
being developed by Great Basin Transmission, LLC. SWIP-N would connect Idaho Power’s
Midpoint substation near Shoshone, Idaho, and the Robinson Summit substation near Ely,
Nevada. The project would provide a connection to the One Nevada 500-kV Line (ON Line),
which is an in-service transmission line between Robinson Summit and the Harry Allen
substation in the Las Vegas, Nevada, area. The two projects together are the combined SWIP.
The combined SWIP portion of the project between Midpoint and Harry Allen has
WECC-approved path ratings of 2,070 MW north-to-south and 1,920 MW south-to-north.
The addition of SWIP-N creates 1,117.5 MW of north-to-south capacity and 1,072.5 MW of
south-to-north capacity between Midpoint and Harry Allen for Great Basin Transmission.
Building on the SWIP-N sensitivity analysis performed in the previous 2021 IRP cycle that
showed potential cost savings with participation in the project, Idaho Power performed
additional analysis on the project in this IRP. The California Independent System Operator
(CAISO) has also expressed interest in the SWIP-N project through their most recent 2022–2023
Transmission Plan. CAISO’s primary interest in the project is in the north-to-south direction
while Idaho Power’s interest would be in the south-to-north direction to enable the company to
access the Desert Southwest wholesale market hubs. The Desert Southwest region has a
diverse seasonal load profile compared to Idaho Power and the Pacific Northwest. The market
can be accessed to help serve future Idaho Power peak winter season needs.
7.Transmission Planning
2023 Integrated Resource Plan Page 95
As part of the 2023 IRP, Idaho Power analyzed SWIP-N as providing a 500 MW resource
equivalent capacity, from the Desert Southwest, in the winter months beginning in 2027.
Given the expected very high solar buildout in the southwest, the company also assumed
SWIP-N could provide 50 MW of resource equivalent summer capacity in 2029, and 100 MW
starting in 2030 through the remainder of the plan.
To investigate a potential alternative to SWIP-N, Idaho Power analyzed NV Energy’s planned
Greenlink Nevada transmission projects as an option for obtaining additional firm capacity to
Desert Southwest markets. The Greenlink Nevada project consists of two proposed 500-kV
transmission lines: Greenlink West from Las Vegas, Nevada, to Yerington, Nevada, and
Greenlink North from Yerington, Nevada, to Robinson Summit substation near Ely, Nevada.
While the project will create additional capacity internally within Nevada, it does not create
capacity north of Robinson Summit from Nevada into Idaho. The Greenlink Nevada project is
not a viable for option for Idaho Power to access Desert Southwest markets.
Southwest Market Opportunity
The SWIP-N project, similar to the Four Corners
capacity, would enable Idaho Power to access the
seasonal load diversity that exists between Idaho
Power and utilities to the south. Figure 7.4,
created from historical FERC 714 Balancing
Authority Area (BAA) hourly load data, shows the
gap that exists between the Desert Southwest
summer and winter seasonal peaks. The large gap
that exists between the seasonal summer and
winter peaks indicates potential for excess capacity
in the winter season from the southwest markets
to help meet peak future demand needs for Idaho
Power during winter.
SWIP-N Preliminary Route.
7.Transmission Planning
Page 96 2023 Integrated Resource Plan
Figure 7.4 Historical Desert Southwest Summer and Winter Seasonal Peaks
The following Figure 7.5 is a forward looking forecast of the same Desert Southwest utilities
from the 2021 FERC Form 714 data. The gap between the forecasted summer peak and the
winter peak is projected to continue into the future.
Figure 7.5 Forecasted Desert Southwest Summer and Winter Seasonal Peaks
Federal Funding Opportunities for Transmission
Idaho Power continues to monitor federal funding opportunities for transmission development.
Most applicable to large transmission development is the federal Transmission Facilitation
Program from the Bipartisan Infrastructure Law. The Transmission Facilitation Program provides
federal support to help certain projects overcome initial financial hurdles. Under this program,
7.Transmission Planning
2023 Integrated Resource Plan Page 97
the DOE could serve as an anchor customer by subscribing to up to 50% of a planned project’s
capacity. The DOE would then look to sell this contracted capacity to recover costs. To be
eligible, the projects must be nearly “shovel ready” and be projects that would not otherwise
be constructed without federal support. The Transmission Facilitation Program will not consider
projects that are fully subscribed or have fully allocated sources of revenue. The B2H and
Gateway West projects would not qualify for this program.
Transmission Assumptions in the IRP Portfolios
Idaho Power makes resource location
assumptions to determine transmission
requirements as part of the IRP development
process. Supply-side resources included in the
resource stack typically require local transmission
improvements for integration into Idaho Power’s
system. Additional transmission improvement
requirements depend on the location and size of
the resource. The transmission assumptions and
transmission upgrade requirements for
incremental resources are summarized in
Table 7.8. The company assumed all resources
were located east of the Treasure Valley. Backbone transmission assumptions include an
assignment of the pro-rata share for transmission upgrades identified for resources east
of Boise.
Transmission lines under construction at the
Hemingway substation.
7.Transmission Planning
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Table 7.8 Transmission assumptions and requirements
Resource
Capacity
(MW)
Cost Assumption
Notes
Local Interconnection
Assumption
Hydrogen Combustion Turbine 170 Treasure Valley Area Connection to 230-kV Bus
Local Transmission Upgrades Required
Natural Gas CCCT 300 Treasure Valley Area Connection to 230-kV Bus
Transmission Line Upgrades Required
Natural Gas SCCT 170 Treasure Valley Area Connection to 230-kV Bus
Local Transmission Upgrades Required
Danskin 1 Retrofit SCCT to CCCT Conversion 90 Mountain Home Area Connection to 230-kV Bus
Nuclear SMR 100 Eastern Idaho Area Connection to 230-kV Bus
Transmission Upgrades Required
Geothermal 30 Raft River Area Assumes 138-kV Connection
Biomass Indirect—Anaerobic Digester 30 Magic Valley Area Assumes 138-kV Connection
Solar PV Utility-Scale 1-Axis Tracking 100 Mountain Home Area Connection to 230-kV Bus Local Transmission Upgrades Required
Wind—Wyoming 100 Within 5 Miles of Jim Bridger Connection to 345-kV Bus
Wind—Idaho 100 Magic Valley Area Assumes 345-kV Connection
Pumped Storage New Upper Reservoir & New Generation/Pumping Plant 250 Mountain Home Area Assumes 138-kV Connection Local Transmission Upgrades Required
Short Duration Storage Li-ion Battery 4-Hour 50 Treasure Valley Area Assumes 138-kV Connection
Short Duration Storage Li-ion Battery 4-Hour, Distribution-Connected
5 Treasure Valley Area Assumes Feeder Connection
Medium Duration Storage Li-ion Battery 8-Hour 50 Treasure Valley Area Assumes 138-kV Connection
Multi-Day Duration Storage
Iron-Air Battery 100-Hour
50 Treasure Valley Area Assumes 138-kV Connection
8.Planning Period Forecasts
2023 Integrated Resource Plan Page 99
8.PLANNING PERIOD FORECASTS
The IRP process requires numerous
forecasts and estimates, which can be
grouped into four main categories:
1.Load forecasts
2.Generation forecasts for existing
resources
3.Natural gas price forecasts
4.Resource cost estimates
The load and generation forecasts—
including supply-side resources,
DSM, and transmission import capability—are used to inform the IRP model in developing
portfolio buildouts. The following sections provide details on the forecasts prepared as part of
the 2023 IRP.
Load Forecast
Each year, Idaho Power prepares a forecast of energy sales. This forecast is a product of
historical system data and trends in electricity usage along with numerous external economic
and demographic factors.
Idaho Power has its annual peak demand in the summer, with peak loads driven by irrigation
pumps and air conditioning in June through September. Historically, Idaho Power’s growth rate
of the summertime peak-hour load has exceeded the growth of the average monthly load.
Both measures are important in planning future resources and are part of the load forecast
prepared for the 2023 IRP.
The anticipated average load and peak-hour demand forecasts represent Idaho Power’s most
probable outcomes for load requirements during the planning period. In addition, Idaho Power
prepares other probabilistic load forecasts to address the load variability associated with
abnormal weather and economic scenarios.
The anticipated forecast for system load growth is determined by summing the load forecasts
for individual classes of service, as described in Appendix A—Sales and Load Forecast.
For example, the anticipated annual average system load growth of 2.1% (over the period 2024
through 2043) comprises a residential load growth of 1.1%, a commercial load growth of 0.8%,
an irrigation load growth of 0.6%, an industrial load growth of 1.3%, and an additional firm load
growth of 9.1%. Given notable anticipated growth from industrial customers, the forecast
Chobani plant near Twin Falls, Idaho.
8.Planning Period Forecasts
Page 100 2023 Integrated Resource Plan
annual system load growth over the five-year period from 2024 through 2028 is 5.5%,
disproportionately weighted to those industrial customers.
The number of residential customers in Idaho Power’s service area is expected to increase
1.6% annually from 518,490 at the end of 2022 to nearly 724,000 by the end of 2043. Growth in
the number of customers within Idaho Power’s service area, combined with an expected
declining consumption per customer, results in a 1.1% average annual residential load-growth
rate over the forecast term.
Significant factors that influenced the outcome of the 2023 IRP load forecast include, but are
not limited to, the following items:
•Weather plays a primary role in impacting the load forecast on a monthly and seasonal
basis. In the anticipated load forecast of energy and peak-hour demand, Idaho Power
assumes average temperatures and precipitation over a 30-year meteorological
measurement period or defined as normal climatology. Probabilistic variations of
weather are also analyzed.
•The economic forecast used for the 2023 IRP reflects a softened expansionary economy
in Idaho over the near-term and reversion to the long-term trend of the service-area
economy. While Idaho had the highest residential population growth rate of any state in
the nation for the five years ending 2020, customer growth and residential permit
issuances have come down from those highs in 2022. However, net migration and
business investment continues to result in positive economic activity.
•DSM impacts—including energy efficiency programs, codes and standards, and other
naturally occurring efficiencies—are integrated into the sales forecast. These impacts
are expected to continue to erode use per customer over much of the forecast period.
•New industrial and Energy Service Agreement (ESA) customer requests are inherently
uncertain regarding location and capacity need. The anticipated load forecast reflects
only those industrial customers that have made a sufficient and significant binding
investment or interest indicating a commitment of the highest probability of locating in
the service area. The large number of businesses that have indicated some interest in
locating in Idaho Power’s service area and have not made sufficient commitments are
not included in the anticipated-case sales and load forecast.
•The electricity price forecast used to prepare the sales and load forecast in the 2023 IRP
reflects the additional plant investment and variable costs of integrating the resources
identified in the 2021 IRP Preferred Portfolio.
8.Planning Period Forecasts
2023 Integrated Resource Plan Page 101
Weather Effects
The 50th-percentile load forecast assumes average temperatures and precipitation over a
30-year meteorological measurement period, or normal climatology. This implies a 50% chance
loads will be higher or lower than the anticipated load forecast due to colder-than-normal or
hotter-than-normal temperatures and wetter-than-normal or drier-than-normal precipitation.
However, the 30-year normal temperatures have been increasing over the past several
decades, implying a cold bias in the calculation. Since actual loads can vary significantly
depending on weather conditions, additional scenarios for an increased load requirement were
analyzed to address load variability due to weather—the 70th- and 90th-percentile load
forecasts. The 70th-percentile weather was utilized in the anticipated case to adjust for any
systemic historic changes.
Idaho Power's operating results fluctuate seasonally and can be adversely affected by changes
in weather and climate. Idaho Power's peak electric power sales are bimodal over a year,
with demand in Idaho Power's service area peaking during the summer months. Currently,
summer months exhibit a reliance on the system for cooling load in tandem with requirements
for irrigation pumps. A secondary peak during the winter months also occurs, driven primarily
by colder temperatures and heating. Because Idaho Power is a predominantly summer peaking
utility, timing of precipitation and temperature can impact which of those months’ demand on
the system is greatest. Idaho Power tests differing weather probabilities hinged on a 30-year
normal period. A more detailed discussion of the weather-based probabilistic scenarios and
seasonal peaks is included in Appendix A—Sales and Load Forecast.
Weather is the primary factor affecting the load forecast on a monthly or seasonal basis.
During the forecast period, economic and demographic conditions also influence the
load forecast.
Economic Effects
Numerous external factors influence the sales and load forecast that are primarily economic
and demographic. Moody’s Analytics is the primary provider for these sets of data.
The national, state, Metropolitan Statistical Area (MSA), and county economic and
demographic projections are tailored to Idaho Power’s service area using an in-house economic
database. Specific demographic projections are also developed for the service area from
national and local census data. Additional data sources used to substantiate said economic data
include, but are not limited to, the United States Census Bureau, the Bureau of Labor Statistics,
the Idaho Department of Labor, Woods & Poole, Construction Monitor, and Federal Reserve
economic databases.
The state of Idaho had the highest population growth rate in the nation for several years,
ending in 2020. The number of households in Idaho is projected to grow at an annual rate of
8.Planning Period Forecasts
Page 102 2023 Integrated Resource Plan
1.6% during the forecast period, with most of the population growth centered on the
Boise–Nampa MSA. The Boise MSA (or the Treasure Valley) encompasses Ada, Boise, Canyon,
Gem, and Owyhee counties in southwestern Idaho. The number of households in the
Boise–Nampa MSA is projected to grow faster than the state of Idaho, at an annual rate of 2.2%
during the forecast period. In addition to the number of households, incomes, employment,
economic output, and electricity prices are economic components used to develop
load projections.
Idaho Power continues to manage a pipeline of prospective large-load customers
(over 1 MW)—both existing customers anticipating expansion and companies considering new
investment in the state—that are attracted to Idaho’s positive business climate and low electric
prices. Idaho Power’s economic development strategy is focused on optimizing Idaho Power’s
generation resources and infrastructure by attracting new business opportunities to our service
area in both Idaho and eastern Oregon. Idaho Power’s service offerings are benchmarked
against other utilities. The company also partners with the states and communities to support
local economic development strategies, and coordinates with large-load customers engaged in
a site selection process to locate in Idaho Power’s service area.
The 2023 IRP average annual system load forecast reflects continued growth in the service
area’s economy. While the economic and demographic variables have softened in 2022,
the long-term 2023 IRP forecast reflects a robust sales outlook through the planning period
given the combination of the strong demographic horizon for Idaho and commercial and
industrial investment activity.
Average-Energy Load Forecast
Potential monthly average-energy use by customers in Idaho Power’s service area is defined by
three load forecasts that reflect load uncertainty resulting from different weather-related
assumptions. Figure 8.1 and Table 8.1 show the results of the three forecasts used in the
2023 IRP as annual system load growth over the planning period. There is an approximate
50% probability Idaho Power’s load will exceed the 50th-percentile forecast, a 30% probability
of load exceeding the 70th-percentile forecast (planning condition), and a 10% probability of
load exceeding the 90th-percentile forecast. The projected 20-year average compound annual
growth rate in each of the forecasts is 2.1% over the 2024 through 2043 period.
8.Planning Period Forecasts
2023 Integrated Resource Plan Page 103
Figure 8.1 Average monthly load-growth forecast (aMW)
700
1,000
1,300
1,600
1,900
2,200
2,500
2,800
1987 1992 1997 2002 2007 2012 2017 2022 2027 2032 2037 2042
WA less Astaris Weather Adjusted 50th Percentile Anticipated 90th Percentile
8.Planning Period Forecasts
Page 104 2023 Integrated Resource Plan
Table 8.1 Load forecast—average monthly energy (aMW)
Year 50th Percentile Anticipated 90th Percentile
2024 1,974 2,024 2,087
2025 2,090 2,141 2,205
2026 2,308 2,360 2,425
2027 2,443 2,495 2,561
2028 2,507 2,561 2,627
2029 2,568 2,622 2,689
2030 2,640 2,695 2,763
2031 2,681 2,737 2,805
2032 2,699 2,755 2,825
2033 2,727 2,784 2,854
2034 2,749 2,807 2,878
2035 2,769 2,827 2,899
2036 2,783 2,841 2,914
2037 2,809 2,868 2,942
2038 2,830 2,890 2,964
2039 2,851 2,912 2,987
2040 2,865 2,926 3,001
2041 2,898 2,960 3,036
2042 2,917 2,980 3,057
2043 2,936 2,999 3,076
Growth Rate (2024–2043) 2.1% 2.1% 2.1%
Peak-Hour Load Forecast
The average-energy load forecast, as discussed in the preceding section, is an integral
component of the load forecast. The peak-hour load forecast is similarly integral. Peak-hour
forecasts are derived from the sales forecast, and as the impact of peak-day temperatures.
The system peak-hour load forecast includes the sum of the individual coincident peak
demands of residential, commercial, industrial, and irrigation customers, as well as
ESA customers.
Idaho Power’s system peak-hour load record—3,751 MW—was recorded on Wednesday,
June 30, 2021, at 7 p.m. Summertime peak-hour load growth accelerated in the previous
decade as air conditioning became standard in nearly all new home construction and new
commercial buildings. Growth in system peak demand slowed considerably in 2009, 2010,
and 2011—the consequences of a severe recession that brought home and business
construction to a standstill. Demand response programs have also been effective at reducing
peak demand in the summer. The 2023 IRP load forecast projects annual peak-hour load to
8.Planning Period Forecasts
2023 Integrated Resource Plan Page 105
grow by approximately 80 MW per year throughout the planning horizon. The peak-hour load
forecast does not reflect the company’s demand response programs.
Idaho Power’s winter peak-hour load record is 2,604 MW, recorded December 22, 2022,
at 9 a.m. Historical winter peak-hour load is much more variable than summer peak-hour load.
The winter peak variability is due to peak-day temperature variability in winter months, which is
far greater than the variability of peak-day temperatures in summer months.
Figure 8.2 and Table 8.2 summarize four forecast outcomes of Idaho Power’s estimated annual
system peak load—50th-, 70th-, 90th-, and 95th-percentile. As an example, the 95th-percentile
forecast uses the 95th-percentile peak-day average temperature to determine monthly
peak-hour demand. Alternative scenarios are based on their respective peak-day average
temperature probabilities to determine forecast outcomes.
Figure 8.2 Peak-hour load-growth forecast (MW)
1,500
1,900
2,300
2,700
3,100
3,500
3,900
4,300
4,700
5,100
1987 1992 1997 2002 2007 2012 2017 2022 2027 2032 2037 2042
Actual less Astaris Actual 50th Percentile
70th Percentile 90th Percentile 95th Percentile
8.Planning Period Forecasts
Page 106 2023 Integrated Resource Plan
Table 8.2 Load forecast—peak hour (MW)
Year 50th Percentile 70th Percentile 90th Percentile 95th Percentile
2022 (Actual) 3,568 3,568 3,568 3,568
2024 3,767 3,830 3,894 3,920
2025 3,938 4,001 4,065 4,091
2026 4,193 4,256 4,320 4,347
2027 4,344 4,406 4,470 4,497
2028 4,439 4,501 4,565 4,592
2029 4,522 4,585 4,649 4,676
2030 4,616 4,679 4,743 4,769
2031 4,685 4,747 4,811 4,838
2032 4,735 4,797 4,861 4,888
2033 4,784 4,847 4,911 4,937
2034 4,834 4,897 4,961 4,987
2035 4,881 4,944 5,008 5,035
2036 4,930 4,992 5,056 5,083
2037 4,978 5,041 5,105 5,131
2038 5,028 5,091 5,155 5,181
2039 5,077 5,140 5,204 5,230
2040 5,125 5,188 5,252 5,279
2041 5,180 5,242 5,306 5,333
2042 5,227 5,290 5,354 5,381
2043 5,274 5,337 5,401 5,427
Growth Rate (2024–2043) 1.8% 1.8% 1.7% 1.7%
The 70th-percentile peak-hour load forecast predicts peak-hour load will grow to 5,337 MW by
2043—an average annual compound growth rate of 1.8%. The projected average annual
compound growth rate of the 50th-percentile peak forecast is also 1.8%. The projected average
annual compound growth rate of the 90th- and 95th-percentile peak forecasts is 1.7%.
Additional Firm Load
The additional firm-load category consists of Idaho Power’s largest customers. Idaho Power’s
tariff requires the company to serve requests for electric service greater than 20 MW under
an under a special contract, or ESA, schedule negotiated between Idaho Power and each
large-power customer. The ESA and tariff schedule are approved by the appropriate state
commission. An ESA allows a customer-specific cost-of-service analysis and unique operating
characteristics to be accounted for in the agreement.
Individual energy and peak-demand forecasts are developed for ESA customers, including
Micron Technology, Inc.; Simplot Fertilizer Company (Simplot Fertilizer); INL; Brisbie, LLC
8.Planning Period Forecasts
2023 Integrated Resource Plan Page 107
(Meta Platforms, Inc.); and several anticipated new ESA customers. These ESA customers
comprise the entire forecast category labeled “additional firm load”.
Micron Technology
Micron Technology represents Idaho Power’s largest electric load for an individual customer
and employs more than 5,000 workers in the Boise MSA. The company operates its research
and development fabrication facility in Boise and performs a variety of other activities,
including product design and support; quality assurance; systems integration; and related
manufacturing, corporate, and general services. Micron Technology’s electricity use is a
function of the market demand for its products.
Simplot Fertilizer
This facility, named the Don Plant, is located just outside Pocatello, Idaho. The Don Plant is one
of four fertilizer manufacturing plants in the J.R. Simplot Company’s Agribusiness Group.
Vital to fertilizer production at the Don Plant is phosphate ore mined at Simplot’s Smoky
Canyon Mine on the Idaho–Wyoming border. According to industry standards, the Don Plant is
rated as one of the most cost-efficient fertilizer producers in North America. In total,
J.R. Simplot Company employs 2,000–3,000 people throughout its Idaho locations.
INL
INL is one of the United States DOE’s national laboratories and is the nation’s lead laboratory
for nuclear energy research, development, and demonstration. The DOE, in partnership with its
contractors, is focused on performing research and development in energy programs and
national defense. Much of the work to achieve this mission at INL is performed in
government-owned and leased buildings on the Research and Education Campus in Idaho Falls,
Idaho, and on the INL site, approximately 50 miles west of Idaho Falls. INL is a critical economic
driver and important asset to the state of Idaho with over 4,000 employees.
Brisbie, LLC (Meta Platforms, Inc.)
Idaho Power and Meta executed an ESA which was approved by the IPUC in May 2023.
Meta has announced the construction of a new data center in Kuna, Idaho. With an estimated
investment of $800 million, the Meta data center is projected to bring more than 1,200 jobs to
Kuna during peak construction and 100 operational jobs. Meta plans to support 100% of its
operations through the addition of new renewable resources connected to Idaho Power’s
system. The renewables support will be facilitated through a CEYW arrangement.
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Generation Forecast for Existing Resources
Hydroelectric Resources
For the 2023 IRP, Idaho Power continues
the practice of using 50th-percentile future
streamflow conditions for the Snake River
Basin as the basis for the projections of
monthly average hydroelectric generation.
The 50thpercentile means basin
streamflows are expected to exceed the
planning criteria 50% of the time and are
expected to be below the planning criteria
50% of the time.
Idaho Power uses a combination of two
modeling methods to develop future flows for the IRP. The first method accounts for surface
water regulation in the system and consists of two models built in the Center for Advanced
Decision Support for Water and Environmental Systems RiverWare modeling framework,
collectively referred to as the “Planning Models.” The first of these models covers the spatial
extent of the Snake River Basin from the headwaters to Brownlee Reservoir inflow. The second
model takes the results of the first and regulates the flows through the HCC. The second
method uses the Eastern Snake Plain Aquifer Model (ESPAM) to model aquifer management
practices implemented on the ESPA. Modeling for the 2023 IRP used version 2.2 of the ESPAM.
The two modeling methods used in combination produce a present-conditioned hydrologic
record for the Snake River Basin from water year 1981 through 2018, where the water
management system is representative of current conditions and operated according to current
constraints and requirements. This model adjusted for present conditions is then further
adjusted to account for specified conditions relating to Snake River reach gains,
water-management facilities, irrigation facilities, and operations that are expected to occur or
be in place over the planning horizon. The 50th-percentile modeled streamflows are then
derived from the results of the two Planning Models. Further discussion of flow modeling for
the 2023 IRP is included in Appendix C—Technical Report.
Discharges from the ESPA to the Snake River, commonly referred to as “reach gains,”
have shown a declining trend for several decades. Those declines are mirrored in documented
well-level and storage declines in the ESPA. Although reach gains improved from 2017 to 2020,
drought conditions in 2021 and 2022 have resulted in a return to low discharges for some
gauged springs. Since 2013, reach gains have remained below long-term historic median flows.
C.J. Strike Dam near Mountain Home, Idaho.
8.Planning Period Forecasts
2023 Integrated Resource Plan Page 109
A water management practice affecting Snake River streamflows is the release of water to
augment flows during salmon outmigration. Various federal agencies involved in salmon
migration studies have, in recent years, supported efforts to shift delivery of flow augmentation
water from the Upper Snake River and Boise River basins from the traditional months of July
and August to the spring months of April, May, and June. The objective of the streamflow
augmentation is to mimic the timing of naturally occurring flow conditions. Reported biological
opinions indicate the shift in water delivery is most likely to take place during worse-than-
median water years. Idaho Power continues to incorporate the shifted delivery of flow
augmentation water from the Upper Snake River and Boise River basins for the 2023 IRP.
Augmentation water delivered from the Payette River Basin is assumed to remain in July
and August.
Monthly average generation for Idaho Power’s hydroelectric resources is calculated within the
Planning Models described in Appendix C—Technical Report. The Planning Models
mathematically compute hydroelectric generation while adhering to the reservoir operating
constraints and requirements.
A representative measure of the streamflow condition is the annual inflow volume to Brownlee
Reservoir. Figure 8.3 shows historical annual Brownlee inflow volume as well as modeled
Brownlee inflow distributions for each year of the 2023 IRP. The 2021 IRP modeling results for
the 10th-, 30th-, 50th-, 70th-, and 90th-percentiles are shown for reference only to benchmark the
changes in modeled inflow between IRP cycles. As Figure 8.3 shows, the 2023 IRP modeling
results are similar to the 2021 IRP inflow volume results. The historical record demonstrates the
variability of inflows to Brownlee Reservoir. The modeled inflows include reductions related to
declining base flows in the Snake River and projected future management practices. As noted
previously in this section, these declines are assumed to continue through the planning horizon.
8.Planning Period Forecasts
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Figure 8.3 Brownlee inflow volume historical and modeled percentiles
Natural Gas Resources
Idaho Power owns and operates four natural gas SCCTs and one natural gas CCCT,
having combined existing plant capacity of 716 MW (capacity MW at International Standards
Organization (ISO) reference temperature of 59 degrees Fahrenheit). The company plans to
continue to operate each of its existing gas units through the 20-year planning horizon. Idaho
Power is monitoring alternative fuels, such as hydrogen, or hydrogen/natural-gas fuel blends,
for potential use in the future at existing natural gas plants.
Natural Gas Price Forecast
Based on the methodologies employed by Idaho Power’s peer utilities, as well as feedback
received during IRPAC meetings, Idaho Power enlisted Platts, a well-known third-party vendor,
as the source for the 2023 IRP planning case natural gas price forecast.
The Platts forecast information below was presented by the vendor representative at the
October 13, 2022, IRPAC meeting.
The third-party vendor uses the following fundamentals to develop its gas price forecast:
•Supply and demand balancing network model of the North American gas market
•Oil and natural gas rig count data
•Model pricing for the entire North American grid
•Model production, transmission, storage, and multi-sectoral demand every month
•Individual models of regional gas supply/demand, pipelines, rate zones and structures,
interconnects, capacities, storage areas and operations and combines these models into
an integrated North American gas grid
•Solves for competitive equilibrium, which clears supply and demand markets as well as
markets for transportation and storage
The following industry events helped inform the third-party 2023 natural gas price forecast
used in the IRP analysis:
•Status of North American major gas basins (Figure 8.4) and pipeline capacity
•Oil prices and the associated gas production
•New and existing natural gas electric generation and the possible replacement of coal
and nuclear capacity retirements
•Changes to residential and commercial customer gas demand from energy efficiency
gains as well as policy changes that include new gas appliance service bans
8.Planning Period Forecasts
2023 Integrated Resource Plan Page 111
•Global competition from gas producers (e.g., Russia and Qatar) and the role of liquefied
natural gas exports (e.g., the United States and Australia)
•Possible policy changes at the federal level included carbon price and societal cost
inclusion to natural gas as well as other wider energy policy developments
Figure 8.4 North American major gas basins
Platts’ March 2023 Henry Hub long-term forecast, after applying a basis differential and
transportation costs from Sumas, Washington, served as the planning case forecast of fueling
costs for existing and potential new natural gas generation on the Idaho Power system. Today,
Sumas is the primary hub for Idaho Power’s natural gas.
Because gas price forecasts are a significant driver of costs in the IRP process, Idaho Power also
relied on EIA’s alternative forecasts (High Oil and Gas Supply, and Low Oil and Gas Supply)
from their Annual Energy Outlook 2023 to examine the impact of gas prices on the IRP. More
details on the EIA forecasts can be found in their Annual Energy Outlook 2023.33
33 United States EIA, Annual Energy Outlook 2023 (AEO2023), (Washington, D.C., March 2023).
8.Planning Period Forecasts
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Natural Gas Transport
Ensuring pipeline capacity will be available for future natural gas generation will require the
reservation of pipeline capacity before a prospective resource’s in-service date. Consistent with
the 2021 IRP, Idaho Power believes that turnback Northwest Pipeline capacity (existing
contracts expiring without renewal) from Stanfield, Oregon, to Idaho—or even further south
into the Opal and Rocky Mountain hub region—could serve the need for natural gas generating
capacity for up to 600 MW of installed nameplate capacity and also augment fueling to
converted coal to gas units at the Jim Bridger Plant located off the Mountain West Overthrust
Pipeline. The 600 MW limit is derived from Northwest Pipeline’s turnback capacity from
Stanfield, Oregon, to Idaho as presented in Northwest Pipeline’s spring 2023 Customer Advisory
Board meeting.
Idaho Power projects (located in Idaho) that require additional natural gas generating capacity
beyond an incremental 600 MW of capacity would require an expansion of Northwest Pipeline
from the Rocky Mountain supply region to Idaho. Besides the uncertainty of acquiring capacity
on existing pipeline beyond that necessary for 600 MW of incremental natural gas generating
capacity, a pipeline expansion would provide diversification benefits from the current mix of
firm transportation composed of 60% from British Columbia, 40% from Alberta, and no firm
capacity from the Rocky Mountain supply region. In response to a request for a cost estimate
for a pipeline expansion from the Rocky Mountain supply region, Northwest Pipeline calculated
a levelized cost for a 30-year contract of $1.39/Million British Thermal Units (MMBtu) per day.
It is assumed that any additional transportation would be procured in the short-term capacity
release market, or through delivered supply transactions to cover 100% of the requirements on
any given day.
Natural Gas Storage Facilities
The majority of natural gas consumed in the northwest comes from western Canada and the
United States Rocky Mountain states. Most of this natural gas moves straight to end users
through a network of interstate pipelines, local gas mains, and other utility infrastructure.
Idaho Power also buffers a small share of its natural gas supply from underground
storage facilities.
The first of these facilities is Jackson Prairie Underground Natural Gas Storage. It is located in
Lewis County, Washington, about 100 miles south of Seattle. With 25 billion cubic feet of
working gas, and being interconnected with Northwest Pipeline, Jackson Prairie plays an
important role in ensuring reliable, cost-effective natural gas balancing service for Idaho Power
customers during annual summer and winter peaks for natural gas and power demand.
The second facility is Spire Storage, located in Southwest Wyoming, near Evanston in Uinta
County. This facility will have capacity available to Idaho Power in 2025. Due to its proximity to
8.Planning Period Forecasts
2023 Integrated Resource Plan Page 113
Opal Hub, a working capacity of 35 billion cubic feet of gas and interconnectivity with
five interstate pipelines, Spire Storage not only reliably and economically serves Idaho Power
customers but all major markets in the western United States.
Both Jackson Prairie and Spire Storage facilities provide reliability in fuel supply, intra-day
balancing for variable energy generation, and fueling diversity for Idaho Power’s gas
generation fleet.
Analysis of IRP Resources
For the 2023 IRP, Idaho Power continues to analyze resources based on cost, specifically the
cost of a resource to provide energy and capacity to the system. In addition to the ability to
provide flexible capacity, the system attributes analyzed include the ability to provide
dispatchable capacity, non-dispatchable (i.e., coincidental) capacity, and energy.
Importantly, energy in this analysis is considered to include not only baseload-type resources
but also resources, such as wind and solar, that provide relatively predictable output when
averaged over long periods (i.e., monthly, or longer). The resource attribute analysis also
designates those resources whose variable production gives rise to the need for
flexible capacity.
Resource Costs—IRP Resources
Resource costs are shown using two cost metrics: Levelized Cost of Capacity (LCOC) (fixed) and
Levelized Cost of Energy (LCOE). These metrics are discussed later in this section. Resources are
evaluated based upon their respective costs that will ultimately be funded by customers
through rates. In most cases, as with company-owned supply-side resources, that represents a
total resource cost (TRC) perspective. However, the TRC perspective is not exclusively applied in
the IRP. Examples where TRC is not the cost perspective analyzed includes energy efficiency
resources where the company incentivizes customer investment, and supply-side resources
whose production is purchased under long-term contract (e.g., PPA and PURPA).
Nevertheless, Idaho Power endeavors to conduct an evaluation of resource options using cost
analyses that yield a like-versus-like comparison between resources, and consequently is in the
best interest of customers.
In resource cost calculations, Idaho Power assumes potential IRP resources have varying
economic lives. Financial analysis for the IRP assumes the annual depreciation expense of
capital costs is based on an apportionment of the capital costs over the entire economic life of a
given resource.
The levelized costs for the various resource alternatives analyzed include capital costs, O&M
costs, fuel costs, and other applicable adders and credits (net of associated tax benefits).
The initial capital investment and associated capital costs of resources include engineering
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development, generating and ancillary equipment purchase, installation, plant construction,
and the costs for a transmission interconnection to Idaho Power’s network system. The capital
costs also include an AFUDC (capitalized interest). The O&M portion of each resource’s
levelized cost includes general estimates for property taxes and property insurance premiums.
The value of RECs is not included in the levelized cost estimates but is accounted for when
analyzing the total cost of each resource portfolio in AURORA.
Specific resource cost inputs, fuel forecasts, key financing assumptions, and other operating
parameters are provided in Appendix C—Technical Report.
LCOC—IRP Resources
The annual fixed revenue requirements, for each resource, are summed and levelized over the
assumed economic life and are presented in terms of dollars per kW of nameplate capacity per
month. Included in these LCOCs are the revenue requirements associated with initial resource
investment and associated capital cost and fixed O&M estimates. Resources are considered to
have varying economic lives, and the financial analysis to determine the annual depreciation of
capital costs is based on an apportioning of the capital costs over the entire economic life.
The expression of these costs in terms of kW of peaking capacity can have significant effect,
particularly for VERs having peaking capacity significantly less than installed capacity. The LCOC
values for the selectable 2023 IRP resources are provided in Table 8.3.
Table 8.3 Levelized cost of capacity (fixed) in 2024 dollars per kW per month
Supply-Side Resources Cost of Capital Non-Fuel O&M
Total Cost per
kW/mo.
Clean Peaking Gas—Hydrogen Combustion Turbine $8 $4 $12
Danskin 1 Retrofit—to CCCT Conversion $23 $4 $26
Baseload Gas—CCCT $14 $3 $17
Peaking Gas—SCCT $9 $4 $12
Nuclear—SMR $57 $25 $82
Geothermal $33 $18 $51
Biomass $31 $24 $54
Solar PV $4 $3 $7
Wind—Wyoming $5 $7 $12
Wind—Idaho $7 $7 $14
Short Duration Storage—Li Battery (4 hour) $12 $5 $17
Short Duration Storage—Li Battery (4 hour)—Dist. Connected $11 $4 $15
Medium Duration Storage—Li Battery (8 hour) $19 $8 $27
Long Duration Storage—Pumped Hydro (12 hour) $30 $6 $36
Multi-Day Storage—Iron-Air Battery (100 hour) $16 $4 $20
Note: columns may not perfectly add up due to rounding.
8.Planning Period Forecasts
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LCOE—IRP Resources
Certain resource alternatives carry low fixed costs and high variable operating costs, while
other alternatives require significantly higher capital investment and fixed operating costs but
have low (or zero) operating costs. The LCOE metric represents the estimated annual cost
(revenue requirements) per MWh for a resource based on an expected level of energy output
(capacity factor) over the economic life of the resource. The LCOE assuming the expected
capacity factors for each resource is shown in Table 8.4. Included in these costs are the capital
cost, non-fuel O&M, and fuel costs. The cost of recharge energy for storage resources and the
wholesale energy purchases and sales made available through B2H capacity are not included in
the graphed LCOE values.
The LCOE is provided assuming a common online date of 2024 for all resources and based on
Idaho Power specific financing assumptions. Idaho Power urges caution when comparing LCOE
values between different entities or publications because the valuation is dependent on several
underlying assumptions. The LCOE graphs also illustrate the effect of the ITC on storage
resources, as well as the effect of the PTC on non-carbon emitting resources (like solar and
wind). Idaho Power emphasizes that the LCOE is provided for informational purposes and is
essentially a convenient summary metric reflecting the approximate cost competitiveness of
different generating technologies. However, the LCOE is not an input into AURORA modeling
performed for the IRP.
When comparing LCOEs between resources, consistent assumptions for the computations must
be used. The LCOE metric is the annual cost of energy over the life of a resource converted into
an equivalent annual annuity. This is like the calculation used to determine a car payment;
however, in this case the car payment would also include the cost of gasoline to operate the car
and the cost of maintaining the car over its useful life.
An important input into the LCOE calculation is the assumed level of annual energy output over
the life of the resource being analyzed. The energy output is commonly expressed as a capacity
factor. At a higher capacity factor, the LCOE is reduced because of spreading resource fixed
costs over more MWh. Conversely, lower capacity factor assumptions reduce the MWh over
which resource fixed costs are spread, resulting in a higher LCOE.
For the portfolio cost analysis, resource fixed costs are annualized over the assumed economic
life for each resource and are applied only to the years of output within the IRP planning
period, thereby accounting for end effects.
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Table 8.4 Levelized cost of energy (at stated capacity factors) in 2024 dollars
Supply-Side Resources
Cost of
Capital
Non-Fuel
O&M Fuel
Total Cost per
MWh
Capacity
Factor
Clean Peaking Gas—
Hydrogen Combustion Turbine
$68 $50 $191 $309 12%
Danskin 1 Retrofit —SCCT to
CCCT Conversion
$56 $13 $46 $115 55%
Baseload Gas—CCCT $36 $12 $42 $89 55%
Peaking Gas—SCCT $98 $50 $66 $214 12%
Nuclear—SMR $83 $42 $13 $139 94%
Geothermal $50 $27 –$78 90%
Biomass $65 $61 $110 $236 64%
Solar PV $17 $15 –$31 31%
Wind—Wyoming $16 $19 –$35 47%
Wind—Idaho $28 $25 –$53 36%
Short Duration Storage—Li Battery
(4 hour)
$97 $37 –$134 17%
Short Duration Storage—
Li Battery (4 hour)—
Distribution-Connected
$88 $36 –$124 17%
Medium Duration Storage—
Li Battery (8 hour)
$77 $33 –$111 33%
Long Duration Storage—
Pumped Hydro (12 hour)
$82 $17 –$99 50%
Multi-Day Storage—Iron-Air Battery
(100 hour)
$148 $36 –$184 15%
Note: columns may not perfectly add up due to rounding
Resource Attributes—IRP Resources
While the cost metrics described in this section are informative, caution must be exercised
when comparing costs for resources providing different attributes to the power system.
In other words, it is important to consider both the cost and the economic value of each
individual resource. For the LCOC metric, this critical distinction between cost and economic
value arises because of differences for some resources between installed capacity and peaking
capacity. Specifically, for VERs, an installed capacity of 1 kW equates to an on-peak capacity of
less than 1 kW. For example, Idaho wind is estimated to have an LCOC of $14 per month per kW
of installed capacity. However, assuming wind delivers an ELCC equal to 20% of installed
capacity, the LCOC ($14/month/kW) converts to $70 per month per kW of peaking capacity.
For the LCOE metric, the critical distinction between the cost and economic value of resources
arises because of differences for some resources with respect to the timing at which MWh are
delivered. For example, some resources have similar LCOEs. However, the energy output from
one generating facility might tend to be delivered in a steady and predictable manner during
peak-loading periods. Conversely, the energy output from another generating facility might
8.Planning Period Forecasts
2023 Integrated Resource Plan Page 117
tend to deliver during the high-value peak loading periods less dependably. Utilizing wind,
for example, to meet peak demands can be effective when applying diversity (the wind may not
be blowing in one location but is likely blowing in another). All these characteristics should be
considered when comparing LCOEs for these resources.
In recognition of differences between resource attributes, potential IRP resources for the
2023 IRP are classified based on their attributes.
Table 8.5 Resource attributes
Resource Variable Energy Dispatchable Capacity-Providing Balancing/ Flexibility-Providing Energy Providing
Clean Peaking Gas—Hydrogen
Combustion Turbine ✔✔✔
Danskin 1 Retrofit—SCCT to CCCT
Conversion ✔✔✔
Baseload Gas—CCCT ✔✔✔
Peaking Gas—SCCT ✔✔✔
Nuclear—SMR ✔✔✔
Geothermal ✔✔
Biomass ✔✔
Solar PV ✔✔
Wind—Wyoming ✔✔
Wind—Idaho ✔✔
Short Duration Storage—Li Battery
(4 hour) ✔✔
Short Duration Storage—Li Battery (4 hour) – Dist. Connected ✔✔
Medium Duration Storage—Li Battery
(8 hour) ✔✔
Long Duration Storage—Pumped Hydro (12 hour) ✔✔
Multi-Day Storage—Iron-Air Battery
(100 hour) ✔✔
Energy Efficiency (Additional Bundles) ✔
Demand Response ✔
B2H 500-kV Project ✔✔✔
SWIP-North 500-kV Project ✔✔✔
The following resource attributes are considered in this analysis:
•Variable energy—Renewable resources characterized by variable output and potentially
causing an increased need for resources providing balancing or flexibility
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•Dispatchable capacity-providing—Resources that can be dispatched as needed to
provide capacity during periods of peak-hour loading or to provide output during
generally high-value periods
•Balancing/flexibility-providing—Fast-ramping resources capable of balancing the
variable output from VERs
•Energy-providing—Resources producing energy or reducing energy needs that are
relatively predictable when averaged over long time periods (i.e., monthly or longer)
Table 8.5 provides classification of potential IRP resources with respect to the above attributes.
The table also provides cost information on the estimated size potential and scalability for
each resource.
9.Portfolios
2023 Integrated Resource Plan Page 119
9.PORTFOLIOS
Throughout the 2023 IRP analysis, Idaho Power conducted an extensive review of IRP model
inputs, system settings and specifications, and model validation and verification. The objective
of the review was to ensure accuracy of the company’s modeling methods, processes,
and ultimately, the IRP results. The following sections describe the analysis process.
Capacity Expansion Modeling
For the 2023 IRP, and consistent with prior IRPs, Idaho Power used the LTCE capability of
AURORA to produce optimized portfolios under various future conditions. The logic of the
LTCE model optimizes resource additions and exits for each zone defined within the WECC.
As Idaho Power’s electrical system was modeled as a separate zone, the resource portfolios
produced by the LTCE and examined in this IRP are optimized for Idaho Power. The optimized
portfolios discussed in this document refer to the addition of supply-side and demand-side
resources for Idaho Power’s system and exits from current coal-generation units and converted
natural gas units.
The selection of new resources in the optimized portfolios maintain sufficient reserves as
defined in the model. To ensure the AURORA-produced optimized portfolios provided the
least-cost, least-risk future, the 2023 IRP analysis tested resource and transmission
configurations to find the Preferred Portfolio. These portfolios are discussed further in the
following sections.
For most scenarios, including planning conditions, the 2023 IRP portfolios selected from a broad
range of resource types, as well as varied amounts of nameplate generation additions:
•• Wind and solar (combination between 0 and 4,400 MW in total)
o Wind (between 0 and 1,800 MW in total)
•Wyoming (between 0 and 800 MW)
•Idaho (between 0 and 1,800 MW)
o Solar (between 0 and 2,600 MW in total)
•Standalone (between 0 and 2,600 MW)
•Standalone storage (between 0 and 7,200 MW in total)
o Pumped hydro (between 0 and 500 MW)
o Battery energy storage
•4-hour transmission-connected (between 0 and 4,000 MW)
•4-hour distribution-connected (between 0 and 100 MW)
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•8-hour transmission-connected (between 0 and 2,400 MW)
•100-hour transmission-connected (between 0 and 200 MW)
•Gas combustion (between 0 and 1,892 MW in total)
o CCCT (between 0 and 561 MW)
•New natural gas CCCT (between 0 and 300 MW)
•Danskin retrofit (between 0 and 261 MW)
o SCCT (between 0 and 720 MW)
•Natural gas SCCT (between 0 and 340 MW)
•Hydrogen SCCT (between 0 and 340 MW)
o Coal to natural gas conversion of Jim Bridger units 3 and 4 (between 0 and
350 MW)
o Coal to natural gas conversion of Valmy units 1 and 2 (between 0 and 261 MW)
•Nuclear SMR (between 0 and 1,200 MW)
•Biomass (between 0 and 150 MW)
•Geothermal (between 0 and 150 MW)
•Demand response (between 0 and additional 180 MW)
o Existing program expansion (between 0 and 100 MW)
o Pricing based programs (between 0 and 20 MW)
o Storage based programs (between 0 and 60 MW)
Capacity Planning Reserve Margin
For reliability planning purposes, Idaho Power plans to a position of capacity length as derived
from the 0.1 event-days per year LOLE threshold. One of the AURORA LTCE model’s objectives
is to meet a pre-determined PRM. Therefore, a translation is required between the probabilistic
LOLE analysis and the PRM calculation as necessitated by the AURORA LTCE model. Idaho
Power implements the LOLE methodology through the internally developed RCAT, which is
capable of calculating two of the necessary components of the PRM calculation: the resource
ELCC values and the capacity position. The PRM metric can be defined as the percentage of
expected capacity resources above forecasted peak demand. The PRM and ELCC values that are
calculated using the LOLE methodology are a direct input to the AURORA LTCE model. After
AURORA solves for and produces portfolios, select resource buildouts and their corresponding
data are analyzed with the LOLE methodology and tested to ensure they meet the pre-
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2023 Integrated Resource Plan Page 121
designated reliability hurdle through the calculation of annual capacity positions. This model
consolidation process is laid out in further detail in Figure 9.1.
Figure 9.1 Idaho Power’s reliability flowchart
In the 2021 IRP, the company derived static PRM and resource ELCC values that were held
constant throughout the 20-year planning horizon. As the RCAT and AURORA serve different
purposes in Idaho Power’s planning process, the company recognized that further efforts were
needed to translate and align the data exchanged between the two models. Historically,
the PRM was based on the peak load of a given year plus some additional amount to account
for abnormal weather events or equipment outages. This method worked well to ensure
reliability for Idaho Power as a summer peaking utility with mostly flexible generation
resources. As the wider industry, and the company, moves towards VERs whose hour-to-hour
and season-to-season generation changes, it is no longer viable to only contemplate peak hour
requirements.
To ensure that AURORA would recognize similar capacity needs as identified by the RCAT,
the company developed seasonal PRM values for years in the planning horizon that experience
significant changes in the resource buildout. While the capacity position calculated to assess
reliability is still evaluated on an annual basis because of Idaho Power’s 0.1 event-days per year
LOLE threshold, providing summer and winter PRM values to AURORA is a better
representation of the seasonal resource needs. The minimum seasonal PRM values in
AURORA were updated at different points in the planning horizon to capture the effect of
significant changes in the resource buildout. Historically, when a portfolio added predominantly
flexible generation resources it was also sufficient to give these resources a static peak capacity
contribution (or ELCC) as it was harmonious with a static PRM. As VER and Energy Limited
Resources (ELR) additions increase, static values no longer account for the reduced peak
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capacity contribution due to saturation nor do they capture the diversity benefit (positive or
negative) of a mix of different types of VERs and ELRs.
In addition, recognizing that the ELCC values of different VERs and ELRs fluctuate by season and
change from year to year depending on the portfolio resource mix, Idaho Power implemented
seasonal resource specific ELCC saturation curves for VERs and ELRs in the AURORA LTCE
model. The AURORA LTCE model cannot currently calculate the dynamic diversity benefit
caused by a changing resource mix. To overcome this limitation, a feedback process was
implemented between the AURORA LTCE model and the RCAT. As previously mentioned,
select years in the planning horizon were chosen where the capacity position for an AURORA
LTCE portfolio buildout was calculated using the RCAT. Once the capacity position was known,
the PRM in the AURORA LTCE model was modified so that both models identified a similar
capacity position. The feedback loop continued until both models converged.
More information on the LOLE methodology can be found in the Loss of Load Expectation
section of Appendix C—Technical Report.
Regulation Reserves
The 2020 VER Study provided the rules to define hourly reserves needed to reliably operate the
system based on current and future quantities of solar and wind generation and load
forecasted by season and time of day. The reserves are defined separately and incorporated
into the model. The reserve rules applied in the 2023 IRP are approximations intended to
generally reflect the amount of set-aside capacity needed to balance load and wind and solar
production while maintaining system reliability.
For the 2023 IRP analysis, Idaho Power developed approximations for the VER study’s
regulating reserve rules. The approximations express the monthly up and down regulation
reserve requirements as dynamic percentages of hourly load, wind production, and solar
production. The approximations used for the IRP are given in Table 9.1. For each hour of the
AURORA simulations, the dynamically determined regulating reserve is the sum of that
calculated for each individual element.
9. Portfolios
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Table 9.1 Regulation reserve requirements—percentage of hourly load MW, wind MW, and solar MW
% of Load % of Load % of Wind % of Wind % of Solar % of Solar
Month Load Up Load Dn Wind Up Wind Dn Solar Up Solar Dn
1 8.2% 1.7% 19.6% 19.6% 51.9% 57.6%
2 8.3% 1.6% 15.9% 21.2% 32.1% 39.3%
3 8.3% 1.7% 21.4% 22.1% 59.3% 59.3%
4 8.2% 1.7% 20.3% 26.0% 45.9% 50.6%
5 8.2% 1.6% 25.4% 34.5% 45.6% 53.7%
6 8.1% 1.6% 27.4% 21.7% 43.1% 29.3%
7 8.2% 1.4% 19.4% 22.0% 36.0% 24.6%
8 8.2% 1.5% 18.8% 23.8% 42.5% 31.9%
9 8.5% 1.8% 29.9% 29.9% 42.5% 40.5%
10 8.3% 1.6% 21.0% 31.8% 49.2% 51.4%
11 8.4% 1.8% 18.3% 29.2% 87.8% 71.8%
12 8.1% 1.6% 20.5% 39.3% 65.9% 73.3%
Inputs to AURORA Model
Portfolio Design Overview
Resource portfolios were developed under varying transmission options, future scenarios,
and sensitivities. The LTCE model applies a capacity PRM hurdle and regulation reserve
requirements, and then optimizes resource selections around those constraints to determine a
least-cost, least-risk portfolio. Available future resources possess a wide range of operating,
development, and environmental attributes. Impacts to system reliability and portfolio costs of
these resources depend on future assumptions. Each portfolio consists of a combination of
resources derived from the LTCE process that will enable Idaho Power to supply cost-effective
electricity to customers over the 20-year planning period.
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Figure 9.2 Analysis diagram
For the 2023 IRP, the company focused on key near-term decisions to ensure it identified an
optimal solution specific to its customers. Figure 9.2 details the initial evaluation where the
company compared AURORA-optimized portfolio options with varying transmission and natural
gas conversion assumptions. Each of these portfolios were optimized by the AURORA LTCE
model and validation and verification runs were performed to ensure portfolios were optimal
and reliable.
Portfolio Naming Conventions
Planning conditions and forecasts, as explained throughout the 2023 IRP, are the most probable
conditions and forecasts given the information available when the analysis is performed.
These conditions and forecasts are identified Table 9.2.
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Table 9.2. Planning conditions table
Condition Description Date
B2H Online July 2026
Gateway West Phase 1 Midpoint to Hemingway #2 500-kV Line
Midpoint to Cedar Hill 500-kV Line
Mayfield 500-kV substation
1,000 MW additional capacity
EOY 2028
Gateway West Phase 2 Cedar Hill to Hemingway 500-kV Line
Cedar Hill 500-kV substation
1,000 MW additional capacity
EOY 2030
Gateway West Phase 3 Midpoint to Mayfield 500-kV Line
2,000 MW additional capacity
2040
Natural Gas Price Forecast Long-term Platts Henry Hub March 2023
Carbon Price Adder Forecast California Energy Commission's Integrated Energy Policy Report
Preliminary GHG Allowance Price Projections.
Begins 2027.
December 2021
Load Forecast Idaho Power Generated—70th Percentile 2023
Coal Price Forecast Idaho Power Generated 2023
Hydro Conditions Idaho Power Generated—50th Percentile August 2022
Planning conditions are implied in each case. Deviations from those conditions are listed in each
case’s name. There are no base planning conditions for Valmy, as combinations of unit
conversions are individually tested. The following two naming conventions are explained as
examples. The case, “Valmy 1 & 2,” includes natural gas conversions of both Valmy Unit 1 and
Valmy Unit 2 as well as B2H in July of 2026, all three Gateway West phases as currently
forecasted, and all other forecasts and conditions specified in the Planning Conditions Table
(see Table 9.2). The case, “Nov2026 B2H Valmy 2,” includes a natural gas conversion of Valmy
Unit 2 and all the forecasts and conditions specified in the Planning Conditions Table with the
exception that the B2H in service date is November 2026 instead of July 2026.
The list below entails the main cases analyzed for the 2023 IRP.
1.Valmy 1 & 2 (conversion of both units)
2.Valmy 2 (conversion of unit 2 only)
3.Without Valmy (without any unit conversions and Valmy unit 2 exit in 2026)
4.Nov2026 B2H Valmy 1 & 2 (conversion of both units)
5.Nov2026 B2H Valmy 2 (conversion of unit 2 only)
6. Nov2026 B2H Without Valmy (without any unit conversions and Valmy unit 2 exit
in 2026)
7.Without B2H
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8.Without Gateway West Phases (this portfolio excludes Midpoint–Hemingway #2 500-kV,
Midpoint–Cedar Hill–Hemingway 500-kV, Midpoint–Mayfield 500-kV,
Mayfield substation, and Cedar Hill substation)
9.Gateway West Phase 1 Only (Midpoint–Hemingway #2 500 kV, Midpoint–Cedar Hill
500-kV, and Mayfield substation)
10.Gateway West Phases 1 & 2 Only (Midpoint–Hemingway #2 500-kV and Midpoint–
Cedar Hill–Hemingway 500-kV, Mayfield substation, and Cedar Hill substation)
The company then made relevant comparisons to determine the preferred path forward given
specific conditions. Portfolio costs and stochastic results are detailed in Chapter 10.
The company developed additional portfolios to explore various scenarios, which are all
described later in this section and are shown in Figure 9.2:
•Working with members of the IRPAC, the company developed future scenarios, in the
blue boxes under “Sensitivities” and “Informational Scenarios” headings
•Several validation and verification tests, in dark green boxes under the “Validation and
Verification” heading
•Various transmission robustness sensitivities and cost tests, in green boxes under the
“Other Transmission” heading
Future Scenarios—Purpose: Risk Evaluation
It can be helpful to compare the resources selected in the Preferred Portfolio, developed under
planning constraints and conditions, to resources selected in other possible scenarios. This is
especially useful for near-term resources. The goal of the comparisons is to understand how
resources would need to shift if various scenarios materialized.
Idaho Power identified scenarios to perform and then consulted with members of the IRPAC to
generate additional scenarios of interest. Each is included in this section and the results can be
found in Chapter 11.
The following is a description of the eleven future scenarios assessed in the 2023 IRP.
High Gas High Carbon
The High Gas High Carbon case adjusts the natural gas price and carbon adder price forecasts as
shown in Table 9.3 below.
Table 9.3 High Gas High Carbon table
Variable Designation Date
Natural Gas Price Forecast EIA Low Oil and Gas Supply March 2023
Carbon Price Adder Forecast Social Cost of Carbon, Methane, and Nitrous Oxide, Interim Estimates
under Executive Order 13990
February 2021
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Low Gas Zero Carbon
The Low Gas Zero Carbon case adjusts the natural gas price and carbon adder price forecasts as
shown in Table 9.4 below.
Table 9.4 Low Gas Zero Carbon table
Variable Designation Date
Natural Gas Price Forecast EIA High Oil and Gas Supply March 2023
Carbon Price Adder Forecast Consistent Zero Dollars per Ton
Constrained Storage
The Constrained Storage case examines what a resource portfolio would look like if the supply
chain associated with minerals required for storage technologies was constrained, resulting in
higher storage acquisition and construction prices. To model a constrained storage market,
rather than use the declining price curves associated with storage indicated in the National
Renewable Energy Laboratory’s Annual Technology Baseline, storage prices were set to
increase at the rate of inflation.
100% Clean by 2035
The 100% Clean by 2035 scenario assumes a legislative mandate to move toward 100% clean
energy by the year 2035 throughout the WECC. The scenario carbon emission constraints start
in 2024 with current emission levels and decrease to 0% by 2035. The same constraints were
applied to the WECC unless the existing state constraints were more restrictive.
Technology breakthroughs, such as cost-effective, long-duration energy storage,
nuclear energy, or hydrogen, will likely be required to meet this goal.
100% Clean by 2045
The 100% Clean by 2045 scenario assumes a legislative mandate to move toward 100% clean
energy by the year 2045 throughout the WECC. The scenario carbon emission constraints
start in 2024 with current emission levels and decrease to 20% by 2035 and 0% by 2045.
The same constraints were applied to the WECC unless the existing state constraints were
more restrictive.
Additional Large Load
Within the last few years, large industrial load interest has increased in the number of unique
inquiries and projected total demand for electricity in Idaho. This large-load growth scenario
examines how the resource portfolio might change if 100 and 200 MW of additional load were
to be added to the system. These loads start in 2026 and ramp up to full load in three years.
The load factor is similar to data center loads.
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New Forecasted PURPA
For the 2023 IRP analysis, based on the desire to adequately plan for the future, QF wind
facilities are not assumed to enter into replacement energy sales agreements with Idaho Power
when their existing contracts expire. This is consistent with the assumptions in the 2021 IRP.
If wind QF owners decide to enter into replacement agreements with Idaho Power when their
existing agreements expire, Idaho Power will update its capacity positions in its planning at that
time, and the updated position will be reflected in any subsequent resource procurement
efforts. This approach allows sufficient resources to be selected by the model regardless of
renewal status and allows the most up-to-date information to be considered in resource
procurement. This assumption is for planning purposes and has no impact on the ability of QFs
to decide whether or not to enter into a replacement agreement when their existing
agreement expires.
The company and IRP stakeholders agreed there is value in modeling wind project renewals as
well as a reasonable amount of new PURPA projects to observe how resource selection might
be affected. Based on the policy conditions in Idaho that have resulted in no Idaho-based
PURPA projects in recent years, the company did not consider it reasonable to include new
PURPA contracts within base planning conditions. Rather, the company aligned on a CSPP
scenario analysis with IRPAC. For this scenario, the CSPP wind renewal rate is set at 100% and
new PURPA contracts are modeled at an additional 57 MW each year, 23 MW from wind and
32 MW from solar, starting in 2028. The 57 MW of forecasted PURPA resources was derived by
identifying the average amount of new PURPA development the company experienced over the
10-year period from 2012 through 2021. This analysis showed an average of 57 MW of new
PURPA resources developed per year.
Extreme Weather
The Extreme Weather scenario includes both an increased demand forecast associated with
extreme temperature events and a variable supply of water from year to year. A 70th-percentile
energy 95th-percentile peak load forecast was applied for Idaho Power’s system. The variable
water supply uses hydropower modeling results from the Planning Models. Rather than use the
50th-percentile of the distribution, as is applied in the planning cases, the variable water supply
exhibits a mix of wet and dry cycles that have historically occurred in the hydrologic record.
Using the variable water supply is intended to help determine the sensitivity of resource
buildouts to hydrologic variability.
Rapid Electrification
The company forecasts moderate building and transportation electrification in all scenarios.
The Rapid Electrification scenario was developed to determine what kind of adjustments would
need to be made to the plan to accommodate a very rapid transition toward electrification.
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This rapid transition includes increasing the electric vehicle forecast and the penetration of
electric heat pumps for building heating and cooling. This aggressive forecast assumes over a
million electric vehicles as well as adoption of an 80% penetration of heat pump technology at
residences within the company’s service area. These levels are blended into the load forecast
over the next 20 years and do not factor in current economic consumer choice or the impact of
existing legislation or incentives. The Rapid Electrification scenario is meant to serve as a high
bookend on what is possible with the transition to electrification. As a bookend, the Rapid
Electrification scenario is considered improbable.
Regarding building electrification, as a suggestion from our IRPAC, air-source heat pumps
(ASHP) and ground-source heat pumps (GSHP) were modeled in separate portfolios.
The substantial electrification costs and the difference in cost between heat pumps are not
factored into this analysis.
Load Flattening
At the request of an IRPAC member, Idaho Power examined how resource needs would be met
in a scenario where residential peak demands were shifted in time to non-peak hours. For this
scenario, 10% of the peak each day was shifted to the time of day where the least load was
used. This modification to load would require significant measures to accomplish; however,
the aim of performing this sensitivity was not to identify how it would be done, but rather,
what the resource portfolio would look like if it were accomplished.
Model Validation and Verification
The purpose of the Model Validation and Verification testing is to ensure the selection of the
preferred portfolio is optimal and the model used in its selection is performing as expected.
Model inputs also go through a validation and verification process. The optimization model
validation and verification process includes a series of tests designed to show that the
resources selected by the model are optimized correctly with a focus on the Action Plan
Window (2024–2028). That is, by forcing the model to make different resource selections than
the optimized output, verify that the forced resource selection is suboptimal. New to the
2023 IRP, the model was allowed to reoptimize the remaining selections. This process allows for
robust testing of both key decisions like those concerning Bridger and Valmy as well as to test
the selection of new resources. A high-level diagram of several tests performed is shown in
Figure 9.3, followed by a discussion of these tests.
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Figure 9.3 Model validation and verification tests
Bridger
Background—During the 2023 IRP cycle, Idaho Power was informed that PacifiCorp was
analyzing the economics of converting Jim Bridger power plant units 3 and 4 from coal to
natural gas. This validation and verification test is designed to test the Preferred Portfolio’s
selection for units 3 and 4.
Tests—To validate the conversion, or lack thereof, for units 3 and 4 to natural gas—whatever
choice the model makes—the opposite will be forced into the model and then reoptimized
around that selection. See Table 10.4.
Result—The decision made to convert Bridger units 3 and 4 to natural gas operation as selected
in the Preferred Portfolio is the optimal decision based on the validation and verification tests.
For details on the resources selected in the test results, see Appendix C–Technical Report.
Valmy
Background—During the 2023 IRP cycle, Idaho Power analyzed conversion options for Valmy
units 1 and 2, which is detailed in Chapter 5. If either unit is converted, then the option also
exists to exit from the unit prior to the technical end of life for the plant.
Test—Given the importance of the Valmy conversion or exit decision in the 2023 IRP, each of
the conversion options for Valmy were individually tested in separate portfolios, with the
remaining buildout allowed to optimize around those options.
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Result—The decision to convert Valmy units 1 and 2 to natural gas operation as shown in the
Preferred Portfolio is the optimal decision based on a comparison of the main case portfolios.
For a cost comparison on each of the test results, see Table 10.2 and for a comparison of
resources selected, see Appendix C–Technical Report.
New Resource Selections
Wind
Background—Wind resources are a major part of the Preferred Portfolio. Recent supply chain
issues have increased the cost of wind production.
Test—Increase the cost of wind generation by 30% and determine how selected resources shift.
See Table 10.4 for a cost comparison and the Long-Term Capacity Expansion Results section in
Appendix C—Technical Report for the associated resource build.
Result—In an environment where wind costs are higher, the model can still select resources
that keep the system reliable. The increased cost of wind increases the cost of the portfolio,
as expected.
Battery Storage
Background—Battery storage resources are a major part of the Preferred Portfolio.
Test—Constrain the use of battery storage in the model by increasing the price, imitating a
supply shortage. See Table 10.3 for a cost comparison and the Long-Term Capacity Expansion
Results section in Appendix C—Technical Report for the associated resource build.
Result—The model is still able to select from resources that provide reliable capacity in the
constrained storage scenario. Constraining storage results in a higher portfolio cost,
as expected.
Nuclear
Background—Nuclear was not selected in the Preferred Portfolio.
Test—Force 100 MW of nuclear generation into the resource selection to offset the retirement
of the Bridger units in 2038 and allow the model to optimize all other resources. See Table 10.4
for a cost comparison and the Long-Term Capacity Expansion Results section in Appendix C—
Technical Report for the associated resource build.
Result—Forcing 100 MW of nuclear generation in 2038 increases costs, as expected.
Additional EE Bundles
Background—Additional EE bundles beyond the economic forecast were not selected in the
Preferred Portfolio.
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Test—Force six bundles of the lowest cost tier of EE measures in the Action Plan Window
(2026–2028) with a combined nameplate of 98 MW. See Table 10.4 for a cost comparison and
the Long-Term Capacity Expansion Results section in Appendix C—Technical Report for the
associated resource build.
Result—Forcing EE measures into the Preferred Portfolio resource selection increases costs,
as expected.
Demand Response
Background—No DR buckets were selected in the Preferred Portfolio.
Test—Force three bundles, one each to expand existing programs, add pricing programs, and
add storage programs, into the Action Plan Window (2026-2028) with a combined nameplate of
60 MW. See Table 10.4 for a cost comparison and the Long-Term Capacity Expansion Results
section in Appendix C—Technical Report for the associated resource build.
Result—Forcing EE measures into the Preferred Portfolio resource selection increases costs,
as expected.
B2H Timing
Background—During the 2023 IRP cycle, Idaho Power analyzed the in-service date for B2H.
Test—Given the importance of B2H’s in-service timing in the 2023 IRP, two timing scenarios
were individually tested in separate portfolios: the planned July 2026 date and a conservative,
post-summer, November 2026 date. The resource buildout was allowed to optimize around the
B2H timing.
Result—The July 2026 date results in a least-cost portfolio, as expected. If necessary,
Idaho Power can pivot to a November 2026 B2H in-service date but will see a moderate
portfolio cost increase, as shown in Table 10.2. For details on the resources selected for a
November 2026 B2H in-service date case, see Appendix C–Technical Report.
Natural Gas Price Variation Portfolios
Idaho Power tested portfolios under an additional high natural gas price forecast, EIA’s Low Oil
& Gas Supply forecast and low natural gas price forecast, EIA’s High Oil & Gas Supply forecast.
For more details and discussion on the natural gas price forecasts, see Chapter 8.
Carbon Price Variation Portfolios
Idaho Power developed portfolios primarily using the Planning Cast Carbon Cost forecast,
and utilized both a Zero Carbon Costs and High Carbon Costs forecast for the Low Gas Zero
Carbon scenario and the High Gas High Carbon scenario, respectively (see Chapter 10).
These carbon price scenarios for the 2023 IRP are shown in Figure 9.4:
9.Portfolios
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1.Zero Carbon Costs—assumes there will be no tax or fee on carbon emissions for those
regions not already subject to a carbon cost.
2.Planning Carbon Cost—is based on the California Energy Commission’s 2020 Integrated
Energy Policy Report Preliminary Green House Gas Allowance Price Projections,34 Low-
price Scenario. The carbon cost forecast assumes a price of roughly $28 per ton
beginning in 2027 and increases to over $83 per ton by the end of the IRP planning
horizon. The price applies to those regions that have a carbon price less than this
assumed price.
3.High Carbon Costs—is based on a federal interagency working group Technical Support
Document: Social Cost of Carbon, Methane, and Nitrous Oxide Interim Estimates under
Executive Order 13990.35 The carbon cost forecast assumes a price of approximately
$65 per ton beginning in 2024 that increases to more than $132 per ton (nominal
dollars) by the end of the IRP planning horizon. The price applies to those regions that
have a carbon price less than this assumed price.
34 2020 California Energy Commission’s Integrated Energy Policy Report Preliminary Green House Gas Allowance
Price Projections, Low-price Scenario. Energy Assessment Division (December 2021).
35 Technical Support Document: Social Cost of Carbon, Methane, and Nitrous Oxide Interim Estimates under
Executive Order 13990. Interagency Working Group and Social Cost of Greenhouse Gases, United States Government. February 2021. Accessed 9/1/2021 whitehouse.gov/wp-content/uploads/2021/02/Technical
SupportDocument_SocialCostofCarbonMethaneNitrousOxide.pdf.
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Figure 9.4 Carbon price forecast
$0.00
$20.00
$40.00
$60.00
$80.00
$100.00
$120.00
$140.00
2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043
2023 No Carbon Cost 2023 Planning Case Carbon Cost - CEC Low Price 2023 High Carbon Cost/SCC
10.Modeling Analysis
2023 Integrated Resource Plan Page 135
10.MODELING ANALYSIS
Portfolio Cost Analysis and Results
Once the portfolios are created using the LTCE model, Idaho Power uses AURORA as the
primary tool for modeling resource operations and determining operating costs for the 20-year
planning horizon. AURORA modeling results provide detailed estimates of zonal energy pricing
and resource operation and emissions data. The portfolio cost analysis is a step that occurs
following the development of the resource buildouts through the LTCE model.
The AURORA software applies economic principles and dispatch simulations to model the
relationships between generation, transmission, and demand to forecast zonal prices.
The operation of existing and future resources is based on forecasts of key fundamental
elements, such as demand, fuel prices, hydroelectric conditions, and operating characteristics
of new resources. Various mathematical algorithms are used in unit dispatch, unit commitment,
and regional pool-pricing logic. The algorithms simulate the regional electrical system to
determine how utility generation and transmission resources operate to serve load.
Portfolio costs are calculated as the NPV of the 20-year stream of annualized costs, fixed and
variable, for each portfolio. Financial variables used in the analysis are shown in Table 10.1.
Each resource portfolio was evaluated using the same set of financial variables.
Table 10.1 Financial assumptions
Financial Variable Value
Discount Rate (weighted average capital cost) 7.12%
Composite tax rate 25.74%
Deferred rate 21.30%
General O&M escalation rate 2.60%
Annual property tax rate (% of investment) 0.44%
B2H annual property tax rate (% of investment) 0.70%
Property tax escalation rate 3.00%
B2H property tax escalation rate 1.05%
Annual insurance premium (% of investment) 0.046%
B2H annual insurance premium (% of investment) 0.003%
Insurance escalation rate 5.00%
B2H insurance escalation rate 5.00%
AFUDC rate (annual) 7.50%
The purpose of the AURORA hourly simulations is to compare how portfolios perform
throughout the 20-year timeframe of the IRP. These simulations include the costs associated
10.Modeling Analysis
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with adding generation resources (both supply-side and demand-side) and optimally
dispatching the resources to meet the constraints within the model. The results from the main
case simulations, including different transmission and Valmy conversion assumptions,
are shown in Table 10.2. These different portfolios and their associated costs can be compared
as potential options for a preferred portfolio.
Table 10.2 2023 IRP main cases
Portfolio NPV years 2024–2043 ($ x 1,000,000)
Preferred Portfolio (Valmy 1 & 2) $9,746
Valmy 2 $9,795
Without Valmy $9,824
Nov2026 B2H Valmy 1 & 2 $9,767
Nov2026 B2H Valmy 2 $9,880
Nov2026 B2H Without Valmy $10,192
Without B2H $10,582
Without GWW Phases $10,326
GWW Phase 1 Only $10,263
GWW Phases 1 & 2 Only $9,759
This comparison, as well as the stochastic risk analysis applied to select portfolios from this list
(see the Stochastic Risk Analysis section of this chapter), indicate the Valmy 1 & 2 portfolio best
minimizes both cost and risk and is the appropriate choice for the Preferred Portfolio.
The scenarios listed in Table 10.3 were sensitivities tested on the Preferred Portfolio and are
included to show the associated costs. Please note that these scenarios have varying conditions
and constraints (see Chapter 10) associated with each specific future. Comparisons made
between these scenario costs must take this into account. As an example, an alternative
portfolio developed in a future with low natural gas prices and no carbon price adder (Low Gas
Zero Carbon) would have a lower cost than the Preferred Portfolio (Valmy 1 & 2), but that lower
cost would be attributable to both the direct influence on Idaho Power resources caused by the
variable adjustments and the convolution of changes indirectly caused by their adjustments in
the wider WECC.
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Table 10.3 2023 IRP sensitivities
Portfolio NPV years 2024–2043 ($ x 1,000,000)
Preferred Portfolio (Valmy 1 & 2) $9,746
High Gas High Carbon $12,520
Low Gas Zero Carbon $8,594
Constrained Storage $10,007
100% Clean by 2035 $11,351
100% Clean by 2045 $9,808
Additional Large Load (100 MW) $10,236
Additional Large Load (200 MW) $10,747
New Forecasted PURPA $10,720
Extreme Weather $10,211
Rapid Electrification (ASHP) $12,271
Rapid Electrification (GSHP) $11,175
Load Flattening $10,663
The validation and verification tests are listed in Table 10.4. These were modeling simulations
performed on the Preferred Portfolio, with changes to the resources identified in the
Near-Term Action Plan window, to ensure the model was optimizing correctly and to test
assumptions. More details on the setup and expected outcome of each test are provided in
Chapter 9.
Table 10.4 2023 IRP validation and verification tests
Portfolio NPV years 2024–2043 ($ x 1,000,000)
Preferred Portfolio (Valmy 1 & 2) $9,746
V&V Without Bridger 3 & 4 $9,945
V&V Valmy 1 & 2 Early Exit $9,803
V&V Wind +30% Cost $10,397
V&V Nuclear $10,013
V&V Energy Efficiency $10,042
V&V Demand Response $9,816
Portfolio Emission Results
Figure 10.1 compares the full 20-year emissions of the company’s 2023 IRP Preferred Portfolio
contenders (main cases). In Figure 10.1, from left to right, the first six cases are the
predicted planning conditions emissions associated with the Valmy conversion permutations
in both the July and November B2H timing scenarios. The seventh case from the left is the
Without B2H case emissions and the final three cases are the Gateway West sensitivities.
Each of the six Valmy study cases show similar total emissions over the 20-year planning
10.Modeling Analysis
Page 138 2023 Integrated Resource Plan
period with the percent difference between the max and min cases being less than 6%.
Generally, the November B2H cases show marginally lower emissions over the 20-year planning
horizon. The resources needed to replace the B2H capacity in the summer of 2026 slightly
lower emissions but increase costs over the July B2H cases as seen in Table 10.2. Without B2H,
the model builds new gas resources starting with a CCCT in 2029 which increases
overall emissions.
The Gateway West sensitivities show that the access Gateway West provides to renewables
significantly decreases portfolio emissions. Indeed, the case without any Gateway West phases
has the greatest emissions of the preferred portfolio contenders.
The information presented in figures 1.4 and 3.2 demonstrate that Idaho Power’s CO2
emissions can be expected to trend downward over time. Idaho Power will continue to
evaluate resource needs and alternatives that balance cost and risk, including the relative
potential CO2 emissions.
10.Modeling Analysis
2023 Integrated Resource Plan Page 139
Figure 10.1 Estimated portfolio emissions from 2021–2040
0
5,000,000
10,000,000
15,000,000
20,000,000
25,000,000
30,000,000
35,000,000
40,000,000
45,000,000
50,000,000
Without Valmy Valmy 2 Valmy 1 & 2 Without Valmy Valmy 2 Valmy 1 & 2 Without B2H Without GWW
Phases
GWW Phase 1
Only
GWW Phase 1
and 2 Only
Jul2026 B2H Nov2026 B2H Without B2H GWW Sensetivities
Main Cases CO2 Emissions (Metric Tons)
2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043
10. Modeling Analysis
Page 140 2023 Integrated Resource Plan
In conclusion, the Preferred Portfolio (Valmy 1 & 2) strikes an appropriate balance of cost and
risk while simultaneously reducing annual planning conditions emissions by more than 80%
comparing 2024 to 2043. The Preferred Portfolio also lays a cost-effective foundation to build
upon for further emissions reductions into the future. Idaho Power believes that technological
advances will continue to occur to allow the company to reliably and cost-effectively achieve its
goal of providing 100% clean energy by 2045.
For additional details on emissions for the 2023 IRP portfolios, please see the Portfolio
Emissions Forecast section in Appendix C—Technical Report.
Qualitative Risk Analysis
Major Qualitative Risks
Supply Chain—For the last few years, various components and products have encountered
supply chain issues. Supply chain issues limit the availability of resources and increase financial
risk because low supply results in higher costs. Supply chain issues can also impact the ability to
acquire resources when they are needed.
Fuel Supply—All generation resources require fuel to provide electricity. Different resource
types have different fuel supply risks. Thermal resources like coal and natural gas rely on fuel
supply infrastructure to produce and transport fuel by rail or pipeline and include mining or
drilling facilities. New fuel supply chains like hydrogen or advanced nuclear reactors require
new fuel which have yet to be developed at scale or a commercially viable price.
Fuel supply infrastructure has several risks when evaluating resources; it is susceptible to
outages from weather, mechanical failures, labor unrest, etc. Fuel supply infrastructure can be
limited in its existing availability to increase delivery of fuel to a geographic area that limits
resources dependent on the capacity constrained infrastructure.
Fuel Price Volatility—Fuel prices can be volatile and impact a plant’s economics and usefulness
to our customers both in the short and long term. Resources requiring purchased fuels like
natural gas have a higher exposure to fuel price risk.
Market Price Volatility—Portfolios with resources that increase imports or exports heighten
the exposure to a portfolio cost variability brought on by changes in market price and energy
availability. Market price volatility is often dependent on regional fuel supply availability,
weather, and fuel price risks. Resources, like wind and solar, that cannot respond to market
price signals, expose the customer to higher short-term market price volatility.
Some resources can act as a hedge on market price volatility. Transmission can help reduce
market volatility by allowing power to flow between regions during times of surplus or need.
Storage resources can produce benefits from market volatility through arbitrage (charging at
times when market prices are low and discharging when market prices are high).
10.Modeling Analysis
2023 Integrated Resource Plan Page 141
Market Access—With many utilities including Idaho Power relying more on resources like wind
and solar, the ability to access markets like the EIM becomes increasingly important. Lack of
market access can cause considerable wholesale price fluctuations and high costs as well as
present reliability concerns during times of need.
Siting and Permitting—All generation and transmission resources in the portfolios require
siting and permitting for the resource to be developed. Siting and permitting processes are
uncertain and time-consuming, increasing the risk of unsuccessful or prolonged resource
acquisition resulting in an adverse impact on economic planning and operations. Resources that
require air and water permits or that have large geographic footprints have a higher risk.
All resources considered have some level of this qualitative risk. Portfolios with resources that
are already through significant portions of the permitting process, like B2H and Gateway West,
have a lower level of siting and permitting risk.
Emerging Technology—The potential for new or developing technologies to underperform
relative to expectations (cost, operational characteristics, time to market, etc.). These risks can
be difficult to predict and manage, as the technologies are often new and untested.
Partnerships—Idaho Power is a partner in generation facilities and is jointly permitting and
siting transmission facilities in anticipation of partner participation in construction and
ownership of these facilities. Coordinating partner need and timing of resource acquisition or
retirement increases the risk of an Idaho Power timing or planning assumption not being
met. Partner risk may adversely impact customers economically and adversely impact
system reliability.
Federal and State Regulatory and Legislative Risks—There are many federal and state rules
governing power supply and planning. The risk of future rules altering the economics of new
resources or Idaho Power’s electrical system composition is an important consideration.
Examples include carbon emission limits or price adders, PURPA rules governing renewable
resource contracts, tax incentives and subsidies for renewable generation or other
environmental or political reasons. New or changed rules could have an adverse economic
impact on customers and impact system reliability.
Each resource possesses a set of qualitative risks that, when combined over the study period,
results in a unique and varied qualitative portfolio risk profile. Assessing a portfolio’s aggregate
risk profile is a subjective process weighing each component resource’s characteristics against
the potential bad outcomes for each resource and the portfolio of resources in aggregate.
Idaho Power considered how qualitative risks affect each resource portfolio. Although the
qualitative risk analysis performed is expansive, it is not exhaustive. For brevity, Idaho Power
has limited the qualitative risk analysis to those risks that are typical within the power industry
10. Modeling Analysis
Page 142 2023 Integrated Resource Plan
and accordingly does not consider exceedingly rare or hypothetical “black swan” events when
performing qualitative risk analysis.
For purposes of risk assessment, each portfolio and risk is assigned a low-, medium-,
or high-risk level. Consideration was given to both the likelihood and potential impact of each
risk. The results of Idaho Power’s qualitative risk assessment are presented in Table 10.5:
Table 10.5 Qualitative risk comparison
Valmy 1 & 2 Low Low Medium Medium Low Medium Medium Medium
Without
Valmy Low Medium Medium Medium Medium Medium Low Medium
Without
B2H Medium Medium High High High Medium Medium High
GWW High High Medium Medium High High Medium High
Phase 1 High High Medium Medium Medium High Medium High
Stochastic Risk Analysis
The stochastic risk analysis assesses the effect on portfolio costs when select variables have
values different from their planning-case levels. Stochastic variables are selected based on the
degree to which there is uncertainty regarding their forecasts and the degree to which they can
affect the analysis results (i.e., portfolio costs).
The purpose of the analysis is to help understand the range of portfolio costs across the full
extent of stochastic shocks (i.e., across the full set of stochastic iterations) and how the ranges
for portfolios differ. It is used to identify the probabilities of various risks and the shape of those
risks. To assess stochastic risk, the key drivers of natural gas prices, customer load,
hydroelectric generation, and carbon prices are allowed to vary based on their historical
variance. A full description of how these variables were modeled in the stochastic analysis can
be found in the Stochastic Risk Analysis section of Appendix C—Technical Report.
In Figure 10.2 below, each line represents the likelihood of occurrence by NPV. Higher values
on the line represent a higher probability of occurrence, with values near the horizontal
axis representing improbable events. Values that occur toward the left have lower cost,
while values toward the right have higher cost. As indicated by the peak of the graph
being furthest left, the results of the stochastic analysis show that the Preferred Portfolio
(Valmy 1 & 2) has the lowest cost given a range of natural gas prices, load forecasts,
carbon prices, and hydroelectric generation levels.
10.Modeling Analysis
2023 Integrated Resource Plan Page 143
Figure 10.2 NPV stochastic probability kernel—Preferred Portfolio contenders (likelihood by NPV [$ x 1,000])
Loss of Load Expectation Based Reliability Evaluation of Portfolios
As a post-processing reliability evaluation, Idaho Power calculated the annual capacity position
with the RCAT of select AURORA-produced portfolios to ensure the 20-year load and resource
buildouts achieved the pre-determined reliability threshold.
The annual capacity position is obtained by averaging the resulting size of a perfect generating
unit required to achieve a 0.1 event-days per year LOLE from each of the RCAT’s six test years.
If the LOLE-derived reliability evaluation found any select portfolio to have one or more years
that resulted in a capacity shortfall, the company recalibrated the seasonal PRM points in
AURORA and reran the LTCE which would again be tested for reliability.
The LOLE-derived evaluation is a minimum requirement for portfolios to be considered
capacity reliable, however, there are other factors that drive resource selections and the
resulting annual capacity positions. The AURORA LTCE model can select resources to address
regulation reserves and energy requirements. Also, while VERs and ELRs can be added in more
granular increments to meet the different AURORA LTCE requirements, other resources
(i.e., coal-to-gas conversions and hydrogen units) must be selected at their identified
0.0%
0.5%
1.0%
1.5%
2.0%
2.5%
3.0%
3.5%
4.0%
Jul2026 B2H No Valmy Jul2026 B2H Valmy 2 Jul2026 B2H Valmy 1 & 2
Nov2026 B2H No Valmy Nov2026 B2H Valmy 2 Nov2026 B2H Valmy 1 & 2
10. Modeling Analysis
Page 144 2023 Integrated Resource Plan
nameplate capacity and at a specific time. Historically, Idaho Power has been capacity
constrained, meaning peak capacity was the driving factor for acquiring resources. However,
with the increased penetration of energy storage, energy needs and economics could drive
resource additions.
An in-depth discussion of the reliability LOLE calculation process can be found in the Loss of
Load Expectation section of Appendix C—Technical Report.
Annual Capacity Positions of the Preferred Portfolio
The annual capacity positions for the Preferred Portfolio are provided in Table 10.6,
which shows an annual position of capacity length for all years of the planning horizon meeting
the company’s reliability threshold.
Table 10.6 Preferred Portfolio annual capacity positions (MW)
Year July 2026 B2H &
Valmy 1 & 2 Gas Conversion
2024 11 Length
2025 3 Length
2026 224 Length
2027 284 Length
2028 211 Length
2029 126 Length
2030 134 Length
2031 131 Length
2032 157 Length
2033 137 Length
2034 126 Length
2035 117 Length
2036 108 Length
2037 111 Length
2038 45 Length
2039 54 Length
2040 62 Length
2041 56 Length
2042 49 Length
2043 57 Length

All main cases were in a position of capacity length for all twenty years of the planning horizon.

11. Preferred Portfolio and Near-Term Action Plan
2023 Integrated Resource Plan Page 145
11. PREFERRED PORTFOLIO AND
NEAR-TERM ACTION PLAN
Preferred Portfolio
The 2023 IRP scenario analysis strategy focused on key near-term decisions and varying
sensitivities to ensure that it had identified an optimal solution specific to Idaho Power and its
customers. The company first identified main cases with resource buildouts driven by the
timing of B2H, the inclusion of Gateway West, and assumptions related to Valmy unit
conversions. Once portfolio buildouts were generated, to evaluate future cost risks,
the company performed a cost analysis for the main cases by performing a stochastic analysis
on the portfolios (see Chapter 10).
The company also evaluated the qualitative risks and evaluated the reliability of each of the
main cases (see Chapter 10).
Using the Preferred Portfolio (Valmy 1 & 2), the company developed additional portfolios to do
the following:
1. Evaluate risk associated with different futures and sensitivities (discussed later in this
Chapter)
2. Perform validation and verification tests on the Preferred Portfolio
The Preferred Portfolio (Valmy 1 & 2) follows.

11. Preferred Portfolio and Near-Term Action Plan
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Table 11.1Preferred Portfolio resource selections
Preferred Portfolio (MW)
Year
Coal Exits Gas H2 Wind Solar 4Hr 8Hr 100Hr Trans. Geo DR
EE Forecast EE Bundles
2024 -357 357 0 0 100 96 0 0 0 0 0 17 0
2025 0 0 0 0 200 227 0 0 0 0 0 18 0
2026 -134 261 0 0 100 0 0 0 Jul B2H 0 0 19 0
2027 0 0 0 400 375 5 0 0 0 0 0 20 0
2028 0 0 0 400 150 5 0 0 0 0 0 21 0
2029 0 0 0 400 0 5 0 0 GWW1 0 20 22 0
2030 -350 350 0 100 500 155 0 0 0 30 0 21 0
2031 0 0 0 400 400 5 0 0 GWW2 0 0 21 0
2032 0 0 0 100 100 205 0 0 0 0 0 20 0
2033 0 0 0 0 0 105 0 0 0 0 20 20 0
2034 0 0 0 0 0 5 0 0 0 0 40 19 0
2035 0 0 0 0 0 5 0 0 0 0 40 18 0
2036 0 0 0 0 0 5 0 0 0 0 40 17 0
2037 0 0 0 0 0 55 50 0 0 0 0 17 0
2038 0 -706 340 0 0 155 50 200 0 0 0 17 0
2039 0 0 0 0 0 5 50 0 0 0 0 15 0
2040 0 0 0 0 400 5 0 0 GWW3 0 0 14 0
2041 0 0 0 0 200 5 0 0 0 0 0 14 0
2042 0 0 0 0 200 55 0 0 0 0 0 14 0
2043 0 0 0 0 600 0 0 0 0 0 0 14 0
Sub
Total -841 261 340 1,800 3,325 1,103 150 200 30 160 360 0
Total 6,888
The following items are included in Table 11.1:
•The addition of 3,325 MW of solar generation, including expected solar projects and
solar to support the energy needs of large industrial customers.
•The conversion of Bridger units 1 and 2 (a combined 357 MW) is shown as a coal exit
and a gas addition in 2024. These units are exited at the end of their useful life at the
end of 2037.
•The conversion of Valmy units 1 and 2 (a combined 261 MW) occurs in 2026.
Because Idaho Power exited coal operations at Valmy Unit 1, only Valmy Unit 2 is
shown in that year as a coal exit. These units operate through the planning horizon.
•The conversion of Bridger units 3 and 4 (a combined 350 MW) occurs in 2030.
These units are exited at the end of their useful life at the end of 2037.
11. Preferred Portfolio and Near-Term Action Plan
2023 Integrated Resource Plan Page 147
• A total of 1,800 MW of economic wind projects are identified from 2027 through 2032.
The quantity of wind and solar additions are dependent on the Gateway West
transmission phases that are constructed.
• A total of 1,373 MW of energy storage, which includes the energy storage projects
already contracted for completion in 2024 and 2025.
• In addition to meeting system resource needs, 80 MW of distribution-connected storage
projects are intended to defer T&D investments.
• The B2H and Gateway West transmission lines (GWW1: Midpoint–Hemingway #2,
Midpoint–Cedar Hill, and Mayfield substation; GWW2:
Cedar Hill–Hemingway and Cedar Hill substation; and GWW 3: Midpoint–Mayfield)
are represented in the Trans. column in 2026, 2029, 2031, and 2040, respectively.
• New to the 2023 IRP, hydrogen peaking units are identified. These units are identified in
2038 to facilitate the replacement of the Bridger units.
• A single 30 MW geothermal generation facility was selected in 2030.
• The combination of 160 MW of DR which represent both an expansion of the company’s
existing DR program and new programs.
• The energy efficiency (EE) Forecast column shows a total of 360 MW of cost-effective EE
measures that will be added to Idaho Power’s system to meet growing energy demand.
These EE measures were identified in the EE Potential Assessment.

11. Preferred Portfolio and Near-Term Action Plan
Page 148 2023 Integrated Resource Plan
Preferred Portfolio Compared to Varying Future Scenarios
High Gas High Carbon
The following portfolio of resources was optimized for a future where gas prices throughout the
WECC were driven high by perpetually low supply and carbon price adders were increased.
It should be noted that the conditions given in this scenario (high gas price and carbon adder
forecasts) were applied to the entire WECC. Because every region was facing higher prices,
low-cost, carbon-free resources were selected and the market was saturated with low price
energy. Additional storage, including 250 MW of pumped hydro storage in 2031 (included in
the “Storage” column of Table 11.2), is included in this portfolio as it is an effective way to
store and then use the overabundance of renewable resources in the WECC. Though the
portfolio shows the addition of some carbon emitting resources to meet needs, it should be
noted that the emissions of this portfolio are lower than the emissions of the planning scenario,
as expected.
11.Preferred Portfolio and Near-Term Action Plan
2023 Integrated Resource Plan Page 149
Table 11.2 Preferred Portfolio—High Gas High Carbon comparison table
Preferred Portfolio—Valmy 1 & 2 (MW) High Gas High Carbon (MW)
Year
Coal
Exits Gas/H2 Wind Solar Storage Trans. DR EE GNB* Year
Coal
Exits Gas/H2 Wind Solar Storage Trans. DR EE GNB*
2024 -357 357 0 100 96 0 0 17 0 2024 -357 357 0 100 96 0 0 17 0
2025 0 0 0 200 227 0 0 18 0 2025 0 0 0 200 227 0 0 18 0
2026 -134 261 0 100 0 Jul B2H 0 19 0 2026 -134 134 0 100 0 Jul B2H 0 19 0
2027 0 0 400 375 5 0 0 20 0 2027 0 0 400 375 0 0 0 20 0
2028 0 0 400 150 5 0 0 21 0 2028 0 0 400 150 5 0 0 29 0
2029 0 0 400 0 5 GWW1 20 22 0 2029 0 170 400 100 55 GWW1 0 31 0
2030 -350 350 100 500 155 0 0 21 30 2030 -350 686 200 0 55 0 0 32 30
2031 0 0 400 400 5 GWW2 0 21 0 2031 0 0 400 600 455 GWW2 40 32 30
2032 0 0 100 100 205 0 0 20 0 2032 0 0 0 100 5 0 0 20 0
2033 0 0 0 0 105 0 20 20 0 2033 0 0 0 200 50 0 0 20 0
2034 0 0 0 0 5 0 40 19 0 2034 0 0 0 0 0 0 0 19 0
2035 0 0 0 0 5 0 40 18 0 2035 0 0 0 0 0 0 0 18 0
2036 0 0 0 0 5 0 40 17 0 2036 0 0 0 0 0 0 20 17 0
2037 0 0 0 0 105 0 0 17 0 2037 0 0 0 0 150 0 20 17 0
2038 0 -366 0 0 405 0 0 17 0 2038 0 -706 0 0 405 0 20 17 0
2039 0 0 0 0 55 0 0 15 0 2039 0 0 0 0 5 0 40 15 0
2040 0 0 0 400 5 GWW3 0 14 0 2040 0 0 0 0 5 0 40 14 0
2041 0 0 0 200 5 0 0 14 0 2041 0 0 0 0 50 0 0 14 0
2042 0 0 0 200 55 0 0 14 0 2042 0 0 0 0 0 0 0 14 0
2043 0 0 0 600 0 0 0 14 0 2043 0 0 0 600 0 GWW3 0 14 0
Sub Total -841 601 1,800 3,325 1,453 160 360 30 Sub Total -841 640 1,800 2,525 1,563 180 401 60
Resources 6,888 Resources 6,328
NPV Cost $9,746M NPV Cost $12,520M
*Geothermal Nuclear Biomass
11.Preferred Portfolio and Near-Term Action Plan
Page 150 2023 Integrated Resource Plan
Low Gas Zero Carbon
Similar to the prior scenario, the Low Gas Zero Carbon scenario includes adjustment to these
variables throughout the entire WECC. In a scenario where natural gas prices are low and
carbon emission adders are not present, this scenario shows that additional natural gas
generation resources are cost effective. Emissions from this portfolio are higher than the
emissions of the planning scenario, as expected.
This portfolio carries more risk in scenarios where the associated forecasts are higher.
11.Preferred Portfolio and Near-Term Action Plan
2023 Integrated Resource Plan Page 151
Table 11.3 Preferred Portfolio—Low Gas Zero Carbon comparison table
Preferred Portfolio—Valmy 1 & 2 (MW) Low Gas Zero Carbon (MW)
Year
Coal
Exits Gas/H2 Wind Solar Storage Trans. DR EE GNB* Year
Coal
Exits Gas/H2 Wind Solar Storage Trans. DR EE GNB*
2024 -357 357 0 100 96 0 0 17 0 2024 -357 357 0 100 96 0 0 17 0
2025 0 0 0 200 227 0 0 18 0 2025 0 0 0 200 227 0 0 18 0
2026 -134 261 0 100 0 Jul B2H 0 19 0 2026 -134 261 0 0 0 Jul B2H 0 19 0
2027 0 0 400 375 5 0 0 20 0 2027 0 0 400 375 5 0 0 20 0
2028 0 0 400 150 5 0 0 21 0 2028 0 0 200 150 5 0 0 21 0
2029 0 0 400 0 5 GWW1 20 22 0 2029 0 0 400 300 5 GWW1 0 22 0
2030 -350 350 100 500 155 0 0 21 30 2030 -350 350 400 200 155 0 0 21 0
2031 0 0 400 400 5 GWW2 0 21 0 2031 0 0 400 400 155 GWW2 0 21 0
2032 0 0 100 100 205 0 0 20 0 2032 0 0 0 200 155 0 0 20 0
2033 0 0 0 0 105 0 20 20 0 2033 0 0 0 0 55 0 0 20 0
2034 0 0 0 0 5 0 40 19 0 2034 0 0 0 0 5 0 20 19 0
2035 0 0 0 0 5 0 40 18 0 2035 0 0 0 0 5 0 40 18 0
2036 0 0 0 0 5 0 40 17 0 2036 0 0 0 0 5 0 40 17 0
2037 0 0 0 0 105 0 0 17 0 2037 0 340 0 0 5 0 0 17 0
2038 0 -366 0 0 405 0 0 17 0 2038 0 -366 0 0 105 0 0 17 0
2039 0 0 0 0 55 0 0 15 0 2039 0 0 0 0 55 0 0 15 0
2040 0 0 0 400 5 GWW3 0 14 0 2040 0 0 0 0 5 0 40 14 0
2041 0 0 0 200 5 0 0 14 0 2041 0 0 0 500 0 GWW3 0 14 0
2042 0 0 0 200 55 0 0 14 0 2042 0 0 0 400 5 0 0 14 0
2043 0 0 0 600 0 0 0 14 0 2043 0 0 0 600 5 0 0 14 0
Sub Total -841 601 1,800 3,325 1,453 160 360 30 Sub Total -841 941 1,800 3,425 1,053 140 360 0
Resources 6,888 Resources 6,878
NPV Cost $9,746M NPV Cost $8,594M
*Geothermal Nuclear Biomass
11.Preferred Portfolio and Near-Term Action Plan
Page 152 2023 Integrated Resource Plan
Constrained Storage
In the Constrained Storage run, in response to elevated storage costs throughout the WECC,
natural gas generation and an additional 90 MW of geothermal replaced approximately
300 MW of storage. Also, while the total amount of incremental DR was the same in both
portfolios, DR programs were identified early in the plan to assist the reduced amount of
storage to meet system needs.
While Idaho Power expects storage technologies to continue to develop and for storage to
become more affordable in the future, it is helpful to examine this assumption and understand
which resources could be used in the place of cost-effective storage.
11.Preferred Portfolio and Near-Term Action Plan
2023 Integrated Resource Plan Page 153
Table 11.4 Preferred Portfolio—Constrained Storage comparison table
Preferred Portfolio—Valmy 1 & 2 (MW) Constrained Storage (MW)
Year
Coal
Exits Gas/H2 Wind Solar Storage Trans. DR EE GNB* Year
Coal
Exits Gas/H2 Wind Solar Storage Trans. DR EE GNB*
2024 -357 357 0 100 96 0 0 17 0 2024 -357 357 0 100 96 0 0 17 0
2025 0 0 0 200 227 0 0 18 0 2025 0 0 0 200 227 0 0 18 0
2026 -134 261 0 100 0 Jul B2H 0 19 0 2026 -134 134 0 0 0 Jul B2H 0 19 0
2027 0 0 400 375 5 0 0 20 0 2027 0 0 400 475 5 0 20 20 0
2028 0 0 400 150 5 0 0 21 0 2028 0 0 400 150 5 0 40 21 0
2029 0 0 400 0 5 GWW1 20 22 0 2029 0 0 400 400 55 GWW1 40 22 0
2030 -350 350 100 500 155 0 0 21 30 2030 -350 350 200 0 205 0 0 21 0
2031 0 0 400 400 5 GWW2 0 21 0 2031 0 -134 400 500 105 GWW2 20 21 30
2032 0 0 100 100 205 0 0 20 0 2032 0 0 0 100 5 0 20 20 30
2033 0 0 0 0 105 0 20 20 0 2033 0 0 0 0 105 0 0 20 30
2034 0 0 0 0 5 0 40 19 0 2034 0 0 0 0 5 0 0 19 30
2035 0 0 0 0 5 0 40 18 0 2035 0 0 0 0 55 0 0 18 0
2036 0 0 0 0 5 0 40 17 0 2036 0 0 0 0 55 0 0 17 0
2037 0 0 0 0 105 0 0 17 0 2037 0 170 0 0 55 0 0 17 0
2038 0 -366 0 0 405 0 0 17 0 2038 0 -196 0 0 55 0 0 17 0
2039 0 0 0 0 55 0 0 15 0 2039 0 0 0 0 55 0 0 15 0
2040 0 0 0 400 5 GWW3 0 14 0 2040 0 0 0 0 55 0 0 14 0
2041 0 0 0 200 5 0 0 14 0 2041 0 0 0 0 5 0 0 14 0
2042 0 0 0 200 55 0 0 14 0 2042 0 0 0 200 5 GWW3 0 14 0
2043 0 0 0 600 0 0 0 14 0 2043 0 0 0 300 5 0 20 27 0
Sub Total -841 601 1,800 3,325 1,453 160 360 30 Sub Total -841 680 1,800 2425 1,158 160 373 120
Resources 6,888 Resources 5,876
NPV Cost $9,746M NPV Cost $10,007M
*Geothermal Nuclear Biomass
11. Preferred Portfolio and Near-Term Action Plan
Page 154 2023 Integrated Resource Plan
100% Clean by 2035
With increasing urgency to move quickly to clean energy resources and at the request of the
IRPAC, a 100% Clean by 2035 scenario was modeled. Model studies were set up to compare the
Preferred Portfolio to a resource selection that adhered to a WECC wide 100% clean energy
constraint by 2035.
Achieving a 100% clean portfolio by 2035 requires twice the storage as the Preferred Portfolio,
including 500 MW of pumped storage in 2035 (included in the Storage column of Table 11.5).
The pumped storage expands Idaho Power’s hydro generation base and provides flexible
energy when it is needed. The elevated energy costs in this scenario resulted in the selection
of other high-cost resources including an additional 120 MW of geothermal generation and
150 MW of biomass. These resources supply the firm generation necessary to reliably serve
system needs.
The portfolio cost for the 100% Clean by 2035 scenario does not include early decommissioning
costs associated with Idaho Power’s natural gas generation units.
11.Preferred Portfolio and Near-Term Action Plan
2023 Integrated Resource Plan Page 155
Table 11.5 Preferred Portfolio—100% Clean by 2035 comparison table
Preferred Portfolio—Valmy 1 & 2 (MW) 100% Clean by 2035 (MW)
Year
Coal
Exits Gas/H2 Wind Solar Storage Trans. DR EE GNB* Year
Coal
Exits Gas/H2 Wind Solar Storage Trans. DR EE GNB*
2024 -357 357 0 100 96 0 0 17 0 2024 -357 357 0 100 96 0 0 17 0
2025 0 0 0 200 227 0 0 18 0 2025 0 0 0 200 227 0 0 18 0
2026 -134 261 0 100 0 Jul B2H 0 19 0 2026 -134 134 0 100 105 Jul B2H 0 19 0
2027 0 0 400 375 5 0 0 20 0 2027 0 0 400 375 5 0 0 20 0
2028 0 0 400 150 5 0 0 21 0 2028 0 0 400 150 5 0 20 21 0
2029 0 0 400 0 5 GWW1 20 22 0 2029 -175 0 400 0 255 GWW1 40 22 0
2030 -350 350 100 500 155 0 0 21 30 2030 -174 0 400 200 155 0 20 21 60
2031 0 0 400 400 5 GWW2 0 21 0 2031 0 0 200 500 55 GWW2 0 21 30
2032 0 0 100 100 205 0 0 20 0 2032 0 0 0 200 205 0 0 20 60
2033 0 0 0 0 105 0 20 20 0 2033 0 0 0 100 205 0 0 20 60
2034 0 0 0 0 5 0 40 19 0 2034 0 0 0 0 205 0 40 19 30
2035 0 0 0 0 5 0 40 18 0 2035 0 -1,260 0 0 705 0 60 61 60
2036 0 0 0 0 5 0 40 17 0 2036 0 0 0 0 55 0 0 17 0
2037 0 0 0 0 105 0 0 17 0 2037 0 170 0 0 0 0 0 17 0
2038 0 -366 0 0 405 0 0 17 0 2038 0 170 0 0 0 0 0 17 0
2039 0 0 0 0 55 0 0 15 0 2039 0 0 0 0 5 0 0 15 0
2040 0 0 0 400 5 GWW3 0 14 0 2040 0 0 0 100 5 GWW3 0 14 0
2041 0 0 0 200 5 0 0 14 0 2041 0 0 0 0 5 0 0 14 0
2042 0 0 0 200 55 0 0 14 0 2042 0 0 0 100 5 0 0 56 0
2043 0 0 0 600 0 0 0 14 0 2043 0 0 0 0 305 0 0 55 0
Sub Total -841 601 1,800 3,325 1,453 160 360 30 Sub Total -841 429 1,800 2,125 2,603 180 487 300
Resources 6,888 Resources 6,993
NPV Cost $9,746M NPV Cost $11,351M
*Geothermal Nuclear Biomass
11. Preferred Portfolio and Near-Term Action Plan
Page 156 2023 Integrated Resource Plan
100% Clean by 2045
Idaho Power set a goal to provide 100% clean energy by 2045. A comparison of resources
selected in the Preferred Portfolio compared to the resource selection that adheres to emission
constraints that linearly lead to the goal is shown in the following table. The path to clean
energy may not be linear and these assumptions were made to create a comparison scenario.
The 100% Clean by 2045 scenario is strikingly similar to the Preferred Portfolio in the first
several years, which illustrates how the current trajectory is in alignment with this goal.
Early acquisition of cost-effective renewable resources is included in both portfolios.
Similar to other scenarios (e.g., 100% Clean by 2035 and High Gas High Carbon), the constraints
that make this run unique were applied to the entire WECC because the economic and
sustainability drivers that move Idaho Power towards this goal are likely to apply regionally.
Other utilities and states are already making changes to their energy mix and moving
this direction.
In this environment, cleaner, low-cost energy is available in the market. The optimized resource
portfolio for this scenario takes advantage of this low-cost energy availability by increasing
storage quantities earlier in the plan (compare storage builds in the years 2029 and 2030). This
adjustment is more costly under planning conditions but is optimal for a rapidly transitioning
clean future.
11.Preferred Portfolio and Near-Term Action Plan
2023 Integrated Resource Plan Page 157
Table 11.6 Preferred Portfolio—100% Clean by 2045 comparison table
Preferred Portfolio—Valmy 1 & 2 (MW) 100% Clean by 2045 (MW)
Year
Coal
Exits Gas/H2 Wind Solar Storage Trans. DR EE GNB* Year
Coal
Exits Gas/H2 Wind Solar Storage Trans. DR EE GNB*
2024 -357 357 0 100 96 0 0 17 0 2024 -357 357 0 100 96 0 0 17 0
2025 0 0 0 200 227 0 0 18 0 2025 0 0 0 200 227 0 0 18 0
2026 -134 261 0 100 0 Jul B2H 0 19 0 2026 -134 134 0 100 0 Jul B2H 0 19 0
2027 0 0 400 375 5 0 0 20 0 2027 0 0 400 375 5 0 0 20 0
2028 0 0 400 150 5 0 0 21 0 2028 0 0 400 150 5 0 20 21 0
2029 -175 0 400 0 5 GWW1 20 22 0 2029 -350 340 400 0 305 GWW1 40 22 0
2030 -174 350 100 500 155 0 0 21 30 2030 0 0 400 200 255 0 40 21 30
2031 0 0 400 400 5 GWW2 0 21 0 2031 0 0 200 100 5 GWW2 20 21 0
2032 0 0 100 100 205 0 0 20 0 2032 0 0 0 300 5 0 0 20 0
2033 0 0 0 0 105 0 20 20 0 2033 0 0 0 400 55 0 0 20 0
2034 0 0 0 0 5 0 40 19 0 2034 0 0 0 0 105 0 0 19 0
2035 0 0 0 0 5 0 40 18 0 2035 0 -134 0 0 5 0 0 18 0
2036 0 0 0 0 5 0 40 17 0 2036 0 0 0 0 5 0 40 17 0
2037 0 0 0 0 105 0 0 17 0 2037 0 170 0 0 5 0 0 17 0
2038 0 -366 0 0 405 0 0 17 0 2038 0 -187 0 0 155 0 0 17 0
2039 0 0 0 0 55 0 0 15 0 2039 0 0 0 0 50 0 0 15 0
2040 0 0 0 400 5 GWW3 0 14 0 2040 0 0 0 200 55 GWW3 0 14 0
2041 0 0 0 200 5 0 0 14 0 2041 0 0 0 100 55 0 0 14 0
2042 0 0 0 200 55 0 0 14 0 2042 0 0 0 200 50 0 0 14 0
2043 0 0 0 600 0 0 0 14 0 2043 0 0 0 300 0 0 0 14 0
Sub Total -841 601 1,800 3,325 1,453 160 360 30 Sub Total -841 680 1,800 2,725 1,443 160 360 30
Resources 6,888 Resources 6,357
NPV Cost $9,746M NPV Cost $9,808M
*Geothermal Nuclear Biomass
11. Preferred Portfolio and Near-Term Action Plan
Page 158 2023 Integrated Resource Plan
Additional Large Load
Idaho Power’s industrial load is growing rapidly. The following two tables compare the
Preferred Portfolio to a scenario where 100 MW and 200 MW of industrial load is added to the
planning load forecast, respectively.
An additional 100 MW of load is supported by 160 MW of additional storage and a 170 MW
natural gas generation unit in 2038. The larger 200 MW of additional load sees an increase of
two gas units of the same size and 60 MW of geothermal generation. As expected,
additional flexible generation resources facilitate increased base loads, especially during winter.
11.Preferred Portfolio and Near-Term Action Plan
2023 Integrated Resource Plan Page 159
Table 11.7 Preferred Portfolio—Additional Large Load 100 MW comparison table
Preferred Portfolio—Valmy 1 & 2 (MW) Additional LL 100 MW (MW)
Year
Coal
Exits Gas/H2 Wind Solar Storage Trans. DR EE GNB* Year
Coal
Exits Gas/H2 Wind Solar Storage Trans. DR EE GNB*
2024 -357 357 0 100 96 0 0 17 0 2024 -357 357 0 100 96 0 0 17 0
2025 0 0 0 200 227 0 0 18 0 2025 0 0 0 200 227 0 0 18 0
2026 -134 261 0 100 0 Jul B2H 0 19 0 2026 -134 261 0 0 5 Jul B2H 0 19 0
2027 0 0 400 375 5 0 0 20 0 2027 0 0 400 475 5 0 0 20 0
2028 0 0 400 150 5 0 0 21 0 2028 0 0 400 150 5 0 40 21 0
2029 0 0 400 0 5 GWW1 20 22 0 2029 0 0 400 0 105 GWW1 40 22 0
2030 -350 350 100 500 155 0 0 21 30 2030 -350 350 300 300 105 0 0 21 30
2031 0 0 400 400 5 GWW2 0 21 0 2031 0 0 300 0 5 GWW2 0 21 0
2032 0 0 100 100 205 0 0 20 0 2032 0 0 0 600 155 0 0 20 0
2033 0 0 0 0 105 0 20 20 0 2033 0 0 0 0 205 0 20 20 0
2034 0 0 0 0 5 0 40 19 0 2034 0 0 0 100 155 0 0 19 0
2035 0 0 0 0 5 0 40 18 0 2035 0 0 0 0 105 0 0 18 0
2036 0 0 0 0 5 0 40 17 0 2036 0 0 0 0 5 0 20 17 0
2037 0 0 0 0 105 0 0 17 0 2037 0 170 0 0 5 0 0 17 0
2038 0 -366 0 0 405 0 0 17 0 2038 0 -366 0 0 305 0 40 17 0
2039 0 0 0 0 55 0 0 15 0 2039 0 0 0 0 55 0 0 15 0
2040 0 0 0 400 5 GWW3 0 14 0 2040 0 0 0 500 5 GWW3 0 14 0
2041 0 0 0 200 5 0 0 14 0 2041 0 0 0 200 5 0 0 14 0
2042 0 0 0 200 55 0 0 14 0 2042 0 0 0 200 55 0 0 14 0
2043 0 0 0 600 0 0 0 14 0 2043 0 0 0 500 5 0 0 14 0
Sub Total -841 601 1,800 3,325 1,453 160 360 30 Sub Total -841 771 1,800 3,325 1,613 160 360 30
Resources 6,888 Resources 7,218
NPV Cost $9,746M NPV Cost $10,236M
*Geothermal Nuclear Biomass
11. Preferred Portfolio and Action Plan
Page 160 2023 Integrated Resource Plan
Table 11.8 Preferred Portfolio—Additional Large Load 200 MW comparison table
Preferred Portfolio—Valmy 1 & 2 (MW) Additional LL 200 MW (MW)
Year
Coal
Exits Gas/H2 Wind Solar Storage Trans. DR EE GNB* Year
Coal
Exits Gas/H2 Wind Solar Storage Trans. DR EE GNB*
2024 -357 357 0 100 96 0 0 17 0 2024 -357 357 0 100 96 0 0 17 0
2025 0 0 0 200 227 0 0 18 0 2025 0 0 0 200 227 0 0 18 0
2026 -134 261 0 100 0 Jul B2H 0 19 0 2026 -134 261 0 0 5 Jul B2H 20 19 0
2027 0 0 400 375 5 0 0 20 0 2027 0 0 400 475 5 0 20 20 0
2028 0 0 400 150 5 0 0 21 0 2028 0 0 400 150 105 0 20 21 0
2029 0 0 400 0 5 GWW1 20 22 0 2029 0 0 400 300 255 GWW1 40 22 0
2030 -350 350 100 500 155 0 0 21 30 2030 -350 350 300 0 205 0 0 21 30
2031 0 0 400 400 5 GWW2 0 21 0 2031 0 0 300 500 5 GWW2 0 21 30
2032 0 0 100 100 205 0 0 20 0 2032 0 0 0 200 5 0 40 20 30
2033 0 0 0 0 105 0 20 20 0 2033 0 0 0 0 105 0 20 20 0
2034 0 0 0 0 5 0 40 19 0 2034 0 0 0 0 55 0 20 19 0
2035 0 0 0 0 5 0 40 18 0 2035 0 0 0 0 50 0 0 18 0
2036 0 0 0 0 5 0 40 17 0 2036 0 0 0 0 0 0 0 17 0
2037 0 0 0 0 105 0 0 17 0 2037 0 170 0 0 5 0 0 17 0
2038 0 -366 0 0 405 0 0 17 0 2038 0 -196 0 0 155 0 0 17 0
2039 0 0 0 0 55 0 0 15 0 2039 0 0 0 0 5 0 0 15 0
2040 0 0 0 400 5 GWW3 0 14 0 2040 0 0 0 100 5 GWW3 0 14 0
2041 0 0 0 200 5 0 0 14 0 2041 0 0 0 400 5 0 0 14 0
2042 0 0 0 200 55 0 0 14 0 2042 0 0 0 100 55 0 0 14 0
2043 0 0 0 600 0 0 0 14 0 2043 0 0 0 200 100 0 0 14 0
Sub Total -841 601 1,800 3,325 1,453 160 360 30 Sub Total -841 941 1,800 2,725 1,448 180 360 90
Resources 6,888 Resources 6,703
NPV Cost $9,746M NPV Cost $10,747M
*Geothermal Nuclear Biomass

11. Preferred Portfolio and Near-Term Action Plan
2023 Integrated Resource Plan Page 161

11. Preferred Portfolio and Near-Term Action Plan
Page 162 2023 Integrated Resource Plan
New Forecasted PURPA
In response to requests from stakeholders to include a forecast of new PURPA QF development,
in preparing the 2023 IRP, Idaho Power consulted with the IRPAC to develop a scenario that
includes a forecast of future QF development. This scenario and forecast has the effect of
reducing any deficits that might otherwise be identified, and therefore decreases the
nameplate amount of capacity that would need to be acquired to meet increasing energy
demand. Idaho Power applied this forecast of new QF development after the Action Plan
window, starting in 2029, a choice made in consultation with IRPAC and with the understanding
that earlier qualifying facility additions could distort resource selection in the critical near-term
window and inaccurately reshape actions for regulatory acknowledgment. The forecast of
future development is based on historical average nameplate capacity added over the years
2012 through 2021, and assumes in the future that 23 MW of wind is added per year, 32 MW of
solar is added per year, and 2 MW of hydro—all in the form of PURPA qualifying facilities.
The portfolio build comparison is below.
Additional PURPA contracts in this scenario result in a similar quantity of renewable
resources compared to the Preferred Portfolio (4,705 MW and 5,125 MW, respectively).
Flexible resources are also required in similar quantities for both scenarios. The New Forecasted
PURPA scenario illustrates that PURPA contracts can help meet the need for renewable
generation and that the resource quantities selected in the Preferred Portfolio are in general
alignment with the resources selected in the New Forecasted PURPA scenario.
New and renewing PURPA resource rates were based on recent PURPA renewal prices.
11.Preferred Portfolio and Near-Term Action Plan
2023 Integrated Resource Plan Page 163
Table 11.9 Preferred Portfolio—New Forecasted PURPA comparison table
Preferred Portfolio—Valmy 1 & 2 (MW) New Forecasted PURPA (MW)
Year
Coal
Exits Gas/H2 Wind Solar Storage Trans. DR EE GNB* Year
Coal
Exits Gas/H2 Wind Solar Storage Trans. DR EE GNB*
2024 -357 357 0 100 96 0 0 17 0 2024 -357 357 0 100 96 0 0 17 0
2025 0 0 0 200 227 0 0 18 0 2025 0 0 0 200 227 0 0 18 0
2026 -134 261 0 100 0 Jul B2H 0 19 0 2026 -134 261 0 100 0 Jul B2H 0 19 0
2027 0 0 400 375 5 0 0 20 0 2027 0 0 400 775 5 0 0 20 0
2028 0 0 400 150 5 0 0 21 0 2028 0 0 23 182 5 0 0 21 2
2029 0 0 400 0 5 GWW1 20 22 0 2029 0 0 423 32 5 GWW1 0 22 2
2030 -350 350 100 500 155 0 0 21 30 2030 -350 350 423 232 5 0 0 21 2
2031 0 0 400 400 5 GWW2 0 21 0 2031 0 0 423 32 155 GWW2 0 21 2
2032 0 0 100 100 205 0 0 20 0 2032 0 0 223 432 5 0 0 20 2
2033 0 0 0 0 105 0 20 20 0 2033 0 0 23 32 5 0 0 20 2
2034 0 0 0 0 5 0 40 19 0 2034 0 0 23 32 55 0 0 19 2
2035 0 0 0 0 5 0 40 18 0 2035 0 0 23 32 5 0 20 18 2
2036 0 0 0 0 5 0 40 17 0 2036 0 0 23 32 5 0 40 17 2
2037 0 0 0 0 105 0 0 17 0 2037 0 0 23 32 5 0 40 17 2
2038 0 -366 0 0 405 0 0 17 0 2038 0 -706 23 32 855 0 40 17 2
2039 0 0 0 0 55 0 0 15 0 2039 0 0 23 32 5 0 20 15 2
2040 0 0 0 400 5 GWW3 0 14 0 2040 0 0 23 32 0 0 0 14 2
2041 0 0 0 200 5 0 0 14 0 2041 0 0 23 32 5 0 0 14 2
2042 0 0 0 200 55 0 0 14 0 2042 0 0 23 32 5 0 0 14 2
2043 0 0 0 600 0 0 0 14 0 2043 0 0 23 132 5 GWW3 0 14 2
Sub Total -841 601 1,800 3,325 1,453 160 360 30 Sub Total -841 261 2,168 2,537 1,453 160 360 32
Resources 6,888 Resources 6,130
NPV Cost $9,746M NPV Cost $10,720M
*Geothermal Nuclear Biomass
11. Preferred Portfolio and Near-Term Action Plan
Page 164 2023 Integrated Resource Plan
Extreme Weather
In this scenario, the company modeled consistent high demand associated with extreme
temperature events (95th percentile) and variable water supplies. These extremes are modeled
for all years into the future.
Additional renewable resources and storage were identified to meet the requirements of the
Extreme Weather scenario. The modeling adjustments impact resource selections starting in
2026 with 105 MW of additional storage. Other notable differences include an extra natural gas
unit in 2029 and another hydrogen unit in 2038, both to meet the increased demand and
compensate for low hydro years.
11.Preferred Portfolio and Near-Term Action Plan
2023 Integrated Resource Plan Page 165
Table 11.10 Preferred Portfolio – Extreme Weather comparison table
Preferred Portfolio—Valmy 1 & 2 (MW) Extreme Weather (MW)
Year
Coal
Exits Gas/H2 Wind Solar Storage Trans. DR EE GNB* Year
Coal
Exits Gas/H2 Wind Solar Storage Trans. DR EE GNB*
2024 -357 357 0 100 96 0 0 17 0 2024 -357 357 0 100 96 0 0 17 0
2025 0 0 0 200 227 0 0 18 0 2025 0 0 0 200 227 0 0 18 0
2026 -134 261 0 100 0 Jul B2H 0 19 0 2026 -134 261 0 100 105 Jul B2H 20 19 0
2027 0 0 400 375 5 0 0 20 0 2027 0 0 400 375 5 0 40 20 0
2028 0 0 400 150 5 0 0 21 0 2028 0 0 400 150 105 0 20 21 0
2029 0 0 400 0 5 GWW1 20 22 0 2029 0 170 400 0 0 GWW1 0 22 0
2030 -350 350 100 500 155 0 0 21 30 2030 -350 350 300 300 5 0 0 21 0
2031 0 0 400 400 5 GWW2 0 21 0 2031 0 0 300 0 5 GWW2 0 21 0
2032 0 0 100 100 205 0 0 20 0 2032 0 0 0 300 5 0 0 20 0
2033 0 0 0 0 105 0 20 20 0 2033 0 0 0 400 205 0 0 20 0
2034 0 0 0 0 5 0 40 19 0 2034 0 0 0 0 5 0 0 19 0
2035 0 0 0 0 5 0 40 18 0 2035 0 0 0 0 5 0 0 18 0
2036 0 0 0 0 5 0 40 17 0 2036 0 0 0 0 5 0 20 17 0
2037 0 0 0 0 105 0 0 17 0 2037 0 0 0 0 155 0 20 17 0
2038 0 -366 0 0 405 0 0 17 0 2038 0 -196 0 0 205 0 20 17 0
2039 0 0 0 0 55 0 0 15 0 2039 0 0 0 0 5 0 0 15 0
2040 0 0 0 400 5 GWW3 0 14 0 2040 0 0 0 0 55 0 0 14 0
2041 0 0 0 200 5 0 0 14 0 2041 0 0 0 0 5 0 40 14 0
2042 0 0 0 200 55 0 0 14 0 2042 0 0 0 200 55 GWW3 0 14 0
2043 0 0 0 600 0 0 0 14 0 2043 0 0 0 500 105 0 0 14 0
Sub Total -841 601 1,800 3,325 1,453 160 360 30 Sub Total -841 941 1,800 2,625 1,358 180 360 0
Resources 6,888 Resources 6,423
NPV Cost $9,746M NPV Cost $10,211M
*Geothermal Nuclear Biomass
11. Preferred Portfolio and Near-Term Action Plan
Page 166 2023 Integrated Resource Plan
Rapid Electrification
A rapid path towards electrification—modeled with an aggressive electric vehicle forecast and
an accelerated building heating and cooling transition—increases demand on the system
year-round and throughout each day, but the increase in load during the winter has the most
significant impacts on the electrical grid. The rapid electrification shift would require additional
baseload generation units to reliably serve demand.
Using ASHPs for building electrification also requires an increased quantity of energy storage on
the system, while GSHPs—at their significantly higher cost—help to mitigate that need.
The differences between the Preferred Portfolio and the Rapid Electrification scenarios can be
seen in tables 11.11 and 11.12.
The comparison of the Preferred Portfolio and the Rapid Electrification scenario illustrates that
course corrections, including the acquisition of additional flexible generation resources starting
as early as 2029, can be made along the way to adjust to a steep ramp towards electrification.
11.Preferred Portfolio and Near-Term Action Plan
2023 Integrated Resource Plan Page 167
Table 11.11 Preferred Portfolio—Rapid Electrification (ASHP) comparison table
Preferred Portfolio—Valmy 1 & 2 (MW) Rapid Electrification (ASHP) (MW)
Year
Coal
Exits Gas/H2 Wind Solar Storage Trans. DR EE GNB* Year
Coal
Exits Gas/H2 Wind Solar Storage Trans. DR EE GNB*
2024 -357 357 0 100 96 0 0 17 0 2024 -357 357 0 100 96 0 0 17 0
2025 0 0 0 200 227 0 0 18 0 2025 0 0 0 200 227 0 0 18 0
2026 -134 261 0 100 0 Jul B2H 0 19 0 2026 -134 261 0 100 5 Jul B2H 0 19 0
2027 0 0 400 375 5 0 0 20 0 2027 0 0 400 375 55 0 20 20 0
2028 0 0 400 150 5 0 0 21 0 2028 0 0 400 150 205 0 40 21 0
2029 0 0 400 0 5 GWW1 20 22 0 2029 0 300 400 300 5 GWW1 0 22 0
2030 -350 350 100 500 155 0 0 21 30 2030 -350 350 300 0 5 0 0 21 30
2031 0 0 400 400 5 GWW2 0 21 0 2031 0 170 300 400 5 GWW2 0 21 0
2032 0 0 100 100 205 0 0 20 0 2032 0 0 0 300 355 0 0 20 0
2033 0 0 0 0 105 0 20 20 0 2033 0 0 0 0 705 0 0 20 0
2034 0 0 0 0 5 0 40 19 0 2034 0 340 0 0 5 0 20 19 0
2035 0 0 0 0 5 0 40 18 0 2035 0 0 0 0 55 0 20 18 0
2036 0 0 0 0 5 0 40 17 0 2036 0 0 0 0 5 0 0 17 0
2037 0 0 0 0 105 0 0 17 0 2037 0 340 0 0 5 0 0 17 0
2038 0 -366 0 0 405 0 0 17 0 2038 0 -196 0 0 155 0 20 17 30
2039 0 0 0 0 55 0 0 15 0 2039 0 0 0 0 155 0 20 15 0
2040 0 0 0 400 5 GWW3 0 14 0 2040 0 0 0 400 200 GWW3 0 14 0
2041 0 0 0 200 5 0 0 14 0 2041 0 0 0 400 0 0 0 14 0
2042 0 0 0 200 55 0 0 14 0 2042 0 0 0 300 5 0 0 14 0
2043 0 0 0 600 0 0 0 14 0 2043 0 0 0 400 155 0 20 14 0
Sub Total -841 601 1,800 3,325 1,453 160 360 30 Sub Total -841 1,921 1,800 3,425 2,403 160 360 60
Resources 6,888 Resources 9,288
NPV Cost $9,746M NPV Cost $12,271M
*Geothermal Nuclear Biomass
11. Preferred Portfolio and Near-Term Action Plan
Page 168 2023 Integrated Resource Plan
Table 11.12 Preferred Portfolio—Rapid Electrification (GSHP) comparison table
Preferred Portfolio—Valmy 1 & 2 (MW) Rapid Electrification (GSHP) (MW)
Year
Coal
Exits Gas/H2 Wind Solar Storage Trans. DR EE GNB* Year
Coal
Exits Gas/H2 Wind Solar Storage Trans. DR EE GNB*
2024 -357 357 0 100 96 0 0 17 0 2024 -357 357 0 100 96 0 0 17 0
2025 0 0 0 200 227 0 0 18 0 2025 0 0 0 200 227 0 0 18 0
2026 -134 261 0 100 0 Jul B2H 0 19 0 2026 -134 261 0 0 5 Jul B2H 0 19 0
2027 0 0 400 375 5 0 0 20 0 2027 0 0 400 475 5 0 0 20 0
2028 0 0 400 150 5 0 0 21 0 2028 0 0 400 150 5 0 0 21 0
2029 0 0 400 0 5 GWW1 20 22 0 2029 0 300 400 0 5 GWW1 0 22 0
2030 -350 350 100 500 155 0 0 21 30 2030 -350 350 200 400 5 0 0 21 0
2031 0 0 400 400 5 GWW2 0 21 0 2031 0 0 400 0 5 GWW2 0 21 0
2032 0 0 100 100 205 0 0 20 0 2032 0 170 0 300 55 0 20 20 0
2033 0 0 0 0 105 0 20 20 0 2033 0 0 0 300 255 0 20 20 0
2034 0 0 0 0 5 0 40 19 0 2034 0 0 0 0 5 0 20 19 0
2035 0 0 0 0 5 0 40 18 0 2035 0 0 0 0 5 0 0 18 0
2036 0 0 0 0 5 0 40 17 0 2036 0 170 0 0 5 0 0 17 0
2037 0 0 0 0 105 0 0 17 0 2037 0 340 0 0 5 0 20 17 0
2038 0 -366 0 0 405 0 0 17 0 2038 0 -196 0 0 5 0 20 17 0
2039 0 0 0 0 55 0 0 15 0 2039 0 0 0 0 5 0 40 15 0
2040 0 0 0 400 5 GWW3 0 14 0 2040 0 170 0 0 5 0 0 14 0
2041 0 0 0 200 5 0 0 14 0 2041 0 0 0 0 5 0 20 14 0
2042 0 0 0 200 55 0 0 14 0 2042 0 0 0 100 5 GWW3 20 14 0
2043 0 0 0 600 0 0 0 14 0 2043 0 0 0 100 55 0 0 14 0
Sub Total -841 601 1,800 3,325 1,453 160 360 30 Sub Total -841 1,921 1,800 2,125 763 180 360 0
Resources 6,888 Resources 6,308
NPV Cost $9,746M NPV Cost $11,175M
*Geothermal Nuclear Biomass
11. Preferred Portfolio and Near-Term Action Plan
2023 Integrated Resource Plan Page 169
11.Preferred Portfolio and Near-Term Action Plan
Page 170 2023 Integrated Resource Plan
Load Flattening
The purpose of the Load Flattening scenario was to determine how shifting load from peak
demand times to times where demand was lowest would impact resource need and portfolio
cost. This approach reduces peak load and increases system load factor by flattening the
load curve.
As solar resources increase throughout the WECC in the plan, the cost of energy during summer
daytime hours decrease. For the Load Flattening sensitivity, this had the undesired impact of
shifting some load from high renewable output time periods to hours when flexible resources
were required to meet demand. The shift required two additional flexible generation units
(one in 2037 and one in 2038).
The Load Flattening scenario illustrates that to be effective at reducing costs, such a shift would
need to adapt seasonally and annually to changing system needs and would need to be cost
competitive with resources like battery storage that can serve a similar function.
11.Preferred Portfolio and Action Plan
2023 Integrated Resource Plan Page 171
Table 11.13 Preferred Portfolio—Load Flattening comparison table
Preferred Portfolio—Valmy 1 & 2 (MW) Load Flattening (MW)
Year
Coal
Exits Gas/H2 Wind Solar Storage Trans. DR EE GNB* Year
Coal
Exits Gas/H2 Wind Solar Storage Trans. DR EE GNB*
2024 -357 357 0 100 96 0 0 17 0 2024 -357 357 0 100 96 0 0 17 0
2025 0 0 0 200 227 0 0 18 0 2025 0 0 0 200 227 0 0 18 0
2026 -134 261 0 100 0 Jul B2H 0 19 0 2026 -134 261 0 100 5 Jul B2H 20 19 0
2027 0 0 400 375 5 0 0 20 0 2027 0 0 400 375 5 0 20 20 0
2028 0 0 400 150 5 0 0 21 0 2028 0 0 400 150 105 0 40 21 0
2029 0 0 400 0 5 GWW1 20 22 0 2029 0 0 400 0 255 GWW1 0 22 0
2030 -350 350 100 500 155 0 0 21 30 2030 -350 350 300 300 205 0 0 21 30
2031 0 0 400 400 5 GWW2 0 21 0 2031 0 0 300 600 205 GWW2 0 21 30
2032 0 0 100 100 205 0 0 20 0 2032 0 0 0 100 55 0 20 20 0
2033 0 0 0 0 105 0 20 20 0 2033 0 0 0 0 5 0 20 20 0
2034 0 0 0 0 5 0 40 19 0 2034 0 0 0 0 55 0 0 19 0
2035 0 0 0 0 5 0 40 18 0 2035 0 0 0 0 5 0 20 18 0
2036 0 0 0 0 5 0 40 17 0 2036 0 0 0 0 5 0 20 17 0
2037 0 0 0 0 105 0 0 17 0 2037 0 170 0 0 5 0 0 17 0
2038 0 -366 0 0 405 0 0 17 0 2038 0 -196 0 0 155 0 0 17 0
2039 0 0 0 0 55 0 0 15 0 2039 0 0 0 0 5 0 0 15 0
2040 0 0 0 400 5 GWW3 0 14 0 2040 0 0 0 400 5 GWW3 0 14 0
2041 0 0 0 200 5 0 0 14 0 2041 0 0 0 200 5 0 0 14 0
2042 0 0 0 200 55 0 0 14 0 2042 0 0 0 500 5 0 0 14 0
2043 0 0 0 600 0 0 0 14 0 2043 0 0 0 300 5 0 20 27 0
Sub Total -841 601 1,800 3,325 1,453 160 360 30 Sub Total -841 941 1,800 3,325 1,413 180 373 60
Resources 6,888 Resources 7,252
NPV Cost $9,746M NPV Cost $10,663M
*Geothermal Nuclear Biomass
11. Preferred Portfolio and Near-Term Action Plan
Page 172 2023 Integrated Resource Plan
Near-Term Action Plan (2024–2028)
The Near-Term Action Plan for the 2023 IRP reflects near-term actionable items of the
Preferred Portfolio. The Near-Term Action Plan identifies key milestones to successfully position
Idaho Power to provide reliable, economic, and environmentally sound service to customers
into the future. The current regional electric market, regulatory environment, pace of
technological change and Idaho Power’s goal of 100% clean energy by 2045 make the 2023
Near-Term Action Plan especially relevant.
The Near-Term Action Plan associated with the Preferred Portfolio is driven by its core resource
actions through 2028. These core resource actions include some actions to which the company
had committed prior to the development of the 2023 IRP and some that were identified as a
result of the 2023 IRP analysis:
Actions Committed to Prior to the 2023 IRP–Not for Regulatory
Acknowledgment
•100 MW of solar and 96 MW of four-hour storage added in 2024 (resources selected
through Requests for Proposals [RFP])
•Conversion of Bridger units 1 and 2 from coal to natural gas by summer 2024
(conversions scheduled to occur by summer of 2024)
•95 MW of additional cost-effective EE between 2024 and 2028 (added EE identified in
Idaho Power’s 2022 energy efficiency potential study)
•200 MW of solar added in 2025 (executed contract for clean energy customer resource)
•227 MW of four-hour storage added in 2025 (resources selected from the 2024 RFP)
2023 IRP Decisions for Acknowledgment
•B2H online by summer 2026
•Continue exploring Idaho Power’s potential participation in the SWIP-N project
•Install cost-effective distribution-connected storage from 2025 through 2028
•Convert Valmy units 1 and 2 from coal to natural gas by summer 2026
•If economic, acquire up to 1,425 MW of combined wind and solar, or other economic
resources, in 2026 through 2028 (inclusive of 625 MW of forecast CEYW resources)
•Explore a 5 MW long-duration storage pilot project
•Include 14 MW of capacity associated with the WRAP
11. Preferred Portfolio and Near-Term Action Plan
2023 Integrated Resource Plan Page 173
•Midpoint–Hemingway #2 500-kV, Midpoint–Cedar Hill 500-kV, and Mayfield 500-kV
substation (Gateway West Phase 1) online by end-of-year 2028
The Near-Term Action Plan is the result of the above resource actions and portfolio attributes,
which are discussed in the following sections. Further discussion of the core resource actions
and attributes of the Preferred Portfolio is included in this chapter. A chronological listing of the
near-term actions follows in Table 11.14.
Table 11.14 Near-Term Action Plan (2024–2028)
Year Action
2023–2024 Continue exploring potential participation in the SWIP-N project
2024 Add 100 MW of solar and 96 MW of four-hour storage
Summer 2024 Convert Bridger units 1 and 2 from coal to natural gas
2024–2028 Add 95 MW of cost-effective EE between 2024 and 2028
2024–2028 Explore a 5 MW long-duration storage pilot project
2025 Add 200 MW of solar
2025 Add 227 MW of four-hour storage
2025–2028 Install cost effective distribution-connected storage
Summer 2026 Bring B2H online
Summer 2026 Convert Valmy units 1 and 2 from coal to natural gas
2026–2028 If economic, acquire up to 1,425 MW of combined wind and solar, or other economic resources
2027 Include 14 MW of capacity associated with the Western Resource Adequacy Program
2028 Bring the first phase of Gateway West online (Midpoint–Hemingway #2 500-kV line,
Midpoint–Cedar Hill 500-kV line, and Mayfield substation)
Resource Procurement
Idaho Power’s capacity shortfall identified for 2026 through 2028 will require incremental
generating capacity. Idaho Power issued an all-source 2026 RFP in spring 2023. This RFP is for
resources to come online by summer 2026 or summer 2027. The all-source 2026 RFP is
ongoing. An additional RFP may be necessary to acquire resources for summer of 2028.
For more information on Idaho Power RFPs visit idahopower.com/about-us/doing-business-
with-us/request-for-resources/.
Annual Capacity Positions Replace Traditional Load and Resource Balance
To better align with and represent the probabilistic reliability analyses used in the 2023 IRP,
the company provides annual capacity positions in place of the deterministic load and resource
balance used in previous IRP cycles. The annual capacity position is a better indication of
resource reliability.
11. Preferred Portfolio and Near-Term Action Plan
Page 174 2023 Integrated Resource Plan
The annual capacity position used in the 2023 IRP (Table 11.15) incorporates the most
up-to-date resource and load inputs. The resulting capacity deficiency (approximately 22 MW
in 2026, 44 MW in 2027, and 182 MW in 2028) clearly demonstrates capacity needs.
Table 11.15 Pre and post Preferred Portfolio annual capacity positions
Annual Capacity Position (MW)
Year Existing & Contracted Resource Only Add Preferred Portfolio Resources
2024 11 Length 11 Length
2025 3 Length 3 Length
2026 (22) Shortfall 224 Length
2027 (44) Shortfall 284 Length
2028 (182) Shortfall 211 Length
2029 (324) Shortfall 126 Length
2030 (693) Shortfall 134 Length
2031 (767) Shortfall 131 Length
2032 (796) Shortfall 157 Length
2033 (869) Shortfall 137 Length
2034 (891) Shortfall 126 Length
2035 (913) Shortfall 117 Length
2036 (938) Shortfall 108 Length
2037 (1006) Shortfall 111 Length
2038 (1317) Shortfall 45 Length
2039 (1347) Shortfall 54 Length
2040 (1377) Shortfall 62 Length
2041 (1415) Shortfall 56 Length
2042 (1456) Shortfall 49 Length
2043 (1568) Shortfall 57 Length

The first month of deficiency was determined to be the first month that exceeded a
0.0083 event-days per year LOLE (or 0.1 divided by 12) on the first year of capacity deficiency
(2026). For this IRP, the first month over that threshold was July 2026, as shown in Figure 11.1.
11. Preferred Portfolio and Near-Term Action Plan
2023 Integrated Resource Plan Page 175
Figure 11.1 First month of capacity shortfall
An in-depth discussion of the reliability LOLE calculation process can be found in the Loss of
Load Expectation section of Appendix C—Technical Report.
2025 IRP Filing Schedule
The 2025 IRP will be filed in June 2025. Including the extended timelines for the 2021 IRP and
the 2023 IRP, both were completed approximately 21 months from the previous IRP filing.
The same timeframe for the 2025 IRP will result in an on-time filing. The following associated
tasks will be completed between the 2023 IRP filing and the 2025 IRP filing:
•Model inputs will be collected prior to IRPAC meetings in the first 10 months.
•Between 8 and 12 IRPAC meetings will be conducted in 8–12 months.
•The analysis will begin coincident with the last three to four IRPAC meetings.
•The report will be drafted concurrent with the IRPAC meetings and analysis.
•A public review will be scheduled prior to the IRP filing.
•The IRP will be filed in June 2025.
0.00
0.01
0.02
0.03
0.04
0.05
0.06
0.07
0.08
Monthly LOLE Shortfall Threshold
11. Preferred Portfolio and Near-Term Action Plan
Page 176 2023 Integrated Resource Plan
Conclusion
The 2023 IRP provides guidance for Idaho Power as its
portfolio of resources evolves over the coming years.
The B2H transmission line continues in the 2023 IRP
analysis to be a top performing resource alternative,
providing Idaho Power access to affordable and clean
energy in the Pacific Northwest wholesale electric
market. From a regional perspective, the B2H
transmission line, and high-voltage transmission in
general, is critical to achieving cost-effective clean
energy objectives, including Idaho Power’s goal of 100%
clean energy by 2045.
Idaho Power prepares an IRP every two years. The next
plan will be filed in 2025. The energy industry is
expected to continue undergoing substantial
transformation over the coming years, and new
challenges and questions will be encountered in the
2025 IRP. Idaho Power will continue to monitor trends in
the energy industry and adjust as necessary.
Idaho Power linemen install upgrades.
A P P E N D I X A : A P P E N D I X A : S A L E S & L O A D F O R E C A S TS A L E S & L O A D F O R E C A S T
IRP
INTEGRATED RESOURCE PLAN
September 2023
Printed on recycled paper
SAFE HARBOR STATEMENT
This document may contain forward-looking statements,
and it is important to note that the future results could
differ materially from those discussed. A full discussion
of the factors that could cause future results to differ
materially can be found in Idaho Power’s filings with the
Securities and Exchange Commission.
Table of Contents
2023 Integrated Resource Plan—Appendix A Page i
TABLE OF CONTENTS
Table of Contents .............................................................................................................................. i
List of Tables .................................................................................................................................... ii
List of Figures ................................................................................................................................... ii
List of Appendices ........................................................................................................................... iv
Introduction .................................................................................................................................... 1
2023 IRP Sales and Load Forecast ................................................................................................... 3
Average Load............................................................................................................................. 3
Peak-Hour Demands ................................................................................................................. 4
Overview of the Forecast and Scenarios ........................................................................................ 6
Forecast Probabilities................................................................................................................ 6
Load Forecasts Based on Weather Variability .................................................................... 6
Load Forecasts Based on Economic Uncertainty ................................................................ 8
Company System Load .................................................................................................................. 11
Additional Scenarios Developed ............................................................................................. 12
Load Flattening ................................................................................................................. 12
Electrification Scenarios .................................................................................................... 13
High Growth Scenarios ..................................................................................................... 14
Company System Peak .................................................................................................................. 15
Seasonal Peak Forecast ........................................................................................................... 15
Peak Model Design ................................................................................................................. 18
Class Sales Forecast ....................................................................................................................... 20
Residential ............................................................................................................................... 20
Commercial ............................................................................................................................. 23
Industrial ................................................................................................................................. 27
Irrigation.................................................................................................................................. 31
Additional Firm Load ............................................................................................................... 33
Micron Technology ........................................................................................................... 34
Simplot Fertilizer ............................................................................................................... 34
Idaho National Laboratory ................................................................................................ 34
Table of Contents
Page ii 2023 Integrated Resource Plan—Appendix A
Brisbie, LLC (Meta Platforms, Inc.) .................................................................................... 35
Additional Considerations ............................................................................................................. 36
Energy Efficiency ..................................................................................................................... 36
On-Site Generation ................................................................................................................. 37
Electric Vehicles ...................................................................................................................... 37
Demand Response .................................................................................................................. 38
Fuel Prices ............................................................................................................................... 38
Other Considerations .............................................................................................................. 41
Hourly Load Forecast .............................................................................................................. 41
Hourly Load Forecast Methodology ................................................................................. 41
Technical Specifications of Hourly Load Forecasting ........................................................ 41
Hourly System Load Forecast Design ................................................................................ 42
Contract Off-System Load ............................................................................................................. 44

LIST OF TABLES
Table 1. Average load and peak-demand forecast scenarios ..................................................... 7
Table 2. System load growth (aMW) .......................................................................................... 7
Table 3. Forecast probabilities ................................................................................................... 9
Table 4. System load growth (aMW) ........................................................................................ 10
Table 5. System summer peak load growth (MW) ................................................................... 15
Table 6. System winter peak load growth (MW) ...................................................................... 17
Table 7. Residential load growth (aMW) .................................................................................. 20
Table 8. Commercial load growth (aMW) ................................................................................ 24
Table 9. Industrial load growth (aMW) .................................................................................... 28
Table 10. Irrigation load growth (aMW) ..................................................................................... 31
Table 11. Additional firm load growth (aMW) ........................................................................... 33
Table 12. Residential fuel-price escalation (2024–2043) (average annual percent
change) ........................................................................................................................ 39
LIST OF FIGURES
Figure 1. Forecast system load (aMW) ........................................................................................ 8
Table of Contents
2023 Integrated Resource Plan—Appendix A Page iii
Figure 2. Forecast system load (aMW) ...................................................................................... 10
Figure 3. Composition of system company electricity sales (thousands of MWh) ................... 12
Figure 4. Forecast system summer peak (MW) ......................................................................... 16
Figure 5. Forecast system winter peak (MW) ............................................................................ 17
Figure 6. Idaho Power monthly peaks (MW) ............................................................................. 18
Figure 7. Forecast residential load (aMW) ................................................................................ 20
Figure 8. Forecast residential UPC (weather-adjusted kWh) .................................................... 21
Figure 9. Residential customer growth rates (12-month change)............................................. 22
Figure 10. Residential sales forecast methodology framework .................................................. 23
Figure 11. Forecast commercial load (aMW) ............................................................................... 24
Figure 12. Commercial building share—energy use .................................................................... 25
Figure 13. Forecast commercial UPC (weather-adjusted kWh) .................................................. 26
Figure 14. Commercial categories UPC, 2022 relative to 2016 ................................................... 27
Figure 15. Forecast industrial load (aMW) .................................................................................. 29
Figure 16. Industrial electricity consumption by industry group (based on 2022 sales) ............ 30
Figure 17. Commercial and industrial sales forecast methodology ............................................ 31
Figure 18. Forecast irrigation load (aMW) ................................................................................... 32
Figure 19. Forecast additional firm load (aMW) .......................................................................... 34
Figure 20. Forecast residential electricity prices (cents per kWh) .............................................. 39
Figure 21. Forecast residential natural gas prices (dollars per therm) ........................................ 40
Figure 22. Class contribution to system peak .............................................................................. 43

Table of Contents
Page iv 2023 Integrated Resource Plan—Appendix A
LIST OF APPENDICES
Appendix A1. Historical and Projected Sales and Load .............................................................. 45
Company System Load (excluding Astaris) ............................................................................. 45
Historical Company System Sales and Load, 1982–2022 (weather adjusted) ................. 45
Company System Load ............................................................................................................ 46
Projected Company System Sales and Load, 2024–2043 ................................................. 46
Residential Load ...................................................................................................................... 47
Historical Residential Sales and Load, 1982–2022 (weather adjusted)............................ 47
Projected Residential Sales and Load, 2024–2043 ........................................................... 48
Commercial Load .................................................................................................................... 49
Historical Commercial Sales and Load, 1982–2022 (weather adjusted) .......................... 49
Projected Commercial Sales and Load, 2024–2043.......................................................... 50
Irrigation Load ......................................................................................................................... 51
Historical Irrigation Sales and Load, 1982–2022 (weather adjusted) .............................. 51
Projected Irrigation Sales and Load, 2024–2043 .............................................................. 52
Industrial Load ........................................................................................................................ 53
Historical Industrial Sales and Load, 1982–2022 (not weather adjusted) ........................ 53
Projected Industrial Sales and Load, 2024–2043 .............................................................. 54
Additional Firm Sales and Load ............................................................................................... 55
Historical Additional Firm Sales and Load, 1982–2022 .................................................... 55
Projected Additional Firm Sales and Load, 2024–2043 .................................................... 56

Introduction
2023 Integrated Resource Plan—Appendix A Page 1
INTRODUCTION
Idaho Power has prepared Appendix A—Sales and Load Forecast as part of the 2023 Integrated
Resource Plan (IRP). Appendix A includes details on the energy sales and load forecast of future
demand for electricity within the company’s service area. The above-mentioned forecast covers
a 20-year period from 2024 through 2043.
This appendix describes the development of the anticipated monthly sales forecast.
The forecast is Idaho Power’s estimate of the most probable outcome for sales growth during
the 20-year planning period. In addition, to account for inherent uncertainty in the forecast,
additional forecast cases are prepared to test ranges of variability to the anticipated case.
Economic and demographic (non-weather-related) assumptions are modified to create
scenarios for a low and a high economic-related case. By holding weather variability constant,
these forecasts test the assumptions of the anticipated case economic/demographic variables
by applying historically based parameters of growth on both the low and high side of the
economic determinants of the anticipated case forecast.
Economic data in the forecast models is primarily sourced from Moody’s Analytics and Woods
& Poole Economics. The national, state, Metropolitan Statistical Area (MSA), and county
economic and demographic projections are tailored to Idaho Power’s service area using an
in-house historic economic database. Specific demographic projections are also developed for
the service area from national and local census data. Additional data sources used to
substantiate said economic data include, but are not limited to, the Idaho Department of Labor,
Construction Monitor, and Federal Reserve economic databases.
As economic growth assumptions influence several classes of service growth rates, it is
important to review several key components. The number of households in Idaho is projected
to grow at an annual rate of 1.6% during the forecast period. The growth in the number of
households within individual counties in Idaho Power’s service area is projected to grow faster
than the remainder of the state over the planning period. Similarly, the number of households
in the Boise–Nampa MSA is also projected to grow faster than the state of Idaho, at an annual
rate of 2.2% during the forecast period. The Boise MSA (or the Treasure Valley) is an area
that encompasses Ada, Boise, Canyon, Gem, and Owyhee counties in southwestern Idaho.
In addition to the number of households, incomes, employment, economic output, and real
retail electricity prices are used to develop load projections.
Scenarios of weather-related influence on potential ranges of the anticipated forecast are
tested utilizing a probabilistic distribution of normal weather (temperature and precipitation)
applied to the weather assumptions in the anticipated case. This provides a comparative range
of outcome that isolates long-term sustained weather influences on the forecast.
Introduction
Page 2 2023 Integrated Resource Plan—Appendix A
The anticipated forecast scenario shows Idaho Power’s system load increasing to 2,999 average
megawatts (aMW) by 2043 from 2,024 aMW in 2024, representing an average yearly growth
rate of 2.1% over the 20-year planning period (2024–2043). A similar annual average growth
rate in system load is reflected in various weather-related scenarios. From an annual
peak-hour demand perspective, the anticipated case of the peak-demand forecast will grow
to 5,337 megawatts (MW) in 2043 from the all-time system peak of 3,751 MW that occurred
on Wednesday, June 30, 2021, at 7 p.m. Idaho Power’s system peak increases at an average
growth rate of 1.8% per year over the 20-year planning period (2024–2043) under this case.
Over this same term, the number of Idaho Power active retail customers is expected to
increase from the December 2022 level of 616,857 customers to over 855,000 customers by
year-end 2043.
Beyond the weather, climate, economic and demographic assumptions used to drive the
anticipated case forecast scenario, several additional assumptions were incorporated into the
forecasts of the residential, commercial, industrial, and irrigation sectors.
Some examples include conservation influences on the load forecast, including Idaho Power
energy efficiency demand side management (DSM) programs, statutory programs, and non-
programmatic trends in conservation. These influences are included in the load forecasts. Idaho
Power DSM programs are described in detail in Idaho Power’s Demand-Side Management 2022
Annual Report, which is incorporated into this IRP document as Appendix B. Idaho Power also
recognizes the impact of on-site generation and electric vehicles in its service territory and does
include the impact of their energy reduction or addition in the long-term sales and load
forecast. Further discussion of these assumptions is presented in each respective section.
Outside of weather, potential primary risks during the 20-year forecast horizon include major
shifts in the electric utility industry (e.g., state and federal regulations and varying electricity
prices) which could influence the load forecast. Additionally, the price and volatility of
substitute fuels, such as natural gas, may also impact future demand for electricity. The
uncertainty associated with such changes is reflected in the economic high and low-load growth
scenarios described previously. The alternative sales and load scenarios in Appendix A—Sales
and Load Forecast were prepared under the assumption that Idaho Power’s geographic service
area remains unchanged during the planning period.
Data describing the historical and projected figures for the sales and load forecast are
presented in Appendix A1 of this report.
2023 IRP Sales and Load Forecast
2023 Integrated Resource Plan—Appendix A Page 3
2023 IRP SALES AND LOAD FORECAST
Average Load
The economic and demographic variables driving the 2023 forecast have the impact of
increasing current annual sales levels throughout the planning period. The extended business
cycle recovery process after the Great Recession in 2008 for the national and service area
economy muted load growth post-recession through 2011. However, in 2012, the extended
recovery process was evident, and on-balance stronger growth was exhibited in most economic
drivers relative to post Great Recession history. From that point, the global pandemic recession
in 2020 had profound effects across the national and global economy. For the company,
residential sales increased approximately 5% in 2020 and into 2021. This growth was
attributable to both work-from-home edicts as well as continued strong in-migration trends.
In the second half of 2022 and into 2023, migration trends have slowed relative to previous
years. However, net migration growth into the service area remains positive and more
consistent with long-term trends. Negative energy use was initially exhibited by the commercial
and industrial classes but has since stabilized and, overall, rebounded quickly. Irrigation sales
were mostly unaffected by the pandemic and continue to follow the expected growth trend.
Overall, it is assumed economic conditions will return to long-term fundamentals during the
2023 IRP forecast term. Additional significant factors and considerations that influenced the
outcome of the 2023 IRP load forecast include the following:
• Weather plays a primary role in impacting the load forecast on a monthly and seasonal
basis. In the anticipated load forecast of energy and peak-hour demand, Idaho Power
assumes average temperatures and precipitation over a 30-year meteorological
measurement period or defined as normal climatology. Probabilistic variations of
weather are also analyzed.
• The economic forecast used for the 2023 IRP reflects a softened expansionary
economy in Idaho over the near term and reversion to the long-term trend of the
service area economy. While Idaho had the highest residential population growth rate
of any state in the nation for the 5 years ending 2020, customer growth and residential
permit issuances have come down from those highs in 2022. However, net migration
and business investment continues to result in positive economic activity.
• Conservation impacts—including DSM energy efficiency programs, codes and
standards, and other naturally occurring efficiencies—are integrated into the sales
forecast. These impacts are expected to continue to erode Use Per Customer (UPC)
over much of the forecast period.
2023 IRP Sales and Load Forecast
Page 4 2023 Integrated Resource Plan—Appendix A
• New industrial and Energy Service Agreement (ESA) customer requests are inherently
uncertain regarding location and capacity needs. The anticipated load forecast reflects
only those industrial customers that have made a sufficient and significant binding
investment and/or interest indicating a commitment of the highest probability of
locating in the service area. The large numbers of prospective businesses that have
indicated some interest in locating in Idaho Power’s service area but have not made
sufficient commitments are not included in the anticipated sales and load forecast.
• The electricity price forecast used to prepare the sales and load forecast in the 2023 IRP
reflects the additional plant investment and variable costs of integrating the resources
identified in the 2021 IRP preferred portfolio. Retail electricity prices throughout the
planning period can impact the sales forecast, a consequence of the inverse relationship
between electricity prices and electricity demand.
Peak-Hour Demands
Average loads, as discussed in the preceding section, are an integral component to the load
forecast, as is the impact of the peak-hour demands on the system. Like the sales forecast
discussed in the preceding section, the peak models incorporate several peak forecast
scenarios based on historical probabilities of peak day temperatures at the 50th, 70th, 90th,
and 95th-percentiles of occurrence for each month of the year. The peak-hour demands (peaks)
are forecasted separately using regressions that are expressed as a function of the sales
(average load) forecast as well as the impact of peak-day temperatures. More discussion is
provided in the forthcoming sections.
The peak forecast results and comparisons with previous forecasts differ for many reasons,
including the following:
• The all-time system summer peak demand was 3,751 MW, recorded
Wednesday, June 30, 2021, at 7 p.m. The previous all-time system summer peak
demand, adjusted for demand response, was 3,437 MW, recorded Friday, July 2, 2013,
at 5 p.m. Idaho Power’s winter peak-hour load record is 2,604 MW,
recorded December 22, 2022, at 9 a.m. The previous winter peak-hour load record was
2,527 MW, realized December 10, 2009, at 8 a.m., and matched January 6, 2017,
at 9 a.m.
• The peak model develops peak-scenario impacts based on historical probabilities of
peak day temperatures at the 50th, 70th, 90th, and 95th-percentiles of occurrence for
each month of the year. These average peak-day temperature drivers are calculated
over the 1993 to 2022 period (the most recent 30 years).
2023 IRP Sales and Load Forecast
2023 Integrated Resource Plan—Appendix A Page 5
• The 2023 IRP peak-demand forecast considers the impact of the current actualized
committed and implemented energy efficiency DSM programs on peak demand.
Overview of the Forecast and Scenarios
Page 6 2023 Integrated Resource Plan—Appendix A
OVERVIEW OF THE FORECAST AND SCENARIOS
The sales and load forecast is constructed by developing a separate energy forecast for each
of the major customer classes: residential, commercial, irrigation, industrial, and ESA
customers. In conjunction with this load (or sales) forecast, an hourly peak-load (peak) forecast
was prepared. In addition, several probability cases were developed for the energy and peak
forecasts. Assumptions for each of the individual categories, the peak hour impacts,
and probabilistic case methodologies are described in greater detail in the following sections.
Forecast Probabilities
Load Forecasts Based on Weather Variability
The future demand for electricity by customers in Idaho Power’s service area is represented by
three load forecasts reflecting a range of load uncertainty due to weather. The anticipated
average load forecast represents the most probable projection of system load growth during
the planning period and is based on the most recent national, state, MSA, and county economic
forecasts and the resulting derived economic forecast for Idaho Power’s service area.
The 50th-percentile average load forecast assumes average temperatures and precipitation
(i.e., there is a 50% chance loads will be higher or lower than the anticipated load forecast
due to colder-than-normal or hotter-than-normal temperatures and wetter-than-normal or
drier-than-normal precipitation). However, the 30-year climatology has been increasing over
the past several decades, implying a cold bias in the calculation. Since actual loads can vary
significantly depending on weather conditions, alternative scenarios were developed to
address load variability due to variable weather—the 70th- and 90th-percentile load forecasts.
The 70th-percentile weather was utilized in the anticipated case to adjust for any systemic
historic changes.
Illustratively, Idaho Power’s maximum annual average load occurs when the highest recorded
levels of heating degree days (HDD) are assumed in winter and the highest recorded levels of
cooling degree days (CDD) and growing degree days (GDD) combined with the lowest recorded
level of precipitation are assumed in summer. Conversely, the minimum annual average load
occurs when the opposite of what is described above takes place. In the 70th-percentile
residential and commercial load forecasts, temperatures in each month were assumed to be at
the 70th-percentile of HDD in wintertime and at the 70th-percentile of CDD in summertime. In
the 70th-percentile irrigation load forecast, GDD were assumed to be at the 70th-percentile and
precipitation at the 30th-percentile, reflecting drier-than-median weather. The 90th-percentile
load forecast was similarly constructed.
For example, the median HDD in December from 1993 to 2022 (the most recent 30 years)
was 1,020 at the Boise Weather Service office. The 70th-percentile HDD is 1,048 and would be
Overview of the Forecast and Scenarios
2023 Integrated Resource Plan—Appendix A Page 7
exceeded in 3 out of 10 years. The 90th-percentile HDD is 1,126 and would be exceeded in 1 out
of 10 years. As an example, for a single month, the near 100th-percentile HDD (the coldest
December over the 30 years) is 1,284, which occurred in December 2016. This same concept
was applied in each month throughout the year for the weather-sensitive customer classes:
residential, commercial, and irrigation.
Since Idaho Power loads are highly dependent on weather and the development of multiple
scenarios allows the careful examination of load variability and how it may impact future
resource requirements, it is important to understand that the probabilities associated with
these forecasts apply to each month. This assumes temperatures and precipitation would
maintain at the 70th-percentile or 90th-percentile level continuously, throughout the entire year.
Table 1 summarizes the load scenarios prepared for the 2023 IRP.
Table 1. Average load and peak-demand forecast scenarios
ability Probability of Exceeding

90th Percentile 90% 1 in 10 years
Anticipated Case 70% 3 in 10 years
50th Percentile 50% 1 in 2 years GDD, precipitation
Forecasts of Peak Demand
95th Percentile 95% 1 in 20 years -day temperatures
90th Percentile 90% 1 in 10 years -day temperatures
70th Percentile 70% 3 in 10 years -day temperatures
50th Percentile 50% 1 in 2 years -day temperatures

Results of Idaho Power’s weather-related probabilistic system load projections are reported in
Table 2 and shown in Figure 1.

Table 2. System load growth (aMW)
Growth 2024 2028 2033 2043
Annual
Growth Rate 2024–2043
90th Percentile ………………………………………………………………. 2,087 2,627 2,854 3,076 2.1%
Anticipated Case 2,024 2,561 2,784 2,999 2.1%
50th Percentile………………………………………………………………. 1,974 2,507 2,727 2,936 2.1%
Overview of the Forecast and Scenarios
Page 8 2023 Integrated Resource Plan—Appendix A

Figure 1. Forecast system load (aMW)1
Load Forecasts Based on Economic Uncertainty
The anticipated load forecast is based on the most recent economic forecast for Idaho Power’s
service area and represents Idaho Power’s most probable outcome for load growth during the
planning period.
To provide risk assessment to economic uncertainty, two additional load forecasts for Idaho
Power’s service area were prepared based on the anticipated case forecast. The forecasts
provide a range of possible load growth rates for the 2024 to 2043 planning period due to high
and low economic and demographic conditions. The average growth rates for these high and
low growth scenarios were derived from the historical distribution of one-year growth rates
over the past 25 years (1998–2022).
Of the three scenarios 1) the anticipated forecast is the median growth path, 2) the standard
deviation observed during the historical time is used to estimate the dispersion around the
anticipated scenario, and 3) the variation in growth rates will be equivalent to the variation in
growth rates observed over the past 25 years (1998–2022).

1 The Astaris elemental phosphorous plant (previously FMC) was located at the western edge of Pocatello, Idaho.
Although no longer a customer of Idaho Power, Astaris had been Idaho Power’s largest individual customer and,
in some years, averaged nearly 200 aMW each month. In April 2002, the energy service agreement between
Astaris and Idaho Power was terminated.

Overview of the Forecast and Scenarios
2023 Integrated Resource Plan—Appendix A Page 9
From the above methodology, two views of probable outcomes form the forecast scenarios—
the probability of exceeding and the probability of occurrence—were developed and are
reported in Table 3. The probability of exceeding the likelihood the actual load growth will be
greater than the projected growth rate in the specified scenario. For example, over the next
20 years, there is a 10% probability the actual growth rate will exceed the growth rate
projected in the high scenario; additionally, it can be inferred that for the stated periods there
is an 80% probability the actual growth rate will fall between the low and high scenarios.
The second probability estimate, the probability of occurrence, indicates the likelihood the
actual growth will be closer to the growth rate specified in that scenario than to the growth
rate specified in any other scenario. For example, there is a 26% probability the actual growth
rate will be closer to the high scenario than to any other forecast scenario for the entire 20-year
planning horizon.
Table 3. Forecast probabilities

Scenario 1-year 5-year 10-year 20-year
Low Growth…………………………………………………………………………………………………………90% 90% 90% 90%
Anticipated Case………………………………………………………………………………………………… 50% 50% 50% 50%
High Growth………………………………………………………………………………………………………..10% 10% 10% 10%
Probability of Occurrence
Scenario 1-year 5-year 10-year 20-year
Low Growth…………………………………………………………………………………………………………26% 26% 26% 26%
Anticipated Case………………………………………………………………………………………………….48% 48% 48% 48%
High Growth………………………………………………………………………………………………………..26% 26% 26% 26%

This probabilistic analysis was applied to Idaho Power’s system load forecast. Its impact on the
system load forecast is the sum of the individual loads of residential, commercial, industrial,
and irrigation customers, as well as ESA customers (including past sales to Astaris, Inc.
[aka FMC]) and on-system contracts (including past sales to Raft River Coop and the City
of Weiser).
Results of Idaho Power’s economic scenario probabilistic system load projections are reported
in Table 4 and shown in Figure 2. The anticipated system load-forecast growth rate averages
2.1% per year over the 20-year planning period. The low scenario projects the system load will
increase at an average rate of 1.9% per year throughout the forecast period. The high
scenario projects a load growth of 2.4% per year. Idaho Power has experienced both the
high- and low-growth rates in the past. These forecasts provide a range of projected growth
Overview of the Forecast and Scenarios
Page 10 2023 Integrated Resource Plan—Appendix A
rates that cover approximately 80% of the probable outcomes as measured by Idaho Power’s
historical experience.
Table 4. System load growth (aMW)
Growth 2024 2028 2033 2043 Annual Growth Rate
2024–2043
Low…………………………………………………… 1,950 2,455 2,630 2,769 1.9%
Anticipated……………………………………….. 2,024 2,561 2,784 2,999 2.1%
High…………………………………………………… 2,066 2,664 2,930 3,224 2.4%

Figure 2. Forecast system load (aMW)
1,000
1,200
1,400
1,600
1,800
2,000
2,200
2,400
2,600
2,800
3,000
3,200
3,400
1992 1997 2002 2007 2012 2017 2022 2027 2032 2037 2042
Weather Adjusted (excluding Astaris)Anticipated Case High Low
Company System Load
2023 Integrated Resource Plan—Appendix A Page 11
COMPANY SYSTEM LOAD
System load is the sum of the individual loads of residential, commercial, industrial, and
irrigation customers, as well as ESA customers (including past sales to Astaris) and on-system
contracts (including past sales to Raft River and the City of Weiser). The system load excludes all
long-term, firm off-system contracts.
The anticipated system load forecast is based on the output of the regression and forecasting
models referenced previously and represents Idaho Power’s most probable load growth during
the planning period. The load growth of the anticipated system forecast averages 2.1% per year
from 2024 to 2043. Company system load projections are reported in Table 2 and shown in
Figure 1.
In the 70th-percentile (anticipated) forecast, the company system load is expected to increase
from 2,024 aMW in 2024 to 2,999 aMW in 2043, an average annual growth rate of 2.1%. In the
weather sensitive scenarios, the 50th-percentile and 90th-percentile forecasts, the company
system load is expected to increase from 1,974 aMW in 2024 to 2,936 aMW by 2043 and
increase from 2,087 aMW in 2024 to 3,076 aMW, respectively. All scenarios have an average
growth rate of 2.1% per year over the planning period. In the economic probability scenarios,
the company system load is expected to increase in the low case from 1,950 aMW in 2024
to 2,769 aMW in 2043, an average annual growth rate of 1.9% and in the high case from
2,066 aMW to 3,224 aMW, an average annual growth rate of 2.4% (Table 4).
The system load, excluding Astaris (formerly known as FMC), portrays the current underlying
general business growth trend within the service area. However, the system load with Astaris
is instructive regarding the impact of a loss or gain of a significant large-load customer on
system load.
Accompanied by the outlook of economic growth for Idaho Power’s service area throughout
the forecast period, continued growth in Idaho Power’s system load is expected. Total load is
made up of system load plus long-term, firm, off-system contracts. Currently, there are no
contracts in effect to provide long-term, firm energy off-system.
The composition of system company electricity sales by year is shown in Figure 3.
Residential sales are forecast to be about 22% higher in 2043, gaining 1.2 million megawatt
hours (MWh) over 2024. Industrial sales are expected to be 28% higher, or 0.8 million MWh,
followed by commercial (17% higher, or 0.7 million additional MWh) and irrigation (12% higher
in 2043 than 2024). Additional firm sales are expected to more than quadruple by 2043,
gaining 5 million MWh over 2024.

Company System Load
Page 12 2023 Integrated Resource Plan—Appendix A

Figure 3. Composition of system company electricity sales (thousands of MWh)
Additional Scenarios Developed
In addition to the anticipated sales forecast, differing weather probability cases, and high and
low economic cases, alternative sales and load cases were developed for analysis within the
2023 IRP. These scenarios included load flattening, high penetration future of building and
transportation electrification, and the addition of approximately 100 MW or 200 MW of
capacity requirements to the load forecast due to high growth within the commercial and
industrial classes. These additional scenarios are discussed in the following.
Load Flattening
A scenario was generated in which the peak hours of the residential class were reduced,
and the load shifted from the peak to the lowest load times of the day to fill in the load valleys.
The objective of the load flattening scenario is not associated with a particular technology or
policy, but rather is an exercise to test the resource portfolios.
The peak and valley hours for both summer and winter were identified by observing the hourly
and seasonal trends of the residential class. A reduction of 10% was subtracted from each hour
of the peaks and added to the valleys.
The summer peak is defined as the hours of 5 to 10 p.m. for the months of May through
September. The summer demand was shifted to the hours of 3 to 8 a.m. the following day.
The winter season is November through March and has both morning and evening peaks.
These are defined as the hours of 7 to 10 a.m. and 6 to 10 p.m., respectively. The morning
Company System Load
2023 Integrated Resource Plan—Appendix A Page 13
winter peak was moved to the subsequent valley of 1 to 4 p.m., and the evening peak was
shifted to 1 to 4 a.m. the following day.
Electrification Scenarios
Rapid electrification scenarios were generated for the IRP to inform Idaho Power of system
load requirements should rapid and extensive electrification occur in Idaho Power’s service
area. Rapid electrification includes assumptions around both transportation and building
electrification, which includes light-duty electric vehicles; residential heat pump water heaters;
and residential air source (and ground source) heat pumps. These are discussed in detail
below. It is important to note this does not represent an electrification path that is most likely,
rather more on the far tails of electrification possibilities. The objective of the electrification
scenario is not associated with a probable outcome but rather is an exercise to test the
resource portfolios.
For the building electrification assumptions, current equipment saturations specified from
Idaho Power’s 2022 end-use study were identified and ramped up to an 80% saturation by the
end of the planning period. These saturations are calibrated to Idaho Power’s customer
forecast to understand the number of units that would be on the system and thus the
amount of energy required for the newly installed equipment. Those equipment saturations
were cross-referenced to equipment usage specifications from Applied Energy Group’s
(AEG) LoadMAP models used in Idaho Power’s 2022 energy efficiency potential study.
Further, the newly installed units were assumed to be the most efficient equipment known
today. The product of the saturations and resulting equipment annual usage was shaped to
understand the hourly impacts over the planning period. Load shapes were taken from the
Northwest Regional Technical Forum (RTF).
For transportation electrification, the electric vehicle adoption assumption was relaxed from
the most probable outcome, as included in the base forecast used in the 2023 IRP, to reach a
saturation level of 93% at the end of the planning period. The electric vehicle load shape was
obtained from the RTF, which was modified from an Avista Utilities Electric Vehicle Supply
Equipment (EVSE) study. The goal was to shift the primary amount of required load away from
the typical summer peak hours into the late evening, as well as the late morning. During this
process, it was also assumed workplace charging became more common.
In these scenarios, all electric vehicles and conversions of space/water heating from natural gas
to electricity were load building. All electric resistance space/water heating and currently
installed heat pumps and air conditioners were converted to more efficient heat pumps and
reduced system load.
Company System Load
Page 14 2023 Integrated Resource Plan—Appendix A
Idaho Power will continue to monitor electric vehicle registrations from the Idaho Department
of Transportation, as well as update end-use studies every few years, to assess if a similar rapid
and extensive electrification scenario is being entered into as modeled.
High Growth Scenarios
Additional scenarios were run for high-growth futures in the Idaho Power service area.
There have been numerous requests to Idaho Power for development of large commercial and
industrial projects over the course of 2022 and 2023. These scenarios were developed to
capture the potential of one of these projects moving forward and assess resource adequacy
and cost. The first scenario represents a single or aggregate 100 MW added on to Idaho
Power’s system over the course of year 2026. The second scenario represents a single or
aggregate 200 MW added on to Idaho Power’s system, ramping up over the years 2026–2027.
Company System Peak
2023 Integrated Resource Plan—Appendix A Page 15
COMPANY SYSTEM PEAK
System peak load includes the sum of the coincident peak demands of residential,
commercial, industrial, and irrigation customers, as well as ESA customers (including Astaris,
historically) and on-system contracts (Raft River and the City of Weiser, historically).
Seasonal Peak Forecast
Idaho Power has two peak periods: 1) a winter peak, resulting primarily from space-heating
demand that normally occurs in December, January, or February and 2) a larger summer peak
that normally occurs in late June, July, or August, which coincides with cooling load and
irrigation pumping demand. The summer peak is reflective of the annual peak for the company.
The all-time system summer peak demand was 3,751 MW, recorded on Wednesday, June 30,
2021, at 7 p.m. The previous all-time system summer peak demand, adjusted for demand
response, was 3,437 MW, recorded on Friday, July 2, 2013, at 5 p.m. The system summer peak
load growth accelerated from 1998 to 2008 as a record number of residential, commercial, and
industrial customers were added to the system and air conditioning became standard in nearly
all new residential homes and new commercial buildings.
In the 95th-percentile forecast, the system summer peak load is expected to increase from
3,920 MW in 2024 to 5,427 MW in 2043. In the 90th-percentile forecast, the system summer
peak load is expected to increase from 3,894 MW in 2024 to 5,401 MW in 2043. In the
70th-percentile forecast, or anticipated case, the system summer peak load is expected to
increase from 3,830 MW in 2024 to 5,337 MW in 2043. Finally, in the 50th-percentile forecast,
the system summer peak load increases from 3,767 MW in 2024 to 5,274 MW in 2043.
The 95th- and 90th-percentile forecasts represent an average summer peak growth rate of 1.7%
per year over the planning period. The 70th- and 50th-percentile forecasts represent an average
summer peak growth rate of 1.8% per year over the planning period (Table 5).
Table 5. System summer peak load growth (MW)
Growth 2024 2028 2033 2043
Annual
Growth Rate 2024–2043
95th Percentile…………………………………………………………… 3,920 4,592 4,937 5,427 1.7%
90th Percentile…………………………………………………………… 3,894 4,565 4,911 5,401 1.7%
70th Percentile…………………………………………………………… 3,830 4,501 4,847 5,337 1.8%
50th Percentile…………………………………………………………… 3,767 4,439 4,784 5,274 1.8%

The four scenarios of projected system summer peak loads are illustrated in Figure 4. Much of
the variation in peak load is due to weather conditions. Note that unique economic events have
Company System Peak
Page 16 2023 Integrated Resource Plan—Appendix A
occurred. As an example, in the summer of 2001, the summer peak was dampened by a nearly
30% curtailment in irrigation load due to a voluntary load reduction program.

Figure 4. Forecast system summer peak (MW)
The all-time system winter peak demand was 2,604 MW, recorded Thursday, December 22,
2022, at 9 a.m. The previous all-time system winter peak demand was 2,527 MW, realized
Thursday, December 10, 2009, at 8 a.m. and matched January 6, 2017, at 9 a.m. As shown in
Figure 5, the historical system winter peak load is much more variable than the summer system
peak load. This is because the variability of peak-day temperatures in winter months is greater
than the variability of peak-day temperatures in summer months. The wider spread of the
winter peak forecast lines in Figure 5 illustrates the higher variability associated with winter
peak-day temperatures.
In the 95th-percentile forecast, the system winter peak load is expected to increase from
2,750 MW in 2024 to 3,593 MW in 2043, an average growth rate of 1.4% per year over the
planning period. In the 90th-percentile forecast, the system winter peak load is expected to
increase from 2,647 MW in 2024 to 3,557 MW in 2043, an average growth rate of 1.6% per year
over the planning period. In the 70th-percentile forecast, or anticipated case, the system winter
peak is expected to increase from 2,567 MW in 2024 to 3,477 MW in 2043, an average growth
rate of 1.6% per year over the planning period. In the 50th-percentile forecast, the system
winter peak load is expected to increase from 2,512 MW in 2024 to 3,422 MW in 2043,
Company System Peak
2023 Integrated Resource Plan—Appendix A Page 17
an average growth rate of 1.6% per year over the planning period. This data is represented in
Table 6. The four scenarios of projected system winter peak load are illustrated in Figure 5.2
Table 6. System winter peak load growth (MW)
Growth 2024 2028 2033 2043
Annual
Growth Rate
2024–2043
95th Percentile……………………………………………………………. 2,750 3,269 3,441 3,593 1.4%
90th Percentile……………………………………………………………. 2,647 3,165 3,379 3,557 1.6%
70th Percentile……………………………………………………………. 2,567 3,085 3,299 3,477 1.6%
50th Percentile……………………………………………………………. 2,512 3,029 3,243 3,422 1.6%

Figure 5. Forecast system winter peak (MW)
The historic relationship of summer and winter peaks is depicted in Figure 6. The growth in the
summer peak over the past several decades in Idaho Power’s service territory, as evidenced by

2 Idaho Power uses a median peak-day temperature driver in lieu of an average peak-day temperature driver in the
50/50 peak-demand forecast scenario. The median peak-day temperature has a 50% probability of being
exceeded. Peak-day temperatures are not normally distributed and can be skewed by one or more extreme
observations; therefore, the median temperature better reflects expected temperatures within the context of
probabilistic percentiles. The weighted average peak-day temperature drivers are calculated over the 1993 to
2022 period (the most recent 30 years).
Company System Peak
Page 18 2023 Integrated Resource Plan—Appendix A
the shift in the most-recent slope lines, has been significantly greater due to the increased
presence of urban cooling load in the peak summer months.

Figure 6. Idaho Power monthly peaks (MW)
Note the 2023 IRP peak-demand forecast model explicitly excludes the impact of demand
response programs to establish peak impacts. The exclusion allows for planning for demand
response programs and supply-side resources in meeting peak demand without the
interference of load intervention on causal variables.
Peak Model Design
Peak-hour demands are integral components to the company’s system planning. Peak-hour
demands are forecast using a system of 12 regression equations, one for each month of the
year. For most monthly models, the regressions are estimated using over 20 years of historical
MW
Avg Daily Temp (system weighted)
Monthly Peaks
Company System Peak
2023 Integrated Resource Plan—Appendix A Page 19
data. However, the estimation periods vary. The peak-hour forecasting regressions express
system peak-hour demand as a function of calendar sales (stated in average megawatts) as well
as the impact of peak-day temperatures, and in some months, precipitation. The contribution
to the system peak of the company’s ESA customers is determined independently,
using historical coincident peak factors, and then added to determine the system peak.
The forecast of average peak-day temperatures is a key driver of the monthly system peak
models. The normal average peak-day temperature drivers are calculated over the 1993 to
2022 period (the most recent 30 years). In addition, the peak model develops peak scenarios
based on historical probabilities of peak day temperatures at the 50th, 70th, 90th, and 95th
percentiles of occurrence for each month of the year.
Note the summertime (June through September) system peak regression models were
re-specified to account for the upward trend in weighted average peak-day temperatures over
time. The trendlines were fitted to the historical weighted average peak-day temperatures and
then projected through 2043, the end of the forecast period. These are added as explanatory
variables in the summertime regression models. The addition of these variables resulted in
models that better fit the actual historical summertime system peaks.
Class Sales Forecast
Page 20 2023 Integrated Resource Plan—Appendix A
CLASS SALES FORECAST
Residential
The 70th-percentile (anticipated) residential load is forecast to increase from 678 aMW in 2024
to 830 aMW in 2043, an average annual compound growth rate of 1.1%. In the 50th-percentile
scenario, the residential load is forecast to increase from 655 aMW in 2024 to 799 aMW in 2043
at an average annual compound growth rate of 1.1%, matching the anticipated residential
growth rate. The 90th-percentile residential load is forecast to increase from 707 aMW in 2024
to 870 aMW in 2043, also at an average annual compound growth rate of 1.1%. The residential
load forecasts are reported in Table 7 and shown in Figure 7.
Table 7. Residential load growth (aMW)
Growth 2024 2028 2033 2043 Annual
Growth Rate
2024–2043
90th Percentile………………………………………………………………. 707 740 793 870 1.1%
Anticipated Case…………………………………………………………… 678 708 758 830 1.1%
50th Percentile………………………………………………………………. 655 683 731 799 1.1%

Figure 7. Forecast residential load (aMW)
Sales to residential customers made up 31% of Idaho Power’s system sales in 1992 and 37% of
system sales in 2022. The number of residential customers is projected to increase to nearly
724,000 by December 2043.
Class Sales Forecast
2023 Integrated Resource Plan—Appendix A Page 21
The average sales per residential customer increased to nearly 14,800 kilowatt-hours (kWh) in
1980 before declining to 13,200 kWh in 2001. In 2002, residential UPC dropped dramatically—
over 500 kWh per customer from 2001—the result of significantly higher electricity prices
combined with a weak national and service area economy. The reduction in electricity prices in
June 2003 and a recovery in the service-area economy caused residential UPC to stabilize
through 2007. However, conservation efforts have placed downward pressure on residential
UPC since that point. This trend is expected to continue, declining at 0.6% annually over the
2024–2043 planning period, as total residential UPC is expected to decrease to approximately
9,700 kWh by 2043. Residential UPC is shown in Figure 8.

Figure 8. Forecast residential UPC (weather-adjusted kWh)
Residential customer growth in Idaho Power’s service area is a function of the number of new
service-area households as derived from Moody’s Analytics’ forecast of county housing stock
and demographic data. The residential customer forecast for 2024 to 2043 shows an average
annual compound growth rate of 1.6% as shown in Figure 9.
5,000
7,000
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Actual Forecast
Class Sales Forecast
Page 22 2023 Integrated Resource Plan—Appendix A

Figure 9. Residential customer growth rates (12-month change)
Final sales to residential retail customers can be framed as an equation that considers several
factors affecting electricity sales to the residential sector. These factors include, but are not
limited to: HDD (wintertime); CDD (summertime); historic energy efficiency trends in Idaho
Power’s residential customer base; saturation and replacement cycle of appliances; the number
of service-area households; the real price of electricity; and the real price of natural gas.
A general schematic of the forecasting methodology using a statistically adjusted end-use (SAE)
forecast model as described above that is used in Idaho Power’s forecast residential sales is
provided in Figure 10.
Class Sales Forecast
2023 Integrated Resource Plan—Appendix A Page 23

Figure 10. Residential sales forecast methodology framework
There were several instances in the SAE framework where the overall outcomes could
benefit from the inclusion of indicator variables. In assessing these and combination thereof,
Idaho Power selected the best statistical result across a menu of options using cross
validation methods.
Commercial
The commercial category is primarily made up of Idaho Power’s small general-service and large
general-service customers. Additional customer types associated with this category include
small general-service on-site generation, customer energy production net-metering, unmetered
general service, street-lighting service, traffic-control signal lighting service, and dusk-to-dawn
customer lighting.
Within the 70th-percentile (anticipated case) scenario, commercial load is projected to increase
from 500 aMW in 2024 to 586 aMW in 2043 (Table 8). The average annual compound growth
rate of the commercial load in the anticipated scenario is 0.8% during the forecast period.
The commercial load in the 50th-percentile scenario is projected to increase from 492 aMW
in 2024 to 576 aMW in 2043, also at an average annual compound growth rate of 0.8%.
The commercial load in the 90th-percentile scenario is projected to increase from 509 aMW in
2024 to 599 aMW in 2043, an average annual compound growth rate of 0.9%. The commercial
load forecast scenarios are illustrated in Figure 11.
Residential
Sales
Forecast
Class Sales Forecast
Page 24 2023 Integrated Resource Plan—Appendix A
Table 8. Commercial load growth (aMW)
Growth 2024 2028 2033 2043
Annual
Growth Rate
2024–2043
90th Percentile………………………………………………………………. 509 524 548 599 0.9%
Anticipated Case…………………………………………………………… 500 515 537 586 0.8%
50th Percentile………………………………………………………………. 492 506 528 576 0.8%

Figure 11. Forecast commercial load (aMW)
With a customer base of over 77,300, the commercial class represents the diversity of the
service area economy, ranging from residential subdivision pressurized irrigation to large
manufacturers. Due to this diversity in load intensity and use—for analytical purposes—
the category is segmented into categories associated with common elements of energy-use
influences, such as economic variables (e.g., employment), industry (e.g., manufacturing),
and building structure characteristics (e.g., offices). Figure 12 shows the breakdown of the
categories and their relative sizes based on 2022 billed energy sales.
Class Sales Forecast
2023 Integrated Resource Plan—Appendix A Page 25

Figure 12. Commercial building share—energy use
As indicated in Figure 12, agricultural-related and office-oriented operations represent
approximately 50% of the commercial sector. The mercantile group continues a contraction
trend due to consolidation and online/home delivery substitution, with substitutive growth
coming to manufacturing/distribution. Growth continues within the construction group,
albeit slowing in the most recent period as new single-housing unit share has diminished in
favor of multi-family housing as well as inventory overhang within the market. The health and
education group consolidation that had previously exhibited contraction in share and growth
rates has diminished and stabilized as of the last IRP. As referenced above, the online share of
the supply chain has resulted in continued growth in warehouse and distribution customers,
reflected in the manufacturing/distribution group. Agricultural and manufacturing operations
continue to migrate to the service territory and flourish with average long-term growth rates of
1.6% and 2.9%, respectively.
The number of commercial customers is expected to increase at an average annual rate of
1.5%, reaching approximately 105,200 customers by December 2043. In 1992, customers in the
commercial category consumed approximately 19% of Idaho Power system sales, growing to
27% by 2022.
Class Sales Forecast
Page 26 2023 Integrated Resource Plan—Appendix A
Figure 13 shows historical and forecast average UPC for the entire category. The commercial
UPC metric in Figure 13 represents an aggregated metric for a highly diverse group of
customers with significant differences in total energy UPC, nonetheless it is instructive in
aggregate for comparative purposes.
The UPC peaked in 2001 at 67,800 kWh and has declined at approximately 1% compounded
annually to 2022. The UPC is forecast to decrease at an annual rate of 0.7% over the planning
period. For this category, common elements that drive use down include a shift toward
service-based over industrial customer composition, adoption of energy efficiency technology,
and electricity prices.

Figure 13. Forecast commercial UPC (weather-adjusted kWh)
Figure 14 shows the diversity in the commercial segment’s UPC as well as the trend for these
sectors. The figure shows the 2022 UPC for each segment relative to the 2016 UPC. A value
greater than 100% indicates the UPC has risen over the period. The figure supports the general
decline of the aggregated trend of Figure 13 but highlights differences in energy and
economic dynamics within the heterogeneous commercial category not evident in the
residential category.
20,000
30,000
40,000
50,000
60,000
70,000
80,000
90,000
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Class Sales Forecast
2023 Integrated Resource Plan—Appendix A Page 27

Figure 14. Commercial categories UPC, 2022 relative to 2016
Energy efficiency implementation is a large determinant in UPC decline over time. In the
commercial sector, the primary DSM technology impact has come from lighting,
however manufacturing motors are significant for that sector. Understandably, aggressive DSM
measures can reduce a customer’s usage to trigger a rate-class change from industrial to
commercial class. These shifts are evident in the chart with the most aggressive DSM
implementation categories of Education and Food Sales. Other influences on UPC include
differences in price sensitivity, sensitivity to business cycles and weather, and degree and
trends in automation. In addition, category UPC can vary when a customer’s total use increases
to the point where it must, by tariff rules, migrate to an industrial (Rate 19) category. Tariff
migration occurs at the boundary of Schedule 9P (large primary commercial) and Schedule 19
(large industrial). Note the forecast models aggregate the energy use of these two schedules to
mitigate this influence.
The commercial sales forecast equations consider several varying factors, as informed by the
regression models, and vary depending on the category. Typical variables include corporate
earnings; government spending; wholesale/retail trade; HDD (wintertime); CDD (summertime);
specific industry growth characteristics and outlook; service-area demographics such as
households, employment, small business conditions; the real price of electricity; and energy
efficiency adoption.
Industrial
The industrial category is comprised of Idaho Power’s large power service (Schedule 19)
customers requiring monthly metered demands between 1,000 kilowatts (kW) and 20,000 kW.
Class Sales Forecast
Page 28 2023 Integrated Resource Plan—Appendix A
The category name “Industrial” is reflective of load requirements and not necessarily indicative
of the industrial nature of the customers’ business.
In 1980, Idaho Power had about 112 industrial customers, which represented about 12% of
Idaho Power’s system sales. By December 2022, the number of industrial customers had risen
to 125, representing approximately 17% of system sales. As mentioned earlier in the
commercial discussion, customer counts in this tariff class are impacted by migration to and
from the commercial class as dictated by tariff rules. However, customer count growth is
primarily illustrative of the positive economic conditions in the service area. Customers with
load greater than Schedule 19 ranges are known as ESA customers and are addressed in the
Additional Firm Load section of this document.
In the anticipated forecast, industrial load grows from 311 aMW in 2024 to 400 aMW in 2043,
an average annual growth rate of 1.3% (Table 9). To a large degree, industrial load variability is
not associated with weather conditions as is the case with residential, commercial, and
irrigation; therefore, the forecasts in the 50th- and 90th-percentile weather scenarios are
identical to the anticipated industrial load scenario. The industrial load forecast is pictured in
Figure 15.
Table 9. Industrial load growth (aMW)
Growth 2024 2028 2033 2043
Annual
Growth Rate
2024–2043
Anticipated Case………………………………………………………… 311 326 346 400 1.3%
Class Sales Forecast
2023 Integrated Resource Plan—Appendix A Page 29

Figure 15. Forecast industrial load (aMW)
As discussed previously, the load growth variability is impacted by both economic,
non-weather factors, and the impacts of DSM. In developing the forecast, customer-specific
DSM implementation is isolated as DSM varies significantly by customer, and the actual energy
use is adjusted to remove the impacts of DSM to optimize the causal influence of non-DSM
causal variables. The history and forecast of DSM are provided by the DSM specialists within
Idaho Power. The economic and other independent (causal) variables for the regression models
are provided by third-party data providers and internally derived time-series for Idaho Power’s
service area.
Figure 16 illustrates the 2022 share of each of the categories within the Rate 19 customers.
By far, the largest share of electricity was consumed by the food manufacturing sector (39%),
followed by dairy (19%) and construction-related (7%). The categorization scheme includes a
range of service-providing industrial building types (assembly, lodging, warehouse, office,
education, and health care). These provide the basis for capturing, modeling, and forecasting
the shifting economic landscape that influences industrial category electricity sales.
Class Sales Forecast
Page 30 2023 Integrated Resource Plan—Appendix A

Figure 16. Industrial electricity consumption by industry group (based on 2022 sales)
The regression models and associated explanatory variables resulting from the
categorization establish the relationship between historical electricity sales and variables
such as, corporate earnings, economics, price, technological, demographic, and other
influences in the form of estimated coefficients from the industry group regression models
applied to the appropriate forecasts of independent time series of energy use. From this
output, the history and forecast of previously excluded DSM is subtracted. Figure 17 shows the
general forecasting methodology used for both the commercial and industrial sectors.
Class Sales Forecast
2023 Integrated Resource Plan—Appendix A Page 31

Figure 17. Commercial and industrial sales forecast methodology
Irrigation
The irrigation category is comprised of agricultural irrigation service customers.
Service under this schedule is applicable to energy supplied to agricultural-use customers at
one point-of-delivery for operating water pumping or water-delivery systems to irrigate
agricultural crops or pasturage.
The 70th-percentile (anticipated) irrigation load is forecast to increase slowly from 240 aMW
in 2024 to 268 aMW in 2043, an average annual compound growth rate of 0.6%. In the
50th-percentile scenario, irrigation load is projected to be 224 aMW in 2024 and 251 aMW in
2043, also at an average annual compound growth rate of 0.6%. In the 90th-percentile scenario,
irrigation load is projected to be 260 aMW in 2024 and 288 aMW in 2043, an average annual
compound growth rate of 0.5%. All irrigation load growth scenarios forecast slower growth
than the system from 2024 to 2043. The individual irrigation load forecasts are summarized in
Table 10 and illustrated in Figure 18.
Table 10. Irrigation load growth (aMW)
Growth 2024 2028 2033 2043
Annual
Growth Rate
2024–2043
90th Percentile………………………………………………………………. 260 264 271 288 0.5%
Anticipated Case…………………………………………………………… 240 244 251 268 0.6%
50th Percentile………………………………………………………………. 224 227 234 251 0.6%
Utility Data
IPCCommercial
and Industrial
CommManuModel
Comm Large Services
IPCCommercialSales Forecast
CommServices Model
Comm LargeManu
Weather Data
IndustrialManu Model
IndustrialServices Model
UniqueIndustrialModels
IPC
IndustrialSales Forecast
IPC
Aggregate
C/I
Sales Forecast
Architecture = EconometricTraining Start = early 1990-2000Dependent Variable = Annual Sales
Economic Data
“Bolts”
Class Sales Forecast
Page 32 2023 Integrated Resource Plan—Appendix A

Figure 18. Forecast irrigation load (aMW)
The annual average loads in Table 10 and Figure 18 are calculated using 8,760 hours in a typical
year. In the highly seasonal irrigation sector, over 97% of the annual energy is billed during the
six months from May through October, and nearly half the annual energy is billed in just two
months, July and August. During the summer, hourly irrigation loads can constitute nearly
900 MW. In a normal July, irrigation pumping accounts for roughly 25% of the energy consumed
during the hour of the annual system peak and nearly 30% of the energy consumed during July
for general business sales. The slight increase of forecasted sales over this period is due to the
expected increase in customer count from the conversion of flood/furrow irrigation to sprinkler
irrigation, primarily related to farmers aiming to reduce labor costs. Additionally, the trend
toward more water intensive crops—primarily alfalfa and corn—due to growth in the dairy
industry, explains most of the increased energy consumption in recent years.
The 2023 IRP irrigation sales forecast model considers several factors affecting electricity sales
to the irrigation class, including temperature; precipitation; Palmer Z Index (calculated by the
National Ocean and Atmospheric Administration [NOAA] from a combination of precipitation,
temperature, and soil moisture data); Moody’s Producer Price Index: Prices Received by
Farmers, All Farm Products; and annual maximum irrigation customer counts.
Actual irrigation electricity sales have grown from the 1970 level of 816,000 MWh to a peak
amount of 2,097,000 MWh in 2013. In 1977, irrigation sales reached a maximum proportion of
20% of Idaho Power system sales. In 2022, the irrigation proportion of system sales was 13%
due to the much higher relative growth in other customer classes.
Class Sales Forecast
2023 Integrated Resource Plan—Appendix A Page 33
In 1980, Idaho Power had about 10,850 active irrigation accounts. By 2022, the number of
active irrigation accounts had increased to 20,936 and is projected to be nearly 25,900 at the
end of the planning period in 2043.
As with other classes, average UPC is an important consideration. Since 1988, Idaho Power has
experienced growth in the number of irrigation customers but slow growth in total electricity
sales (weather-adjusted) to this sector. The number of customers has increased as customers
are converting previously furrow-irrigated land to sprinkler irrigated land. The conversion rate is
slow and the kWh UPC is substantially lower than the average existing Idaho Power irrigation
customer. This is because water for sprinkler conversions is drawn from canals and not pumped
from deep groundwater wells. In future forecasts, factors related to the conjunctive
management of ground and surface water and the possible litigation associated with the
resolution will require consideration. Depending on the resolution of these issues, irrigation
sales may be impacted.
Additional Firm Load
The additional firm-load category consists of Idaho Power’s largest customers. Idaho Power’s
tariff requires the company to serve requests for electric service greater than 20 MW under
an under a special contract, or ESA, schedule negotiated between Idaho Power and each
large-power customer. The ESA and tariff schedule are approved by the appropriate state
commission. An ESA allows a customer-specific cost-of-service analysis and unique operating
characteristics to be accounted for in the agreement.
Individual energy and peak-demand forecasts are developed for ESA customers, including
Micron Technology, Inc.; Simplot Fertilizer Company (Simplot Fertilizer); INL; Brisbie, LLC
(Meta Platforms, Inc.); and several anticipated new ESA customers. These ESA customers
comprise the entire forecast category labeled “additional firm load”.
In the anticipated forecast, additional firm load is expected to increase from 135 aMW in
2024 to 712 aMW in 2043, an average growth rate of 9.1% per year over the planning
period (Table 11). The additional firm load energy and demand forecasts in the 50th- and
90th-percentile scenarios are identical to the anticipated-load growth scenario. The scenario of
projected additional firm load is illustrated in Figure 19.
Table 11. Additional firm load growth (aMW)
Growth 2024 2028 2033 2043
Annual
Growth Rate
2024–2043
Anticipated Case…………………………………………………………. 135 589 702 712 9.1%

Class Sales Forecast
Page 34 2023 Integrated Resource Plan—Appendix A

Figure 19. Forecast additional firm load (aMW)
Micron Technology
Micron Technology represents Idaho Power’s largest electric load for an individual customer
and employs more than 5,000 workers in the Boise MSA. The company operates its research
and development fabrication facility in Boise and performs a variety of other activities,
including product design and support, quality assurance, systems integration and related
manufacturing, and corporate and general services. Micron Technology’s electricity use is a
function of the market demand for its products.
Simplot Fertilizer
This facility named the Don Plant is located just outside Pocatello, Idaho. The Don Plant is one
of four fertilizer manufacturing plants in the J.R. Simplot Company’s Agribusiness Group.
Vital to fertilizer production at the Don Plant is phosphate ore mined at Simplot’s Smoky
Canyon mine on the Idaho/Wyoming border. According to industry standards, the Don Plant
is rated as one of the most cost-efficient fertilizer producers in North America. In total,
J.R. Simplot Company employs 2,000–3,000 workers throughout its Idaho locations.
Idaho National Laboratory
Idaho National Laboratory (INL) is one of the United States Department of Energy’s (DOE)
national laboratories and is the nation’s lead laboratory for nuclear energy research,
development, and demonstration. The DOE, in partnership with its contractors, is focused on
performing research and development in energy programs and national defense. Much of the
work to achieve this mission at INL is performed in government-owned and leased buildings on
Class Sales Forecast
2023 Integrated Resource Plan—Appendix A Page 35
the Research and Education Campus (REC) in Idaho Falls, Idaho, and on the INL site, located
approximately 50 miles west of Idaho Falls. INL is recognized as a critical economic driver and
important asset to the state of Idaho with over 4,000 employees.
Brisbie, LLC (Meta Platforms, Inc.)
Idaho Power and Meta Platforms, Inc. (Meta) executed an ESA at the end of 2021, which is still
pending commission approval at the time of this report. Meta has announced the construction
of a new data center in Kuna, Idaho. With an estimated investment of $800 million, the Meta
data center is projected to bring more than 1,200 jobs to Kuna during peak construction and
100 operational jobs. Meta plans to support 100% of its operations through the addition of new
renewable resources connected to Idaho Power’s system. The renewables support will be
facilitated through a Clean Energy Your Way (CEYW) arrangement.
Additional Considerations
Page 36 2023 Integrated Resource Plan—Appendix A
ADDITIONAL CONSIDERATIONS
Several influential components and their associated impacts to the sales forecast are treated
differently in the forecasting and planning process. The following discussion touches on several
of those important topics.
Energy Efficiency
Energy efficiency (EE) influences on past and future load consist of utility programs, statutory
codes, and manufacturing standards for appliances, equipment, and building materials that
reduce energy consumption. As the influence of statutory codes and manufacturing standards
on customers has increased in importance relative to utility programs, Idaho Power continues
to modify its forecasting models to fully capture the impact. Idaho Power works closely with its
internal DSM program managers and utilizes the updated potential study, most recently
developed by Applied Energy Group (AEG). DSM guidance and the achievable potential from
AEG are used as a benchmark metric for validating forecast model output.
For residential models, the physical unit flow of energy-efficient products is captured through
integrating regional energy efficient product-shipments data into the retail and wholesale
distribution channels. The source for the shipments data is the DOE and is consistent with the
DOE’s National Energy Model (NEM). This data is first refined by Itron for utility-specific
applications. This data captures energy-efficient installations regardless of the source
(e.g., programs, standards, and codes). The DOE/Itron data is recognized in the industry as
well-specified for the homogenous residential sector.
While DOE data is available for the commercial sector, Idaho Power’s test modeling of the data
indicates the regional data does not provide sufficient segmentation to recognize the
heterogeneous differences between the Idaho regional micro-economic composition and the
mountain region economy. As discussed in the previous section on forecast methodology
within the commercial class, Idaho Power segments the commercial customers by economic
and energy profiles and incorporates historical energy efficiency adoption into billed sales.
Thus, the energy efficiency is directly modeled into the forecast model energy variable and the
forecast is adjusted in conformance with the DSM and AEG potential study forecast to
recognize energy efficiency. DOE data is not available for the industrial sector.
The weather and agricultural volatility of the billed sales for the irrigation sector is not
well-suited for modeling energy efficiency impacts. Idaho Power monitors energy efficiency
implementation in history and forecasts from internal and external sources (DSM staff and
presently AEG). The trend of historical implementation (imbedded in the historical usage data)
provides a guideline for evaluating the model forecast output relative to expected DSM and
codes and standards.
Additional Considerations
2023 Integrated Resource Plan—Appendix A Page 37
As discussed above, Idaho Power continuously evaluates the models for adequately capturing
the impacts of energy efficiency and implements improvements when indicated. With input
from DSM program managers and AEG’s knowledge base, Idaho Power retains a high
confidence in the representation of the impacts of energy efficiency in the forecast.
A more detailed description of DSM can be found in the main IRP document under the Energy
Efficiency section. Additionally, the company publishes a dedicated DSM annual report
submitted to the regulatory agencies.
On-Site Generation
In recent years, the number of customers transitioning from standard to net-metering service
(Schedules 6, 8, and 84) has risen dramatically, particularly for residential customers. While the
current population of on-site generation customers is over 2% of the population of retail
customers, recent adoption of solar is relatively strong for Idaho Power’s service area.
The installation of generation and storage equipment at customer sites causes the demand for
electricity delivered by Idaho Power to be reshaped throughout the year. It is important to
measure the overall and future impact on the sales forecast. The long-term sales forecast was
adjusted downward to reflect the impact of the increase in the number customers with on-site
generation, specifically solar generation, connecting to Idaho Power’s system.
Schedules 6, 8, and 84 (net-metering) customer billing histories were compared to billing
histories prior to customers becoming net-metering customers. The resulting average monthly
impact per customer (in kWh) was then multiplied by forecasts of the Schedule 6, 8, and 84
residential, commercial, and irrigation customer counts to estimate the future energy impact
on the sales forecast. The forecast of net metering customers serves as a function of historical
trends and current policy considerations.
The resulting forecast of net-metering customers multiplied by the estimated UPC sales
impact per customer results in a monthly downward adjustment to the sales forecast for
each class. At the end of the forecast period, 2043, the annual residential sales forecast
reduction was about 74 aMW, the commercial reduction was 3 aMW, and the irrigation
reduction was 6 aMW.
Electric Vehicles
The load forecast includes an update of the impact of plug-in electric vehicles (PEV) on system
load to reflect the future impact of this relatively new and evolving source of energy use.
While electric vehicle (EV) consumer adoption rates in Idaho Power’s service area remain
relatively low, the continued technological advancement, limiting attributes of vehicle range
refueling time, and charging availability and technology continue to improve the
competitiveness of these vehicles to non-electric models.
Additional Considerations
Page 38 2023 Integrated Resource Plan—Appendix A
As the market grows, historical adoption data builds to provide a foundation for forecasting
adoption rates and for the models to evolve. Idaho Power receives detailed registration
data from Idaho Transportation Department (ITD). The data provides county-level registration
which provides a basis for determining Idaho Power service-territory vehicle inventory.
Other data sources for monitoring the outlook for PEV adoption includes the DOE, R.L. Polk,
and Moody’s Analytics.
The evolution of the PEV market shows high adoption continues to be evident in
warmer climates, high-density and affluent population centers. The Idaho Power forecast
for PEVs shows the service territory will continue to fall into the lower adoption ranges.
Idaho Power continues to monitor battery technology advancement, vehicle prices, charging
rates, and charging station availability which will serve to build the adoption rate in the
service territory.
Demand Response
Existing and future demand response program impacts are not incorporated into the sales and
load forecast. However, because energy efficiency programs have an impact on peak demand
reduction, a component of peak hour load reduction is integrated into the sales and load
forecast models. This provides a consistent treatment of both types of programs, as energy
efficiency programs are considered in the sales and load forecast. A thorough description of
Idaho Power’s energy efficiency and demand response programs is included in Appendix B—
Demand-Side Management 2022 Annual Report.
Fuel Prices
Fuel prices, in combination with service-area demographic and economic drivers, impact long
term trends in electricity sales. Changes in relative fuel prices can also impact the future
demand for electricity. Class-level and economic-sector-level regression models were used to
identify the relationships between real historical electricity prices and their impact on historical
electricity sales. The estimated coefficients from these models were used as drivers in the
individual sales forecast models.
Short-term and long-term nominal electricity price increases are generated internally from
Idaho Power financial models. The nominal price estimates are adjusted for projected inflation
by applying the appropriate economic deflators to arrive at real fuel prices. The projected
average annual growth rates of fuel prices in nominal and real terms (adjusted for inflation)
are presented in Table 12. The growth rates shown are for residential fuel prices and can be
used as a proxy for fuel-price growth rates in the commercial, industrial, and irrigation sectors.
Additional Considerations
2023 Integrated Resource Plan—Appendix A Page 39
Table 12. Residential fuel-price escalation (2024–2043) (average annual percent change)
Nominal Real*
Electricity—2023 IRP ………………………………………………………………………………………………………………………. 0.1% -2.0%
Electricity—2021 IRP……………………………………………………………………………………………………………………….. 0.9% -1.2%
Natural Gas……………………………………………………………………………………………………………………………………… 0.3% -1.7%

Figure 20 illustrates the average electricity price paid by Idaho Power’s residential
customers over the historical period 1987 to 2022 and over the forecast period 2024 to 2043.
Both nominal and real prices are shown. In the 2023 IRP, nominal electricity prices are expected
to climb to about 11.8 cents per kWh by the end of the forecast period in 2043. Real electricity
prices (inflation adjusted) are expected to decline over the forecast period at an average rate
of 2% annually. In the 2021 IRP, nominal electricity prices were assumed to climb to about
13 cents per kWh by 2043, and real electricity prices (inflation adjusted) were expected to
decline over the forecast period at an average rate of 1.2% annually.
The electricity price forecast used to prepare the sales and load forecast in the 2023 IRP
reflected the additional plant investment and variable costs of integrating the resources
identified in the 2021 IRP preferred portfolio. When compared to the electricity price
forecast used to prepare the 2021 IRP sales and load forecast, the electricity price forecast
used to prepare the 2023 IRP sales and load forecast yields lower future prices. The retail
prices are mostly lower throughout the planning period which can impact the sales forecast,
a consequence of the inverse relationship between electricity prices and electricity demand.

Figure 20. Forecast residential electricity prices (cents per kWh)
0
2
4
6
8
10
12
14
16
1987 1992 1997 2002 2007 2012 2017 2022 2027 2032 2037 2042
Nominal Real Nominal - 2023 IRP Real - 2023 IRP
Additional Considerations
Page 40 2023 Integrated Resource Plan—Appendix A
Electricity prices for Idaho Power customers increased significantly in 2001 and 2002, a direct
result of the western United States energy crisis of 2000 and 2001. Prior to 2001, Idaho Power’s
electricity prices were historically quite stable. From 1990 to 2000, nominal electricity prices
rose only 8% overall, an annual average compound growth rate of 0.8% annually. In contrast,
from 2000 to 2010, nominal electricity prices rose 63% overall, an annual average compound
growth rate of 4.2% annually. More recently, over the period 2010 to 2020, nominal electricity
prices rose 23% overall, an annual average compound growth rate of 1.8% annually.
Figure 21 illustrates the average natural gas price paid by Intermountain Gas Company’s
residential customers over the historical period 1987 to 2021 and forecast prices from 2024
to 2043. Nominal natural gas prices are expected to rise throughout the forecast period,
growing at an average rate of 0.3% per year. Real natural gas prices (adjusted for inflation)
are expected to decrease over the same period at an average rate of 1.7% annually.

Figure 21. Forecast residential natural gas prices (dollars per therm)
One consideration in determining the operating costs of space heating and water heating is
fuel cost. If future natural gas price increases outpace electricity price increases, heating with
electricity would become more advantageous when compared to that of natural gas.
S&P Global Platts provides the forecasts of long-term changes in nominal natural gas prices.
In the 2023 IRP price forecast, the long-term direction in real electricity prices and real natural
gas prices (adjusted for inflation) is downward.
Additional Considerations
2023 Integrated Resource Plan—Appendix A Page 41
Other Considerations
Since the residential, commercial, irrigation, and industrial sales forecasts provide a forecast of
sales as billed, it is necessary to adjust these billed sales to the proper time frame to reflect the
required generation needed in each calendar month. To determine calendar-month sales from
billed sales, the billed sales must first be converted from billed periods to calendar months to
synchronize them with the period in which load is generated. The calendar-month sales are
then converted to calendar-month average load by adding losses and dividing by the number of
hours in each month.
Loss factors are determined by Idaho Power’s Transmission Planning department. The annual
average energy loss coefficients are multiplied by the calendar-month load, yielding the system
load, including losses. The most current system loss study was completed in 2023.
Hourly Load Forecast
As a result of stakeholder feedback and comments filed in the 2017 and 2019 IRPs, Idaho Power
has leveraged several years of advanced metering infrastructure (AMI) data in its hourly load
forecasting methodology. The use of AMI data expanded its footprints at Idaho Power and is
utilized to inform an hourly load forecast that conforms with forecast methods mentioned
throughout this document. It is important to note the monthly modeling mentioned drives the
forecast used in the IRP. The hourly load forecast methodology described below simply
allocates the monthly model regressions to each hour of the year.
Hourly Load Forecast Methodology
The company believes it is prudent to maintain the integrity of the historic long-term
forecasting methodologies. The company concluded in 2021 that the hourly forecast should use
a neural network. A neural network utilizes the stability of monthly sales data to calibrate and
ground the hourly data via monthly peak regressions. This neural network was developed under
counsel with Itron Forecasting. The company ensured this methodology employs control and
flexibility on the neural network while remaining highly transparent.
Technical Specifications of Hourly Load Forecasting
To begin the process, the company engaged in consultation with Itron Forecasting. Together,
Idaho Power and Itron designed the framework to introduce concepts of a neural network
model that utilized two non-linear nodes and was hinged on currently accepted load
forecasting processes. The result of this methodology brought statistical confidence of hourly
load modeling to the company while still conforming to the stability of the legacy methodology
of monthly sales forecasting.
An industry approach to weather responsiveness would be to utilize a linear model based on an
HDD or CDD level of 65 degrees Fahrenheit (°F) (actual point may differ by local utility weather
Additional Considerations
Page 42 2023 Integrated Resource Plan—Appendix A
characteristics). Utilities will also often use splines in regression equations to define the
weather function to reflect the change of slope as the average daily temperature moves away
from the 65°F mark and there is less weather responsiveness. This methodology works very
well by minimizing the potential impact of overfitting. Building on this framework, Idaho Power
uses a non-linear approach, wherein the derivative or local slope of a curve is calculated at each
instance along the weather responsiveness curve. This responsiveness is captured in the neural
network.
The neural network design adopted by Idaho Power outputs a single series of hourly energy
with only one hidden layer that contains two nodes (H1 and H2) representing the heating and
cooling effects along the sales curve. Each of the H1 and H2 nodes uses a logistic activation
function with a linear function applied to the output layer, where impacts of the calendar
(weekend, weekday, holidays, etc.) are captured.
A distinct model is developed for each hour of the year to capture the full spectrum of
temperature responsiveness. For each non-linear hourly model, an instantaneous derivative
value is calculated along the curve to obtain the relationship of energy sales to temperature.
A key initiative for Idaho Power when using a neural network framework is controllability of
calculations and reducing risk of overfitting of the tails of the distribution. This is achieved by
capturing the derivative value and using it in the hourly forecast using 5-degree gradation bins.
Further, by releasing the slopes in this fashion, it creates unique weighting schemes by hour
and facilitates the construction of lagged weather impact, weekends, and holidays. The result of
these hourly models is a transparent set of weather response functions.
At this point, a typical meteorological year is developed using a rolling 30 years of weather
history within the Idaho Power service territory. The company then uses an algorithm to rank
and average the daily temperature within a month from hottest to coldest, averaging the daily
temperature for each rank across years. The result is an appropriate representation of severe,
moderate, and mild daily temperatures for each month. The company uses the ranked and
averaged typical weather by month and employs a transformation algorithm to reorder days
based on a typical weather pattern. Finally, a rotation algorithm is used to ensure the values
over the forecast periods occur on the same day of the week throughout the forecast period,
removing the year-to-year variation in the hourly load shape based on where it lands on the
calendar of the given forecast year.
Hourly System Load Forecast Design
The output from the neural network is joined with the abovementioned typical meteorological
year to develop a near final hourly forecast. An important aspect of the design was for the
company to preserve the monthly sales and monthly peak forecast that has been used
historically. The newly developed methodology leverages a more statistically confident
Additional Considerations
2023 Integrated Resource Plan—Appendix A Page 43
approach for allocated sales by hour within the month. To maintain conformance with the
historical methodology, the company applies a calibration algorithm to the hourly forecast to
both the monthly peak and energy sales within a month as produced by the legacy linear forms
the company operates. The output of hourly sales and subsequent monthly peaks, as defined
by the above-mentioned models, are adjusted such that the duration curve receives
minimal adjustment during or around the peak hour, and any required adjustment grows
larger as it moves out along the duration curve. This minimizes potential impacts of creating
large hour-to-hour swings.
The above process can be repeated for each major customer class to produce estimated
contributions to system peak by customer class as shown in Figure 22.

*Total includes impact from losses
Figure 22. Class contribution to system peak
Contract Off-System Load
Page 44 2023 Integrated Resource Plan—Appendix A
CONTRACT OFF-SYSTEM LOAD
The contract off-system category represents long-term contracts to supply firm energy to off
system customers. Long-term contracts are contracts effective during the forecast period
lasting more than one year. Currently, there are no long-term contracts.
The historical consumption for the contract off-system load category was considerable in
the early 1990s; however, after 1995, off-system loads declined through 2005. As intended,
the off-system contracts and their corresponding energy requirements expired as Idaho
Power’s surplus energy diminished due to retail load growth. In the future, Idaho Power may
enter long-term contracts to supply firm energy to off-system customers if surplus energy
is available.
Appendix A1
2023 Integrated Resource Plan—Appendix A Page 45
Appendix A1. Historical and Projected Sales and Load
Company System Load (excluding Astaris)
Historical Company System Sales and Load, 1982–2022 (weather adjusted)
Year
Billed Sales
(thousands of MWh) Percent Change Average Load (aMW)
1982 7,820 954
1983 8,045 2.9% 978
1984 8,107 0.8% 983
1985 8,256 1.8% 1,003
1986 8,359 1.2% 1,016
1987 8,499 1.7% 1,033
1988 8,834 3.9% 1,071
1989 9,201 4.2% 1,117
1990 9,559 3.9% 1,160
1991 9,741 1.9% 1,182
1992 9,963 2.3% 1,206
1993 10,274 3.1% 1,250
1994 10,663 3.8% 1,295
1995 11,137 4.4% 1,351
1996 11,467 3.0% 1,389
1997 11,755 2.5% 1,427
1998 12,240 4.1% 1,483
1999 12,548 2.5% 1,522
2000 12,928 3.0% 1,566
2001 13,062 1.0% 1,580
2002 12,791 -2.1%1,552
2003 13,140 2.7%1,592
2004 13,344 1.5%1,616
2005 13,707 2.7%1,667
2006 13,995 2.1%1,697
2007 14,389 2.8%1,745
2008 14,464 0.5%1,746
2009 13,986 -3.3%1,697
2010 13,835 -1.1%1,677
2011 13,860 0.2%1,684
2012 14,068 1.5%1,706
2013 14,076 0.1%1,720
2014 14,268 1.4%1,733
Appendix A1
Page 46 2023 Integrated Resource Plan—Appendix A
Year
Billed Sales
(thousands of MWh) Percent Change Average Load (aMW)
2015 14,134 -0.9% 1,721
2016 14,296 1.1% 1,740
2017 14,408 0.8% 1,754
2018 14,579 1.2% 1,777
2019 14,729 1.0% 1,798
2020 14,884 1.1% 1,815
2021 15,156 1.8% 1,858
2022 15,351 1.3% 1,877

Company System Load
Projected Company System Sales and Load, 2024–2043

Year
Billed Sales
(thousands of MWh)

Percent Change

Average Load (aMW)
2024 15,958 1.9% 2,024
2025 16,577 3.9% 2,141
2026 17,544 5.8% 2,360
2027 18,464 5.2% 2,495
2028 19,060 3.2% 2,561
2029 19,514 2.4% 2,622
2030 20,117 3.1% 2,695
2031 20,461 1.7% 2,737
2032 20,671 1.0% 2,755
2033 20,840 0.8% 2,784
2034 21,026 0.9% 2,807
2035 21,186 0.8% 2,827
2036 21,359 0.8% 2,841
2037 21,515 0.7% 2,868
2038 21,690 0.8% 2,890
2039 21,863 0.8% 2,912
2040 22,032 0.8% 2,926
2041 22,251 1.0% 2,960
2042 22,407 0.7% 2,980
2043 22,561 0.7% 2,999

Appendix A1
2023 Integrated Resource Plan—Appendix A Page 47
Residential Load
Historical Residential Sales and Load, 1982–2022 (weather adjusted)
Year
Average
Customers
Percent
Change
kWh per
Customer
Billed Sales
(thousands of MWh)
Percent
Change
Average
Load (aMW)
1982 216,696 13,508 2,927 337
1983 219,849 1.5% 14,332 3,151 7.6% 358
1984 222,695 1.3% 14,005 3,119 -1.0%355
1985 225,185 1.1% 13,821 3,112 -0.2%355
1986 227,081 0.8% 14,073 3,196 2.7%365
1987 228,868 0.8% 13,981 3,200 0.1%365
1988 230,771 0.8% 14,251 3,289 2.8%374
1989 233,370 1.1% 14,209 3,316 0.8%379
1990 238,117 2.0% 14,271 3,398 2.5%387
1991 243,207 2.1% 14,379 3,497 2.9%400
1992 249,767 2.7% 14,102 3,522 0.7%400
1993 258,271 3.4% 14,019 3,621 2.8%415
1994 267,854 3.7% 13,992 3,748 3.5%428
1995 277,131 3.5% 14,011 3,883 3.6%443
1996 286,227 3.3% 13,774 3,943 1.5%450
1997 294,674 3.0% 13,687 4,033 2.3%460
1998 303,300 2.9% 13,778 4,179 3.6%477
1999 312,901 3.2% 13,633 4,266 2.1%487
2000 322,402 3.0% 13,411 4,324 1.4%492
2001 331,009 2.7% 13,168 4,359 0.8%495
2002 339,764 2.6% 12,687 4,311 -1.1%493
2003 349,219 2.8% 12,820 4,477 3.9%509
2004 360,462 3.2% 12,725 4,587 2.5%523
2005 373,602 3.6% 12,715 4,750 3.6%544
2006 387,707 3.8% 12,983 5,033 6.0%574
2007 397,286 2.5% 13,036 5,179 2.9%590
2008 402,520 1.3% 12,905 5,194 0.3%591
2009 405,144 0.7% 12,730 5,157 -0.7%587
2010 407,551 0.6% 12,463 5,079 -1.5%579
2011 409,786 0.5% 12,405 5,083 0.1%579
2012 413,610 0.9% 12,390 5,124 0.8%580
2013 418,892 1.3% 12,043 5,045 -1.6%577
2014 425,036 1.5% 11,965 5,086 0.8%575
2015 432,275 1.7% 11,688 5,053 -0.7%576
2016 440,362 1.9% 11,627 5,120 1.3%583
Appendix A1
Page 48 2023 Integrated Resource Plan—Appendix A
Year
Average
Customers
Percent
Change
kWh per
Customer
Billed Sales
(thousands of MWh)
Percent
Change
Average
Load (aMW)
2017 448,800 1.9% 11,546 5,182 1.2% 590
2018 459,128 2.3% 11,361 5,216 0.7% 594
2019 471,298 2.7% 11,239 5,297 1.5% 607
2020 484,433 2.8% 11,401 5,523 4.3% 633
2021 499,216 3.1% 11,257 5,620 1.8% 642
2022 512,803 2.7% 11,151 5,718 1.8% 643
Projected Residential Sales and Load, 2024–2043
Year
Average
Customers
Percent
Change
kWh per
Customer
Billed Sales
(thousands of MWh)
Percent
Change
Average
Load (aMW)
2024 533,126 2.2% 10,793 5,754 1.1% 678
2025 543,708 2.0% 10,690 5,812 1.0% 687
2026 554,453 2.0% 10,563 5,857 0.8% 693
2027 565,646 2.0% 10,464 5,919 1.1% 701
2028 577,181 2.0% 10,388 5,996 1.3% 708
2029 588,906 2.0% 10,322 6,079 1.4% 720
2030 600,677 2.0% 10,254 6,159 1.3% 729
2031 612,333 1.9% 10,196 6,243 1.4% 739
2032 623,729 1.9% 10,137 6,323 1.3% 747
2033 634,783 1.8% 10,078 6,398 1.2% 758
2034 645,419 1.7% 10,011 6,461 1.0% 765
2035 655,575 1.6% 9,939 6,516 0.8% 772
2036 665,243 1.5% 9,893 6,581 1.0% 778
2037 674,440 1.4% 9,862 6,651 1.1% 788
2038 683,192 1.3% 9,833 6,718 1.0% 796
2039 691,515 1.2% 9,801 6,778 0.9% 804
2040 699,424 1.1% 9,770 6,833 0.8% 808
2041 706,941 1.1% 9,744 6,888 0.8% 817
2042 714,108 1.0% 9,722 6,943 0.8% 824
2043 720,959 1.0% 9,700 6,993 0.7% 830

Appendix A1
2023 Integrated Resource Plan—Appendix A Page 49

Commercial Load
Historical Commercial Sales and Load, 1982–2022 (weather adjusted)

Year
Average
Customers
Percent
Change
kWh per
Customer
Billed Sales
(thousands of MWh)
Percent
Change
Average
Load (aMW)
1982 30,167 54,137 1,633 186
1983 30,776 2.0% 52,637 1,620 -0.8% 185
1984 31,554 2.5% 53,650 1,693 4.5% 193
1985 32,418 2.7% 54,285 1,760 4.0% 201
1986 33,208 2.4% 54,057 1,795 2.0% 205
1987 33,975 2.3% 53,611 1,821 1.5% 208
1988 34,723 2.2% 54,465 1,891 3.8% 216
1989 35,638 2.6% 55,525 1,979 4.6% 226
1990 36,785 3.2% 55,940 2,058 4.0% 235
1991 37,922 3.1% 56,243 2,133 3.7% 244
1992 39,022 2.9% 56,674 2,212 3.7% 252
1993 40,047 2.6% 58,522 2,344 6.0% 268
1994 41,629 4.0% 58,445 2,433 3.8% 278
1995 43,165 3.7% 58,918 2,543 4.5% 292
1996 44,995 4.2% 62,292 2,803 10.2% 320
1997 46,819 4.1% 62,380 2,921 4.2% 333
1998 48,404 3.4% 62,833 3,041 4.1% 348
1999 49,430 2.1% 64,354 3,181 4.6% 363
2000 50,117 1.4% 66,141 3,315 4.2% 379
2001 51,501 2.8% 67,665 3,485 5.1% 397
2002 52,915 2.7% 65,004 3,440 -1.3% 393
2003 54,194 2.4% 64,459 3,493 1.6% 398
2004 55,577 2.6% 64,160 3,566 2.1% 407
2005 57,145 2.8% 63,620 3,636 2.0% 415
2006 59,050 3.3% 63,622 3,757 3.3% 429
2007 61,640 4.4% 63,448 3,911 4.1% 447
2008 63,492 3.0% 62,295 3,955 1.1% 449
2009 64,151 1.0% 59,859 3,840 -2.9% 439
2010 64,421 0.4% 58,905 3,795 -1.2% 432
2011 64,921 0.8% 58,602 3,805 0.3% 434
2012 65,599 1.0% 59,032 3,872 1.8% 440
2013 66,357 1.2% 58,682 3,894 0.6% 446
2014 67,113 1.1% 59,057 3,963 1.8% 451
2015 68,000 1.3% 58,722 3,993 0.7% 456
Appendix A1
Page 50 2023 Integrated Resource Plan—Appendix A

Year
Average
Customers
Percent
Change
kWh per
Customer
Billed Sales
(thousands of MWh)
Percent
Change
Average
Load (aMW)
2016 68,883 1.3% 58,190 4,008 0.4% 457
2017 69,850 1.4% 57,964 4,049 1.0% 461
2018 71,104 1.8% 57,839 4,113 1.6% 470
2019 72,332 1.7% 57,034 4,125 0.3% 471
2020 73,702 1.9% 54,610 4,025 -2.4% 458
2021 75,282 2.1% 54,826 4,127 2.5% 471
2022 76,672 1.8% 54,983 4,216 2.1% 483

Projected Commercial Sales and Load, 2024–2043

Year
Average
Customers
Percent
Change
kWh per
Customer
Billed Sales
(thousands of MWh)
Percent
Change
Average
Load (aMW)
2024 78,882 1.4% 54,802 4,323 1.3% 500
2025 79,984 1.4% 54,353 4,347 0.6% 504
2026 81,175 1.5% 54,083 4,390 1.0% 509
2027 82,419 1.5% 53,521 4,411 0.5% 512
2028 83,738 1.6% 53,094 4,446 0.8% 515
2029 85,121 1.7% 52,569 4,475 0.6% 520
2030 86,551 1.7% 52,271 4,524 1.1% 525
2031 88,012 1.7% 51,706 4,551 0.6% 529
2032 89,487 1.7% 51,348 4,595 1.0% 532
2033 90,965 1.7% 50,853 4,626 0.7% 537
2034 92,433 1.6% 50,520 4,670 0.9% 543
2035 93,885 1.6% 50,244 4,717 1.0% 548
2036 95,314 1.5% 49,820 4,749 0.7% 550
2037 96,718 1.5% 49,493 4,787 0.8% 556
2038 98,098 1.4% 49,253 4,832 0.9% 562
2039 99,452 1.4% 49,088 4,882 1.0% 567
2040 100,781 1.3% 48,855 4,924 0.9% 571
2041 102,086 1.3% 48,658 4,967 0.9% 577
2042 103,368 1.3% 48,409 5,004 0.7% 582
2043 104,630 1.2% 48,177 5,041 0.7% 586

Appendix A1
2023 Integrated Resource Plan—Appendix A Page 51
Irrigation Load
Historical Irrigation Sales and Load, 1982–2022 (weather adjusted)

Year
Maximum
Active
Customers
Percent
Change
kWh per
Customer
Billed Sales
(thousands of MWh)
Percent
Change
Average
Load (aMW)
1982 11,312 152,949 1,730 198
1983 11,133 -1.6% 148,748 1,656 -4.3% 190
1984 11,375 2.2% 136,037 1,547 -6.6% 175
1985 11,576 1.8% 134,360 1,555 0.5% 176
1986 11,308 -2.3% 135,238 1,529 -1.7% 175
1987 11,254 -0.5% 133,394 1,501 -1.8% 172
1988 11,378 1.1% 138,651 1,578 5.1% 180
1989 11,957 5.1% 137,247 1,641 4.0% 187
1990 12,340 3.2% 147,161 1,816 10.7% 207
1991 12,484 1.2% 138,688 1,731 -4.7% 197
1992 12,809 2.6% 138,914 1,779 2.8% 203
1993 13,078 2.1% 135,086 1,767 -0.7% 203
1994 13,559 3.7% 132,262 1,793 1.5% 204
1995 13,679 0.9% 132,474 1,812 1.0% 207
1996 14,074 2.9% 127,844 1,799 -0.7% 205
1997 14,383 2.2% 118,942 1,711 -4.9% 195
1998 14,695 2.2% 119,947 1,763 3.0% 201
1999 14,912 1.5% 122,035 1,820 3.2% 207
2000 15,253 2.3% 128,235 1,956 7.5% 222
2001 15,522 1.8% 116,730 1,812 -7.4% 207
2002 15,840 2.0% 110,152 1,745 -3.7% 199
2003 16,020 1.1% 113,351 1,816 4.1% 208
2004 16,297 1.7% 108,374 1,766 -2.7% 200
2005 16,936 3.9% 106,011 1,795 1.7% 206
2006 17,062 0.7% 99,145 1,692 -5.8% 194
2007 17,001 -0.4% 105,373 1,791 5.9% 205
2008 17,428 2.5% 108,565 1,892 5.6% 214
2009 17,708 1.6% 101,586 1,799 -4.9% 205
2010 17,846 0.8% 102,150 1,823 1.3% 207
2011 18,292 2.5% 100,382 1,836 0.7% 210
2012 18,675 2.1% 103,772 1,938 5.5% 221
2013 19,017 1.8% 102,889 1,957 1.0% 223
2014 19,328 1.6% 104,262 2,015 3.0% 230
2015 19,756 2.2% 95,494 1,887 -6.4% 215
Appendix A1
Page 52 2023 Integrated Resource Plan—Appendix A

Year
Maximum
Active
Customers
Percent
Change
kWh per
Customer
Billed Sales
(thousands of MWh)
Percent
Change
Average
Load (aMW)
2016 20,042 1.4% 96,629 1,937 2.7% 221
2017 20,246 1.0% 90,202 1,826 -5.7% 210
2018 20,459 1.1% 92,540 1,893 3.7% 216
2019 20,566 0.5% 91,922 1,890 -0.1% 217
2020 20,804 1.2% 94,667 1,969 4.2% 224
2021 21,066 1.3% 91,979 1,938 -1.6% 229
2022 21,324 1.2% 89,590 1,910 -1.4% 227

Projected Irrigation Sales and Load, 2024–2043

Year
Maximum
Active
Customers
Percent
Change
kWh per
Customer
Billed Sales
(thousands of MWh)
Percent
Change
Average
Load (aMW)
2024 21,747 1.2% 90,344 1,965 1.8% 240
2025 21,997 1.1% 90,140 1,983 0.9% 243
2026 22,249 1.1% 89,185 1,984 0.1% 243
2027 22,498 1.1% 88,598 1,993 0.5% 244
2028 22,750 1.1% 87,821 1,998 0.2% 244
2029 22,999 1.1% 87,110 2,003 0.3% 246
2030 23,250 1.1% 86,619 2,014 0.5% 247
2031 23,502 1.1% 86,151 2,025 0.5% 248
2032 23,751 1.1% 85,746 2,037 0.6% 249
2033 24,002 1.1% 85,405 2,050 0.7% 251
2034 24,253 1.0% 85,104 2,064 0.7% 252
2035 24,502 1.0% 84,841 2,079 0.7% 254
2036 24,757 1.0% 84,585 2,094 0.7% 255
2037 25,007 1.0% 84,363 2,110 0.7% 258
2038 25,254 1.0% 84,148 2,125 0.7% 259
2039 25,505 1.0% 83,936 2,141 0.7% 261
2040 25,754 1.0% 83,732 2,156 0.7% 262
2041 26,006 1.0% 83,524 2,172 0.7% 265
2042 26,257 1.0% 83,318 2,188 0.7% 267
2043 26,508 1.0% 83,095 2,203 0.7% 268

Appendix A1
2023 Integrated Resource Plan—Appendix A Page 53
Industrial Load
Historical Industrial Sales and Load, 1982–2022 (not weather adjusted)

Year
Average
Customers
Percent
Change
kWh per
Customer
Billed Sales
(thousands of MWh)
Percent
Change
Average
Load (aMW)
1982 122 9,504,283 1,162 133
1983 122 -0.3% 9,797,522 1,194 2.7% 138
1984 124 1.5% 10,369,789 1,282 7.4% 147
1985 125 1.2% 10,844,888 1,357 5.9% 155
1986 129 2.7% 10,550,145 1,357 -0.1% 155
1987 134 4.1% 11,006,455 1,474 8.7% 169
1988 133 -1.0% 11,660,183 1,546 4.9% 177
1989 132 -0.6% 12,091,482 1,594 3.1% 183
1990 132 0.2% 12,584,200 1,662 4.3% 191
1991 135 2.5% 12,699,665 1,719 3.4% 196
1992 140 3.4% 12,650,945 1,770 3.0% 203
1993 141 0.5% 13,179,585 1,854 4.7% 212
1994 143 1.7% 13,616,608 1,948 5.1% 223
1995 120 -15.9% 16,793,437 2,021 3.7% 230
1996 103 -14.4% 18,774,093 1,934 -4.3% 221
1997 106 2.7% 19,309,504 2,042 5.6% 235
1998 111 4.6% 19,378,734 2,145 5.0% 244
1999 108 -2.3% 19,985,029 2,160 0.7% 247
2000 107 -0.8% 20,433,299 2,191 1.5% 250
2001 111 3.5% 20,618,361 2,289 4.4% 260
2002 111 -0.1% 19,441,876 2,156 -5.8% 246
2003 112 1.0% 19,950,866 2,234 3.6% 255
2004 117 4.3% 19,417,310 2,269 1.5% 259
2005 126 7.9% 18,645,220 2,351 3.6% 270
2006 127 1.0% 18,255,385 2,325 -1.1% 265
2007 123 -3.6% 19,275,551 2,366 1.8% 270
2008 119 -3.1% 19,412,391 2,308 -2.4% 261
2009 124 4.0% 17,987,570 2,224 -3.6% 254
2010 121 -2.0% 18,404,875 2,232 0.3% 254
2011 120 -1.1% 18,597,050 2,230 -0.1% 254
2012 115 -4.2% 19,757,921 2,271 1.8% 258
2013 114 -0.7% 20,281,837 2,314 1.9% 265
2014 113 -0.7% 20,863,653 2,363 2.1% 271
2015 116 2.8% 20,271,082 2,360 -0.1% 269
2016 118 1.4% 19,993,955 2,361 0.0% 270
Appendix A1
Page 54 2023 Integrated Resource Plan—Appendix A

Year
Average
Customers
Percent
Change
kWh per
Customer
Billed Sales
(thousands of MWh)
Percent
Change
Average
Load (aMW)
2017 117 -1.1% 20,996,425 2,453 3.9% 280
2018 115 -1.6% 21,274,929 2,447 -0.3% 280
2019 124 8.0% 20,288,866 2,521 3.0% 288
2020 124 -0.3% 19,912,671 2,466 -2.2% 283
2021 124 0.0% 20,671,453 2,560 3.8% 294
2022 123 -0.8% 20,844,705 2,560 0.0% 294

Projected Industrial Sales and Load, 2024–2043

Year
Average
Customers
Percent
Change
kWh per
Customer
Billed Sales
(thousands of MWh)
Percent
Change
Average
Load (aMW)
2024 123 0.8% 22,202,622 2,731 2.5% 311
2025 124 0.8% 22,422,106 2,780 1.8% 318
2026 124 0.0% 22,646,315 2,808 1.0% 321
2027 125 0.8% 22,681,295 2,835 1.0% 324
2028 126 0.8% 22,710,399 2,862 0.9% 326
2029 128 1.6% 22,584,636 2,891 1.0% 330
2030 130 1.6% 22,479,994 2,922 1.1% 334
2031 130 0.0% 22,745,901 2,957 1.2% 338
2032 131 0.8% 22,833,038 2,991 1.2% 341
2033 131 0.0% 23,126,588 3,030 1.3% 346
2034 131 0.0% 23,445,984 3,071 1.4% 351
2035 132 0.8% 23,592,069 3,114 1.4% 356
2036 133 0.8% 23,742,442 3,158 1.4% 360
2037 134 0.8% 23,895,073 3,202 1.4% 366
2038 135 0.7% 24,076,426 3,250 1.5% 372
2039 135 0.0% 24,447,379 3,300 1.5% 377
2040 136 0.7% 24,636,813 3,351 1.5% 382
2041 138 1.5% 24,640,741 3,400 1.5% 389
2042 138 0.0% 25,003,264 3,450 1.5% 394
2043 139 0.7% 25,188,594 3,501 1.5% 400

Appendix A1
2023 Integrated Resource Plan—Appendix A Page 55
Additional Firm Sales and Load
Historical Additional Firm Sales and Load, 1982–2022
Billed Sales
(thousands of MWh) Year Percent Change Average Load (aMW)
1982 367 39
1983 425 15.7% 45
1984 466 9.7% 50
1985 471 1.1% 50
1986 482 2.4% 51
1987 502 4.2% 54
1988 530 5.6% 57
1989 671 26.5% 73
1990 625 -6.9% 67
1991 661 5.8% 71
1992 680 2.9% 72
1993 689 1.3% 73
1994 740 7.5% 79
1995 878 18.6% 95
1996 988 12.6% 107
1997 1,048 6.0% 114
1998 1,113 6.2% 121
1999 1,121 0.8% 122
2000 1,142 1.9% 124
2001 1,118 -2.1% 122
2002 1,139 1.9% 124
2003 1,120 -1.7% 122
2004 1,156 3.3% 126
2005 1,175 1.6% 128
2006 1,189 1.2% 129
2007 1,141 -4.0% 124
2008 1,114 -2.4% 120
2009 965 -13.4% 104
2010 907 -6.0% 97
2011 906 0.0% 99
2012 862 -4.8% 98
2013 867 0.5% 99
2014 841 -2.9% 96
2015 842 0.1% 96
2016 870 3.3% 99
Appendix A1
Page 56 2023 Integrated Resource Plan—Appendix A
Billed Sales
(thousands of MWh) Year Percent Change Average Load (aMW)
2017 897 3.1% 102
2018 910 1.4% 104
2019 895 -1.7%102
2020 900 0.6%103
2021 912 1.2%104
2022 947 3.8%111
*Includes Micron Technology, Simplot Fertilizer, INL, Hoku Materials, City of Weiser, and Raft River Rural Electric
Projected Additional Firm Sales and Load, 2024–2043
Year
Billed Sales
(thousands of MWh) Percent Change Average Load (aMW)
2024 1,186 7.6% 135
2025 1,972 66.4% 225
2026 3,702 87.7% 423
2027 4,717 27.4% 539
2028 5,175 9.7% 589
2029 5,478 5.9% 625
2030 5,910 7.9% 675
2031 6,097 3.2% 696
2032 6,141 0.7% 699
2033 6,149 0.1% 702
2034 6,171 0.4% 704
2035 6,172 0.0% 705
2036 6,193 0.3% 705
2037 6,177 -0.3%705
2038 6,176 0.0%705
2039 6,174 0.0%705
2040 6,184 0.2%704
2041 6,234 0.8%712
2042 6,234 0.0%712
2043 6,234 0.0%712
A P P E N D I X B : A P P E N D I X B : D S M A N N U A L R E P O R TD S M A N N U A L R E P O R T
IRP
INTEGRATED RESOURCE PLAN
September 2023
Printed on recycled paper
SAFE HARBOR STATEMENT
This document may contain forward-looking statements,
and it is important to note that the future results could
differ materially from those discussed. A full discussion
of the factors that could cause future results to differ
materially can be found in Idaho Power’s fi lings with the
Securities and Exchange Commission.
Table of Contents
Demand-Side Management 2022 Annual Report Page i
TABLE OF CONTENTS
Executive Summary ......................................................................................................................... 1
Introduction .................................................................................................................................... 5
Programs and Offerings ............................................................................................................ 5
Funding Sources ........................................................................................................................ 6
Cost-Effectiveness Goals ........................................................................................................... 7
DSM Annual Report Structure .................................................................................................. 8
2022 DSM Program Performance ................................................................................................. 11
Energy Savings and Program Expenses ................................................................................... 11
Efficiency ........................................................................................................................... 11
Demand Response ............................................................................................................ 12
DSM Funding and Expenditures .............................................................................................. 14
Customer Education ................................................................................................................ 16
Marketing ................................................................................................................................ 18
Social Media ...................................................................................................................... 18
Website ............................................................................................................................. 19
Public Relations ................................................................................................................. 19
Customer Relationship Survey ................................................................................................ 20
Customer Satisfaction Surveys................................................................................................ 20
Evaluations .............................................................................................................................. 20
Cost-Effectiveness Results ...................................................................................................... 21
2022 DSM Program Activity .......................................................................................................... 23
Residential Sector Overview ................................................................................................... 23
Residential DSM Programs................................................................................................ 24
Marketing .......................................................................................................................... 25
Customer Satisfaction ....................................................................................................... 30
Field Staff Activities ........................................................................................................... 30
A/C Cool Credit .................................................................................................................. 32
Easy Savings: Low-Income Energy Efficiency Education ................................................... 37
Educational Distributions .................................................................................................. 40
Energy Efficient Lighting ................................................................................................... 47
Table of Contents
Page ii Demand-Side Management 2022 Annual Report
Energy House Calls ............................................................................................................ 52
Heating & Cooling Efficiency Program .............................................................................. 57
Home Energy Audit ........................................................................................................... 68
Home Energy Report Program .......................................................................................... 71
Multifamily Energy Savings Program ................................................................................ 77
Oregon Residential Weatherization ................................................................................. 80
Rebate Advantage ............................................................................................................. 82
Residential New Construction Program ............................................................................ 85
Shade Tree Project ............................................................................................................ 88
Weatherization Assistance for Qualified Customers ........................................................ 94
Weatherization Solutions for Eligible Customers ........................................................... 103
Commercial & Industrial Sector Overview ............................................................................ 107
Commercial and Industrial DSM Programs ..................................................................... 107
Marketing ........................................................................................................................ 108
Customer Satisfaction ..................................................................................................... 111
Training and Education ................................................................................................... 111
Field Staff Activities ......................................................................................................... 113
Commercial and Industrial Energy Efficiency Program .................................................. 114
Commercial Energy-Saving Kits....................................................................................... 128
Flex Peak Program .......................................................................................................... 133
Oregon Commercial Audits ............................................................................................. 138
Small Business Direct Install ........................................................................................... 140
Irrigation Sector Overview .................................................................................................... 143
Irrigation DSM Programs ................................................................................................ 144
Marketing ........................................................................................................................ 144
Customer Satisfaction ..................................................................................................... 145
Training and Education ................................................................................................... 145
Field Staff Activities ......................................................................................................... 145
Irrigation Efficiency Rewards .......................................................................................... 147
Irrigation Peak Rewards .................................................................................................. 151
Other Programs and Activities .............................................................................................. 157
Table of Contents
Demand-Side Management 2022 Annual Report Page iii
Idaho Power’s Internal Energy Efficiency Commitment ................................................. 157
Local Energy Efficiency Funds ......................................................................................... 157
Energy Efficiency Advisory Group (EEAG) ....................................................................... 157
Market Transformation................................................................................................... 158
Regional Technical Forum ............................................................................................... 164
Residential Energy Efficiency Education Initiative .......................................................... 165
Distributed Energy Resources ......................................................................................... 170
University of Idaho Integrated Design Lab ..................................................................... 170
Conclusions ................................................................................................................................. 175
List of Acronyms .......................................................................................................................... 177
Appendices .................................................................................................................................. 183

LIST OF TABLES
Table 1. DSM programs by sector, operational type, and location, 2022 .................................. 6
Table 2. DSM programs by sector summary and energy usage/savings/demand
reduction, 2022 ........................................................................................................... 14
Table 3. 2022 funding source and energy savings .................................................................... 14
Table 4. 2022 DSM program expenditures by category ........................................................... 15
Table 5. 2022 DSM program incentive totals by program type and sector ............................. 16
Table 6. Cost-effectiveness summary by energy efficiency program ...................................... 21
Table 7. Residential sector program summary, 2022 ............................................................... 23
Table 8. A/C Cool Credit demand response event details ........................................................ 33
Table 9. Measures, conditions, and incentives—existing homes ............................................ 58
Table 10. Measures, conditions, and incentives—new homes .................................................. 59
Table 11. Quantity of H&CE Program incentives in 2022 ........................................................... 60
Table 12. Number and percentage of audited homes per heating fuel type............................. 69
Table 13. WAQC activities and Idaho Power expenditures by agency and county in 2022 ....... 96
Table 14. WAQC base funding and funds made available in 2022 ............................................. 97
Table 15. WAQC summary of measures installed in 2022 ......................................................... 98
Table 16. Commercial/Industrial sector program summary, 2022 .......................................... 107
Table of Contents
Page iv Demand-Side Management 2022 Annual Report
Table 17. Custom Projects annual energy savings by primary option measure, 2022 ............ 117
Table 18. Number of kits distributed per state and associated energy savings ...................... 129
Table 19. Flex Peak Program demand response event details ................................................. 134
Table 20. Irrigation sector program summary, 2022 ................................................................ 144
Table 21. Irrigation Peak Rewards demand response event details ........................................ 153
Table 22. Irrigation Peak Rewards program MW load reduction for events ........................... 156

LIST OF FIGURES
Figure 1. Example graphic from the 2022 Energy Efficiency Guide ............................................. 2
Figure 2. Idaho Power service area map ..................................................................................... 5
Figure 3. DSM expense history by program type, 2002–2022 (millions [$]) ............................... 7
Figure 4. Annual energy savings and energy efficiency program expenses, 2002–2022
(MWh and millions [$]) ............................................................................................... 12
Figure 5. Peak demand reduction capacity and demand response expenses, 2004–
2022 (MW and millions [$]) ........................................................................................ 13
Figure 6. 2022 DSM program expenditures by category ........................................................... 15
Figure 7. Percent of DSM program incentive expenses by program type and sector,
2022 ............................................................................................................................ 16
Figure 8. Direct-mail postcard to Idaho residential customers for Easy Savings ...................... 39
Figure 9. Student Energy Efficiency Kit ...................................................................................... 41
Figure 10. Welcome Kit ................................................................................................................ 42
Figure 11. Nightlights as giveaways ............................................................................................. 43
Figure 12. Lighting shelf store display ......................................................................................... 48
Figure 13. Home Energy Report tip ............................................................................................. 49
Figure 14. Lighting post ................................................................................................................ 49
Figure 15. Participation in the Energy House Calls program, 2012–2022 ................................... 53
Figure 16. Participation in the Energy House Calls program, by region ...................................... 54
Figure 17. Energy House Calls participation by job type ............................................................. 55
Figure 18. Page 1 of a sample Home Energy Report .................................................................... 73
Figure 19. Shade Tree Project pick-up event ............................................................................... 89
Figure 20. Excerpt from spring direct-mail letter ........................................................................ 90
Table of Contents
Demand-Side Management 2022 Annual Report Page v
Figure 21. Shade Tree Project social media post ......................................................................... 91
Figure 22. Commercial Energy-Saving Kit .................................................................................. 128
Figure 23. Energy Efficiency Kit featuring the Kill A Watt meter ............................................... 166
Figure 24. Summer energy-saving tips ...................................................................................... 168
Figure 25. Energy Awareness Month social media posts .......................................................... 169
Figure 26. Tip Tuesday post ....................................................................................................... 169

LIST OF APPENDICES
Appendix 1. Idaho Rider, Oregon Rider, and NEEA payment amounts (January–
December 2022) ................................................................................................. 185
Appendix 2. 2022 DSM expenses by funding source (dollars) ................................................ 186
Appendix 3. 2022 DSM program activity ................................................................................ 187
Appendix 4. 2022 DSM program activity by state jurisdiction ............................................... 189

Table of Contents
Page vi Demand-Side Management 2022 Annual Report

Executive Summary
Demand-Side Management 2022 Annual Report Page 1
EXECUTIVE SUMMARY
Idaho Power, through its energy efficiency programs, its customer education programs, and its
focus on the customer experience, fully supports energy efficiency and demand response and
encourages its customers to use energy wisely. Idaho Power remains one of the top-ranked
utilities and ranked #3 in the West Midsize Segment of the J.D. Power 2022 Electric Utility
Residential Customer Satisfaction Study.
In 2022, Idaho Power achieved 169,889 megawatt-hours (MWh) or 19.4 average megawatts
(aMW) of incremental energy efficiency savings, including Northwest Energy Efficiency Alliance
(NEEA) estimated energy savings, which exceeded the economic technical achievable potential
included in the 2021 Integrated Resource Plan (IRP) of 139,826 MWh or 16 aMW. The 2022
savings represent enough energy to power approximately 14,900 average homes in Idaho
Power’s service area for one year.
The Commercial and Industrial (C&I) Energy Efficiency Program, which typically provides more
than half of the portfolio savings, returned savings 14,218 MWh higher than in 2021.
Consequently, the 2022 savings of 169,889 MWh, including the estimated savings from NEEA,
increased by 26,968 MWh—a 19% year-over-year increase. The savings from Idaho Power’s
energy efficiency programs alone, excluding NEEA savings, were 145,440 MWh in 2022 and
126,102 MWh in 2021—a 15% year-over-year increase. Overall, 2022 was a less challenging
year than 2021 with regard to energy efficiency program participation due to the easing of
COVID-19 restrictions, but supply chain issues, higher labor and material costs, and the
maturity of the residential lighting market continued to put downward pressure on
program participation.
In 2022, the company’s energy efficiency portfolio was cost-effective from both the utility cost
test (UCT) and the total resource cost (TRC) test perspectives with ratios of 2.02 and 1.43,
respectively. The portfolio was also cost-effective from the participant cost test (PCT) ratio,
which was 2.01.
Energy efficiency and demand response are important aspects of Idaho Power’s resources to
meet system energy needs and are reviewed with each IRP. Idaho Power successfully operated
all three of its demand response programs in 2022. The total demand response capacity from
the company’s programs was calculated to be approximately 312 megawatts (MW) with an
actual max load reduction of 200 MW.
Total expenditures from all funding sources of demand-side management (DSM) activities were
$43 million in 2022—$31.7 million from the Idaho Rider, $10 million from Idaho Power base
rates, and $1.3 million from the Oregon Rider. DSM program funding comes from the Idaho and
Oregon Riders, Idaho Power base rates, and the annual power cost adjustment (PCA).
Executive Summary
Page 2 Demand-Side Management 2022 Annual Report
In addition to the education customers get through participation in specific incentive programs
for energy efficiency, Idaho Power educates customers on energy efficiency in many other
ways. One of these methods is to produce an annual Energy Efficiency Guide with information
on energy efficiency equipment and ways to use energy wisely. The 2022 guide was distributed
in June, primarily as an insert in the Boise Weekly and 24 local newspapers. In 2022,
Idaho Power’s education and outreach energy advisors (EOEA) delivered nearly
670 presentations with energy-savings messages to audiences of all ages.

Figure 1. Example graphic from the 2022 Energy Efficiency Guide
In 2022, the Integrated Design Lab (IDL) conducted 14 technical training lunches. A total of
100 architects, engineers, designers, project managers, and others attended. The IDL also
maintains an Energy Resource Library (ERL) with tools for measuring and monitoring energy use
and provides training on how to use them. The library includes over 900 individual pieces of
equipment; 69 new tools were added in 2022.
Idaho Power continued to provide training to its commercial and industrial customers in 2022,
delivering the equivalent of six full days of technical training to over 150 individuals.
Idaho Power provided three virtual irrigation workshops for the Irrigation Efficiency Rewards
and Irrigation Peak Rewards programs and provided one in-person workshop in Oregon.
In October, program staff attended the first annual Idaho Farm and Ranch Conference in Boise
and hosted a booth.
The company sponsors significant customer educational outreach and awareness activities
promoting energy efficiency, and focuses marketing efforts on saving energy—none of which
are quantified or claimed as part of Idaho Power’s annual DSM savings, but are likely to result in
energy savings that accrue to Idaho Power’s electrical system over time.
Executive Summary
Demand-Side Management 2022 Annual Report Page 3
This Demand-Side Management 2022 Annual Report provides a review of the company’s DSM
activities and finances throughout 2022 and satisfies the reporting requirements set out in
Idaho Public Utilities Commission’s (IPUC) Order Nos. 29026 and 29419. Idaho Power will
provide a copy of the report to the Public Utility Commission of Oregon (OPUC) under
Oregon Docket UM 1710.
Executive Summary
Page 4 Demand-Side Management 2022 Annual Report

Introduction
Demand-Side Management 2022 Annual Report Page 5
INTRODUCTION
Idaho Power has been locally operated since 1916 and serves more than 610,000 customers
throughout a 24,000-square-mile area in southern Idaho and eastern Oregon. The company
achieves energy and demand savings objectives in both its Idaho and Oregon service areas
through the careful management of current programs, the offering of new cost-effective
programs, and through customer outreach and education; collectively, the implementation,
operation, tracking, and evaluation of these programs and offerings is called demand-side
management (DSM).
Results of independent surveys show Idaho Power’s efforts to educate and inform customers
are successful: the company remains one of the top-ranked utilities for energy efficiency
awareness and ranked #3 in the West Midsize Segment of the J.D. Power 2022 Electric Utility
Residential Customer Satisfaction Study.

Figure 2. Idaho Power service area map
Programs and Offerings
Idaho Power’s main objectives for DSM programs are to achieve prudent cost-effective energy
efficiency savings and to provide useful and cost-effective demand response programs as
determined by the Integrated Resource Plan (IRP) planning process. Idaho Power strives to
offer customers valuable programs and information to help them wisely manage their energy
usage. DSM programs and offerings by customer sector (residential, commercial/industrial
[C&I], and irrigation) are shown in Table 1.
Introduction
Page 6 Demand-Side Management 2022 Annual Report
Table 1. DSM programs by sector, operational type, and location, 2022
Program by Sector Operational Type State
Residential
A/C Cool Credit ....................................................................... Demand Response ID/OR
Easy Savings: Low-Income Energy Efficiency Education ......... Energy Efficiency ID
Educational Distributions ....................................................... Energy Efficiency ID/OR
Energy Efficient Lighting ......................................................... Energy Efficiency ID/OR
Energy House Calls ................................................................. Energy Efficiency ID/OR
Heating & Cooling Efficiency Program .................................... Energy Efficiency ID/OR
Home Energy Audit................................................................. Energy Efficiency ID
Home Energy Report Program ................................................ Energy Efficiency ID
Multifamily Energy Savings Program ...................................... Energy Efficiency ID/OR
Oregon Residential Weatherization ....................................... Energy Efficiency OR
Rebate Advantage .................................................................. Energy Efficiency ID/OR
Residential New Construction Program.................................. Energy Efficiency ID
Shade Tree Project ................................................................. Energy Efficiency ID
Weatherization Assistance for Qualified Customers .............. Energy Efficiency ID/OR
Weatherization Solutions for Eligible Customers ................... Energy Efficiency ID
Commercial/Industrial
Commercial and Industrial Energy Efficiency Program
Custom Projects ................................................................ Energy Efficiency ID/OR
Green Motors—Industrial ........................................... Energy Efficiency ID/OR
New Construction ............................................................. Energy Efficiency ID/OR
Retrofits ............................................................................ Energy Efficiency ID/OR
Commercial Energy-Saving Kits .............................................. Energy Efficiency ID/OR
Flex Peak Program .................................................................. Demand Response ID/OR
Oregon Commercial Audits .................................................... Energy Efficiency OR
Small Business Direct Install ................................................... Energy Efficiency ID/OR
Irrigation
Irrigation Efficiency Rewards .................................................. Energy Efficiency ID/OR
Green Motors—Irrigation ................................................. Energy Efficiency ID/OR
Irrigation Peak Rewards .......................................................... Demand Response ID/OR
All Sectors
Northwest Energy Efficiency Alliance ..................................... Market Transformation ID/OR

Funding Sources
Energy efficiency and demand response funding comes from multiple sources: Idaho Power
base rates, the Idaho and Oregon Energy Efficiency Riders (Riders), and the annual power cost
adjustment (PCA) in Idaho. Idaho incentives for the company’s demand response programs are
recovered through base rates and tracked through the annual PCA, while Oregon demand
 Introduction 
Demand‐Side Management 2022 Annual Report Page 7 
response incentives are funded through the Oregon Rider. Total expenditures on DSM‐related 
activities from all funding sources were $43 million in 2022, as shown in Figure 3. 

Figure 3. DSM expense history by program type, 2002–2022 (millions [$])
Cost‐Effectiveness Goals
Idaho Power considers cost‐effectiveness of primary importance in the design, implementation, 
and tracking of the energy efficiency and demand response programs. Prior to the actual 
implementation, Idaho Power performs a cost‐effectiveness analysis to assess whether a 
potential program design or measure will be cost‐effective. Incorporated in these models are 
inputs from various sources that use the most current and reliable information available.  
Idaho Power strives for all programs to have benefit/cost (B/C) ratios greater than one for the 
utility cost test (UCT), total resource cost (TRC) test, and participant cost test (PCT) at the 
program and measure levels, where appropriate. Each cost‐effectiveness test provides a 
different perspective, and Idaho Power believes each test adds value when evaluating overall 
program performance. In 2020, Idaho Power transitioned to using the UCT as the primary 
cost‐effectiveness test for energy efficiency resource planning as directed by the Idaho Public 
Utilities Commission (IPUC) in Order No. 34503. The company plans to continue to calculate the 
TRC and PCT because each perspective can help inform the company and stakeholders about 
the effectiveness of a particular program or measure. Additionally, programs and measures 
offered in Oregon must use the TRC as the primary cost‐effectiveness test as directed by the 
OPUC in Order No. 94‐590. 
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Introduction
Page 8 Demand-Side Management 2022 Annual Report
There are many assumptions when calculating the cost-effectiveness of a given program or
measure. Savings can vary based on several factors, such as participation levels or the
participants’ locations. For instance, heat pumps installed in the Boise area will have lower
savings than those installed in the McCall area. If program participation and savings increase,
fixed costs, such as labor and marketing, are distributed more broadly, and the program
cost-effectiveness increases.
When an existing program or measure is not cost-effective, Idaho Power works with its Energy
Efficiency Advisory Group (EEAG) to obtain input before making its determination on
continuing, discontinuing, or modifying an offering. The company must demonstrate why a
non-cost-effective measure or program continues to be offered and communicate the steps the
company plans to take to improve cost-effectiveness. This aligns with the expectations of the
IPUC and the OPUC.
As a result of IPUC Order No. 35336 (IPC-E-21-32) and the Public Utility Commission of Oregon’s
(OPUC) approval on February 8, 2022 in Docket No. ADV 1355, Idaho Power determines
cost-effectiveness for its demand response programs using financial and alternate resource
cost assumptions from each IRP.
Details on the cost-effectiveness assumptions and data are included in Supplement 1:
Cost-Effectiveness.
DSM Annual Report Structure
The Demand-Side Management 2022 Annual Report consists of this main document
and two supplements. The main document contains the following sections related to
2022 DSM activities:
• Program Performance is a summary of total energy savings and program expenses,
funding, expenditures, and the overall approach to marketing, surveys, evaluations,
and cost-effectiveness.
• Program Activity—Residential, C&I, and Irrigation provides sector summaries and
individual program details, including marketing efforts, cost-effectiveness analyses,
customer satisfaction survey results, and evaluation recommendations and responses.
• Other Programs and Activities is an overview of DSM-related programs and activities
that can span multiple sectors, including market transformation.
• Appendices 1 through 4 present data related to payments, funding, and program-level
costs and savings.
Supplement 1: Cost-Effectiveness describes the standard cost-effectiveness tests for
Idaho Power programs and reports current-year program-level and summary cost-effectiveness
and expenses by funding source and cost category.
Introduction
Demand-Side Management 2022 Annual Report Page 9
Supplement 2: Evaluation includes an evaluation and research summary, the evaluation plan,
EEAG meeting notes, links to NEEA evaluations, copies of IDL reports, research and survey
reports, evaluation reports, and other reports related to DSM activities.
Introduction
Page 10 Demand-Side Management 2022 Annual Report

2022 DSM Program Performance
Demand-Side Management 2022 Annual Report Page 11
2022 DSM PROGRAM PERFORMANCE
A summary of the energy efficiency and demand response program performance metrics is
presented in this section and in individual program sections later in this report. Appendices 1
through 4 provide additional details on the funding, expenditures, and savings at the program
and sector levels.
Energy Savings and Program Expenses
Efficiency
Energy efficiency programs are available to all customer segments in Idaho Power’s service area
and focus on reducing energy use by identifying homes, buildings, equipment, or components
for which an energy-efficient design, replacement, or repair can achieve energy savings.
Some energy efficiency programs include behavioral components. For example, the Residential
Energy Efficiency Education Initiative (REEEI), the seasonal contests, the School Cohort,
Water and Wastewater Cohorts, and the Home Energy Report (HER) Program primarily focus on
behavioral energy savings.
Savings from energy efficiency programs are measured on a kilowatt-hour (kWh) or
megawatt-hour (MWh) basis. Programs can supply energy savings throughout the year or at
different times, depending on the energy efficiency measure. Idaho Power shapes the
energy-savings profile based on how end-use equipment uses energy to estimate energy
reduction at specific times of the day and year. The company’s energy efficiency offerings
include programs in residential and commercial new construction (lost-opportunity savings),
residential and commercial retrofit applications, and irrigation and industrial system
improvement or replacement. Idaho Power’s incentives are offered to its residential, irrigation,
industrial, large-commercial, small business, government, and school customers to promote a
wide range of energy-saving projects.
Idaho Power devotes significant resources to maintain and improve its energy efficiency and
demand response programs. The 2022 total savings, including savings from the Northwest
Energy Efficiency Alliance (NEEA), were 169,889 MWh. 2022 savings increased by 26,968 MWh
compared to the 2021 savings of 142,921 MWh—a 19% year-over-year increase—
and represent enough energy to power approximately 14,900 average homes in Idaho Power’s
service area for one year. The savings from Idaho Power’s energy efficiency programs alone,
excluding NEEA savings, were 145,440 MWh in 2022 compared to 126,102 MWh in 2021—
a 15% year-over-year increase. Savings and expenses are shown in Figure 4.
The 2022 savings results consisted of 28,525 MWh from the residential sector, 109,960 MWh
from the C&I sector, and 6,955 MWh from the irrigation sector. The C&I programs contributed
2022 DSM Program Performance 
Page 12 Demand‐Side Management 2022 Annual Report 
76% of the direct program savings. See Appendix 3 for a complete list of programs and 
sector‐level savings.  

Figure 4. Annual energy savings and energy efficiency program expenses, 2002–2022
(MWh and millions [$])
Demand Response 
Idaho Power started its modern demand response programs in 2002 and currently has a 
capacity of more than 8% of its all‐time system peak load available to respond to a system peak 
load event during the summer. The goal of demand response at Idaho Power is to minimize or 
delay the need to build new supply‐side peaking resources. The company estimates future 
capacity needs through the IRP planning process and plans resources to mitigate predicted 
system deficits. Demand response is measured both by the actual demand reduction in 
megawatts (MW) achieved during events, as well as the potential demand reduction if all 
programs were used at full capacity. 
In summer 2022, Idaho Power utilized all or portions of the programs on 15 different days 
between June 15 and September 15. The 2022 actual maximum non‐coincidental load 
reduction from all three programs was 200 MW (Figure 5). The total capacity for all three 
programs was approximately 312 MW at the generation level. The amount of capacity available 
for demand response varies based on weather, time of year, and how programs are used and 
managed. The actual non‐coincidental load reduction (200 MW) is calculated using interval 
meter data from participants. The maximum capacity (312 MW) is calculated using the total 
enrolled MW from participants with an expected maximum realization rate for those 
participants. The maximum capacity for the Irrigation Peak Rewards program is based on the 
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Idaho Power Program Savings (MWh)
EE expenses (no DR)
 2022 DSM Program Performance 
Demand‐Side Management 2022 Annual Report Page 13 
maximum reduction possible during the hours within the program season. For the Flex Peak 
Program, the maximum capacity is the maximum nominated amount of load reduction. For the 
A/C Cool Credit program, the capacity is calculated based on the number of active participants 
multiplied by the maximum per‐unit reduction ever achieved. 
The 2022 demand response season was the first to incorporate program modifications 
approved by the IPUC in Order No. 35336 (IPC‐E‐21‐32) and approved by the OPUC on February 
8, 2022, in Docket No. ADV 1355, which replaced the Settlement Agreement set in IPUC Order 
No. 32923 and OPUC Order No. 13‐482, respectively. The program modifications included 
several operational and incentive changes that allow the demand response programs to better 
meet the needs of the overall system. Namely, under the new terms, the end of the demand 
response season was extended from August 15 to September 15 and events may now extend to 
later in the evening. The orders also approved higher incentive levels to compensate 
participants for the extended event windows as well as expand the company’s ability to market 
the programs to all potential customers.  

Figure 5. Peak demand reduction capacity and demand response expenses, 2004–2022
(MW and millions [$])
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2022 DSM Program Performance
Page 14 Demand-Side Management 2022 Annual Report
Table 2. DSM programs by sector summary and energy usage/savings/demand reduction, 2022
Program Impacts a Idaho Power System Sales

Program
Expenses
Energy
Savings
(MWh)
Peak-Load
Reduction
(MW)b
Sector Total
(GWh)c
Percentage of
Energy Usage
Year-End
Number of
Customers
Residential ................................ $ 5,690,839 28,525 6,022 38% 518,490
Commercial/Industrial .............. 17,939,548 109,960 7,807 49% 77,431
Irrigation ................................... 2,080,027 6,955 1,950 12% 22,071
Market Transformation ............ 2,789,937 24,448
Demand Response .................... 9,852,529 n/a 200/312
Direct Overhead/Other Programs 3,103,553 n/a
Indirect Program Expenses ....... 1,507,146
Total ......................................... $ 42,963,579 169,889 200/312 15,779 100% 617,992
a. Data are rounded to the nearest whole unit, which may result in minor rounding differences.
b. Maximum actual reduction/maximum potential reduction. Includes 9.7% peak line loss assumptions.
c GWh=Gigawatt-hour
DSM Funding and Expenditures
Funding for DSM programs comes from several sources. The Idaho and Oregon Rider funds are
collected directly from customers on their monthly bills. The 2022 Idaho Rider was 3.1% of base
rate revenues, pursuant to IPUC Order No. 34871. The 2022 Oregon Rider was 4% of base rate
revenues. Additionally, Idaho demand response program incentives were funded through base
rates and are tracked through the annual PCA mechanism. DSM expenses not funded through
the riders are included in Idaho Power’s ongoing operation and maintenance (O&M) costs.
Table 3 shows the total expenditures funded by the Idaho and Oregon Riders and Idaho Power
base rates resulting in total DSM expenditures of $42,963,579. The non-rider funding category
includes the company’s demand response incentives in Idaho, Weatherization Assistance for
Qualified Customers (WAQC) expenses, and O&M costs.
Table 3. 2022 funding source and energy savings
Funding Source Expenses a MWh Savings
Idaho Rider ................................................................................................................ $ 31,673,550 166,233
Oregon Rider ............................................................................................................. 1,285,478 3,360
Idaho Power Base Rates ............................................................................................ 10,004,551 295
Total .......................................................................................................................... $ 42,963,579 169,889
a Dollars are rounded to the nearest whole unit, which may result in minor rounding differences.
Table 4 and Figure 6 present 2022 DSM program expenditures by category. While the Incentive
Expense category illustrates the amount paid directly to customers for their participation in an
energy efficiency or demand response program, other categories include items or services that
directly benefited customers. The expenses in the Materials & Equipment category were
primarily for various kit programs ($930,698) and direct-install weatherization measures
 2022 DSM Program Performance 
Demand‐Side Management 2022 Annual Report Page 15 
($125,000). Most expenses in the Other Expense category were for marketing ($1,307,293), 
Custom Projects energy audits ($321,686), program evaluations ($290,983), program trainings 
($88,151), and program expenses ($20,466). The Purchased Services category includes 
payments made to NEEA ($2,789,937), WAQC CAP agencies ($1,212,534), and third‐party 
contractors who help deliver Idaho Power's programs. 
Table 4. 2022 DSM program expenditures by category
Program Expenditure Category Total a % of Total
Incentive Expense ...................................................................................................... $ 25,672,977 59.8% 
Labor/Administrative Expense .................................................................................. 4,021,552 9.4% 
Materials & Equipment ............................................................................................. 1,097,458 2.6% 
Other Expense ........................................................................................................... 2,042,340 4.8% 
Purchased Services .................................................................................................... 10,129,252 23.6% 
Total .......................................................................................................................... $ 42,963,579 100%
a Dollars are rounded to the nearest whole unit, which may result in minor rounding differences.  

Figure 6. 2022 DSM program expenditures by category

Incentive Expense
59.8%
Labor/Administrative Expense
9.4%
Materials & Equipment
2.6%
Other Expense
4.8%
Purchased Services
23.6%
Engineering 
Services
33.2%
Kits
2.5%
NEEA Funding
27.5%
WAQC CAP Agency 
Payments
12.0%
Weatherization 
Solutions LLC 
Payments
1.9%
Misc Contractor 
Services
22.8%
2022 DSM Program Performance
Page 16 Demand-Side Management 2022 Annual Report
Table 5. 2022 DSM program incentive totals by program type and sector
Program Type—Sector a, b Total c % of Total
DR—Residential ........................................................................................................ $ 379,634 1.5%
DR—Commercial/Industrial...................................................................................... 430,322 1.7%
DR—Irrigation ........................................................................................................... 7,895,971 30.8%
EE—Residential ........................................................................................................ 1,836,424 7.2%
EE—Commercial/Industrial ...................................................................................... 13,461,084 52.4%
EE—Irrigation ........................................................................................................... 1,669,543 6.5%
Total ......................................................................................................................... $ 25,672,977 100%
a DR = demand response
b EE = energy efficiency
c Dollars are rounded to the nearest whole unit, which may result in minor rounding differences.

Figure 7. Percent of DSM program incentive expenses by program type and sector, 2022
Customer Education
Idaho Power produced an Energy Efficiency Guide in 2022 and distributed it in June, primarily as
an insert in the Boise Weekly and 24 local newspapers. As COVID-19 concerns declined,
Idaho Power was able to re-engage with customers in person to discuss energy efficiency
at 42 community events. Idaho Power also distributed 1,550 copies of the 30 Simple Things You
Can Do to Save Energy booklet directly to customers. In 2022, Idaho Power’s program
specialists and education and outreach energy advisors (EOEA) delivered nearly
670 presentations and trainings with energy savings messages to audiences of all ages.
2022 DSM Program Performance
Demand-Side Management 2022 Annual Report Page 17
Efforts to enhance digital communication continued—with the goal of bringing a variety of
energy and money-saving tips to a broad range of customers.
Idaho Power supports the Integrated Design Lab (IDL), which conducted Lunch & Learn sessions
to educate architects, engineers, and other design and construction professionals about various
energy efficiency topics. In 2022, the IDL conducted 14 in-person technical training sessions
with 100 architects, engineers, designers, project managers, and other interested parties.
Also, IDL hosted six virtual Building Simulation Users Group (BSUG) sessions with
195 professionals attending.
The IDL also maintains an Energy Resource Library (ERL) with tools for measuring and
monitoring energy use and provides training on how to use them. The ERL includes over
900 individual pieces of equipment and 69 new tools were added in 2022. In 2022, the ERL
home page had 2,768 visitors.
Over the course of 11 days in 2022, Idaho Power delivered six equivalent full-time days of live,
online, technical training sessions at no cost to the customers. Topics included the following:
• HVAC System Testing for Energy Efficiency
• Motors and Variable Frequency Drives (VFD)
• Fan System Training
• Chilled Water System and Cooling Towers
• Compressed Air Training
The level of participation in 2022 remained high, with 216 individuals signing up for the sessions
and 150 unique logins. Due to the virtual nature of the course, in some cases there were
multiple attendees at a single login location.
Idaho Power offered four live, online, technical training sessions to industrial wastewater
customers that were attended by 50 participants. Topics included the following:
• Water Energy Basics
• Wastewater Typical No-/Low-Cost Opportunities
• Pumps and Efficiency
• Activated Sludge Basics
Aside from the classes listed above, Idaho Power also partnered with the Northwest Energy
Efficiency Council (NEEC) to administer a Building Operator Certification Level I Course which
began in November 2021 and was completed in May 2022. Idaho Power sponsored
17 customers who signed up for the training by paying $900 of the $1,895 tuition cost.
Idaho Power provided three virtual irrigation workshops for the Irrigation Efficiency Rewards
and Irrigation Peak Rewards programs and provided one in-person workshop in Oregon. In
2022 DSM Program Performance
Page 18 Demand-Side Management 2022 Annual Report
October, program staff attended the first annual Idaho Farm and Ranch Conference in Boise
and hosted a booth.
Marketing
Idaho Power used multi-channel marketing and public relations (PR) strategies in 2022 to
improve communication and increase energy efficiency program awareness among its
customers. The company employs a wide variety of media and marketing, including owned
media (social, website, and newsletters) and paid media (advertising and sponsorships),
which allow Idaho Power to control the content. Earned unpaid media (news coverage,
Idaho Power’s News Briefs sent to reporters, third-party publications, and television news
appearances) gives Idaho Power access to a broader audience through alternative channels that
help establish credibility and brand trust. Though the company has less control with earned
unpaid media, the value is established through the third-party endorsement.
Idaho Power’s marketing staff networks with organizations across the region and industry to
track current and future marketing trends and successes. Idaho Power continued to work with
NEEA to coordinate, collaborate, and facilitate marketing for all sectors. To build marketing
networks and learn what works in other regions, Idaho Power staff virtually attended several
conferences and webinars in 2022, such as the E Source Utility Marketing Executive Council and
Forum in September.
The following describes a selection of the methods, approaches, and strategies used by
Idaho Power to engage customers regarding energy efficiency, along with their results. See the
respective sector overviews and programs sections later in this report for the company’s
marketing efforts specific to those areas.
Social Media
Approximately 25% of the company’s total social media content promoted energy efficiency in
2022. Idaho Power regularly posted content encouraging energy efficiency behaviors,
program enrollment, and customer engagement on Facebook, Twitter, YouTube, and LinkedIn.
Social media content also showcased local businesses and organizations that have benefitted
from Idaho Power energy efficiency efforts. Idaho Power engaged with customers who posted
their own social media content about Idaho Power programs. Idaho Power’s Facebook and
Twitter pages hosted two customer sweepstakes giveaways, encouraging customers to enter by
leaving a comment about how they save energy in the summer or winter.
Facebook, Twitter, and LinkedIn all remain as priority channels for engaging and communicating
directly with customers on energy efficiency tips and program offerings.
At the end of 2022, Idaho Power had approximately 25,100 followers on Facebook, 6,950 on
Twitter, 14,345 on LinkedIn, and 3,000 on Instagram.
2022 DSM Program Performance
Demand-Side Management 2022 Annual Report Page 19
Website
Idaho Power tracked the number of page views to the main energy efficiency pages—
also known as landing pages—from external users on the company’s website. In 2022,
the company’s energy efficiency homepage received 10,235 page views, the residential landing
page received 98,014 views, and the business and irrigation landing pages received
21,243 views. Idaho Power uses Google Analytics to analyze web activity. Google’s definition of
page views is the total number of pages viewed, with repeated views of a single page by one
user counted as a new view.
Public Relations
Idaho Power’s PR staff supported energy efficiency programs and activities through: videos
telling energy efficiency success stories; Connections, a customer newsletter distributed in
monthly bills and available online; News Briefs, a weekly email of interesting news items sent to
all media in the company’s service area; pitching and participating in news stories; energy
efficiency TV segments; and public events, such as incentive check presentations.
In 2022, the January and June issues of Connections were devoted to energy efficiency,
with additional energy efficiency content for small business customers in the February issue.
The January issue included a variety of ideas for energy-saving tips, such as efficient thermostat
settings, the benefits of induction cooking, and knowing when to replace home appliances for
more efficient options. The June edition featured a residential customer energy-saving success
story, including information on how a local couple saves energy in the summer, as well as
information about how summer temperatures impact energy use, low-cost energy efficiency
improvement, and using My Account to control your energy use.
With another hot summer throughout the company’s service area, energy efficiency
information for staying cool during high temperatures was once again shared across the
company’s owned media channels and with regional media outlets. Social media messaging
included tips about how to save energy during the high demand hours from 4 to 9 p.m.
To recognize National Dairy Month in June 2022, Idaho Power shared multiple pieces of content
through social media, News Briefs, and videos, with a portion of the information focused on
energy efficiency. The company produced a new video highlighting local ice cream maker,
The STIL, including how energy and energy efficiency factor into their business. The company
also produced a short Instagram video highlighting a local dairy farmer who works closely with
Idaho Power for their power and energy efficiency needs.
Media outreach efforts resulted in a variety of earned media coverage focused on energy
efficiency. Energy efficiency topics were pitched in News Briefs throughout the year, and the
company earned media coverage in multiple markets spanning print, TV, and radio.
2022 DSM Program Performance
Page 20 Demand-Side Management 2022 Annual Report
Customer Relationship Survey
Relationship surveys measure the satisfaction of several aspects of a customer’s relationship
with Idaho Power, including energy efficiency, at a very high level. As such, the surveys are not
intended to measure all aspects of the energy efficiency programs.
The 2022 Burke Customer Relationship Survey asked two questions related specifically to
satisfaction with Idaho Power’s energy efficiency programs: 1) Have you participated in an
Idaho Power energy efficiency program? 2) Overall, how satisfied are you with the energy
efficiency program? In 2022, 20.7% of the survey respondents across all sectors indicated they
participated in an Idaho Power energy efficiency program, and 91.7% were “very” or
“somewhat” satisfied with the program they participated in.
The sector-level results of the annual 2022 survey are discussed in the Residential, C&I,
and Irrigation Sector Overview sections of this report.
Customer Satisfaction Surveys
To ensure meaningful survey results, Idaho Power conducts program research every two to
three years unless programs have been changed significantly. Throughout 2022, Idaho Power
administered several surveys regarding energy efficiency programs to measure customer
satisfaction. Some surveys were administered by a third-party contractor; other surveys were
administered by Idaho Power either through traditional paper or electronic surveys or through
the company’s online panel, Empowered Community. Results of these studies are included in
Supplement 2: Evaluation.
Evaluations
Idaho Power considers program evaluation an essential component of its DSM operational
activities. The company uses third-party contractors to conduct impact, process, and other
evaluations on a scheduled and as-required basis. In some cases, research and analyses are
conducted internally and managed by Idaho Power’s Research and Analysis team within the
Customer Relations and Energy Efficiency (CR&EE) department. Third-party contracts are
generally awarded using a competitive bidding process managed by Idaho Power’s Corporate
Services department.
Idaho Power uses industry-standard protocols for its internal and external evaluation efforts,
including the National Action Plan for Energy Efficiency—Model Energy Efficiency Program
Impact Evaluation Guide, the California Evaluation Framework, the International Performance
Measurement and Verification Protocol (IPMVP), the Database for Energy Efficiency Resources,
and the Regional Technical Forum’s (RTF) evaluation protocols.
2022 DSM Program Performance
Demand-Side Management 2022 Annual Report Page 21
The company also supports regional and national studies to promote the ongoing
cost-effectiveness of programs, the validation of energy savings and demand reduction, and the
efficient management of its programs. Idaho Power considers primary and secondary research,
cost-effectiveness analyses, potential assessments, and impact and process evaluations to be
important resources in providing accurate and transparent program savings estimates.
Idaho Power uses recommendations and findings from the evaluations and research to
continuously refine its DSM programs.
In 2022, Idaho Power contracted third-party evaluators to conduct program evaluations for the
following programs: HER Program (impact evaluation), C&I New Construction (impact and
process evaluation), C&I Retrofits (impact and process evaluation), and Commercial
Energy-Saving Kits (Commercial ESK) (impact and process evaluation).
External program administrators compiled program summary reports for the Student Energy
Efficiency Kits (SEEK) program and the HER program, and the company conducted internal
analyses for the A/C Cool Credit, Flex Peak, and Irrigation Peak Rewards programs.
To support Idaho Power’s long-term planning through the IRP, both an Energy Efficiency
Potential Study and Demand Response Potential Study were completed in 2022. Idaho Power
engaged a third party, and utilizing Idaho Power’s customer data and industry information, a
20-year forecast of energy efficiency savings and megawatts of program potential for demand
response was estimated. The information from these studies is being used in the 2023 IRP.
A summary of the results of these evaluations is available in the respective program sections.
An evaluation schedule and the final reports from evaluations, studies, and research completed
in 2022 are provided in Supplement 2: Evaluation.
Cost-Effectiveness Results
A summary of the cost-effectiveness metrics calculated for the energy efficiency programs in
2022 is provided in Table 6. Details on the cost-effectiveness assumptions and data are included
in Supplement 1: Cost-Effectiveness.
Table 6. Cost-effectiveness summary by energy efficiency program
Program/Sector UCT TRC Ratepayer Impact Measure (RIM) PCT
Educational Distributions ............................................................. 1.31 1.62 0.38 n/a
Energy Efficient Lighting ............................................................... 1.68 1.52 0.41 4.35
Energy House Calls1 ...................................................................... 0.70 0.77 0.27 n/a
Heating & Cooling Efficiency Program .......................................... 0.98 0.30 0.34 0.76
Home Energy Report Program2 .................................................... 0.71 0.79 0.25 n/a
Multifamily Energy Savings Program3........................................... 0.49 0.68 0.25 n/a
Rebate Advantage ........................................................................ 1.18 0.54 0.34 1.56
2022 DSM Program Performance
Page 22 Demand-Side Management 2022 Annual Report
Program/Sector UCT TRC Ratepayer Impact Measure (RIM) PCT
Residential New Construction Program ....................................... 1.45 0.84 0.41 1.70
Shade Tree Project ....................................................................... 1.02 1.21 0.47 n/a
Weatherization Assistance for Qualified Customers .................... 0.17 0.32 0.13 n/a
Weatherization Solutions for Eligible Customers ......................... 0.15 0.23 0.11 n/a
Residential Energy Efficiency Sector4 .......................................... 1.00 0.76 0.34 2.89
Commercial and Industrial Energy Efficiency Program
Custom Projects ...................................................................... 2.88 1.12 0.88 1.17
New Construction ................................................................... 4.25 3.64 0.68 5.41
Retrofits .................................................................................. 2.01 1.11 0.57 1.61
Commercial Energy-Saving Kits .................................................... 0.78 0.87 0.39 n/a
Small Business Direct Install ......................................................... 0.95 1.50 0.43 n/a
Commercial/Industrial Energy Efficiency Sector5 ....................... 2.71 1.34 0.73 1.71
Irrigation Efficiency Rewards ........................................................ 2.69 2.54 0.79 2.66
Irrigation Energy Efficiency Sector6 ............................................. 2.69 2.54 0.79 2.66
Energy Efficiency Portfolio7 ......................................................... 2.02 1.43 0.64 2.01
1 Program closed June 30, 2022.
2 Cost-effectiveness based on 2022 savings and expenses. Cost-effectiveness ratios also calculated for the program life-cycle. Program life-cycle UCT and TRC 1.17 and 1.29, respectively.
3 Program closed December 31, 2022.
4 Residential sector cost-effectiveness excludes WAQC benefits and costs. If included, the UCT ,TRC, RIM, and PCT would be 0.84, 0.67, 0.32, and 2.56, respectively.
5 C&I Energy Efficiency Sector cost-effectiveness ratios include savings and participant costs from Green Motors Rewinds.
6 Irrigation Energy Efficiency Sector cost-effectiveness ratios include savings and participant costs from Green Motors Rewinds.
7 Portfolio cost-effectiveness excludes WAQC benefits and costs. If included, the UCT, TRC, RIM, and PCT would be 1.94, 1.40, 0.63, and 2.00, respectively.

Residential Sector Overview
Demand-Side Management 2022 Annual Report Page 23
2022 DSM PROGRAM ACTIVITY
Residential Sector Overview
In 2022, Idaho Power’s residential sector consisted of 512,803 customers averaged throughout
the year; Idaho customers averaged 498,921 and eastern Oregon averaged 13,882. The average
number of residential sector customers grew by 12,716 in 2022, an increase of 2.5% from 2021.
The residential sector represented 38.3% of Idaho Power’s actual total billed electricity usage
and 47.0% of overall retail revenue in 2022.
Table 7 shows a summary of 2022 participants, costs, and savings from the residential energy
efficiency programs.
Table 7. Residential sector program summary, 2022
Total Cost Savings
Program Participants Utility Resource Annual Energy (kWh) Peak Demand (MW)1
Demand Response
A/C Cool Credit ........................................... 19,127 homes $ 829,771 $ 829,771 20.1/26.8
Total ................................................................................................................................... $ $ 829,771 20.1/26.8
Energy Efficiency
Easy Savings: Low-Income Energy
Efficiency Education ..................................
267 -ups 152,718 152,718 22,755
Educational Distributions .......................... 49,136 1,086,813 1,086,813 3,741,954
Energy Efficient Lighting............................ 370,739 534,982 714,445 1,728,352
Heating & Cooling Efficiency Program ...... 1,080 666,016 2,414,026 1,310,260
Home Energy Audit .................................. 425 184,858 239,783 28,350
Home Energy Report Program .................. 104,826 964,791 964,791 20,643,379
Multifamily Energy Savings Program......... 97 [3] [buildings] 34,181 34,181 41,959
Oregon Residential Weatherization .......... 7 8,825 8,825 0
Rebate Advantage ..................................... 97 167,622 402,649 255,541
Residential New Construction Program ... 109 235,732 578,922 337,562
Shade Tree Project .................................... 1,874 128,856 128,856 39,595
Weatherization Assistance for Qualified Customers ................................. 147 -profits 1,281,495 2,028,513 272,647
Weatherization Solutions for
Eligible Customers .....................................
27 205,788 205,788 48,233
Total ................................................................................................................................... $ 5,690,839 8,998,473 28,525,103
Notes:
See Appendix 3 for notes on methodology and column definitions.
Totals may not add up due to rounding.
1 .

Residential Sector Overview
Page 24 Demand-Side Management 2022 Annual Report
Residential DSM Programs
A/C Cool Credit. A demand response program that gives residential customers a credit for
allowing Idaho Power to cycle their air conditioning (A/C) units during periods of high energy
demand or for other system needs.
Easy Savings: Low-Income Energy Efficiency Education. A program offering coupons to income
qualified customers for HVAC tune-ups and one-on-one energy savings education.
Educational Distributions. A multifaceted approach to educating residential customers about
their energy consumption, including giving away various efficient products and engaging
elementary students with in-class and at-home activities.
Energy Efficient Lighting. The Energy Efficient Lighting program provides incentives directly to
manufacturers or retailers, so that discounted prices are passed on to the customer at the point
of purchase.
Energy House Calls. A program designed specifically for owners of manufactured homes to test
and seal ducting and offer energy-efficient products designed to reduce energy costs.
Heating & Cooling Efficiency Program. Providing incentives to customers and builders who
upgrade existing homes or build new ones using energy-efficient heating and cooling
equipment and services.
Home Energy Audit. Idaho customers living in multifamily homes with discrete meters or
single-family homes pay a reduced price for an energy audit to identify energy efficiency
improvement opportunities. Participants may receive energy-efficient products for no
additional cost.
Home Energy Report Program. A program that sends Idaho customers energy reports to
help them understand their energy use and provides energy efficiency tips and
incentive information.
Multifamily Energy Savings Program. A program offering renters in multifamily buildings
energy-efficient products designed to reduce energy use and power costs.
Oregon Residential Weatherization. No-cost energy audits for Oregon customers who heat
with electricity.
Rebate Advantage. Financial incentives for customers who buy energy-efficient manufactured
homes and for the people who sell them.
Residential New Construction Program. Idaho Power offers builders a cash incentive to
construct energy-efficient, above code, single family, all-electric homes that use heat pump
technology for its Idaho customers.
Residential Sector Overview
Demand-Side Management 2022 Annual Report Page 25
Shade Tree Project. A tree giveaway program for Idaho customers. To maximize summer
energy savings, Idaho Power provides participants with a variety of resources to encourage
successful tree growth.
Weatherization Assistance for Qualified Customers and Weatherization Solutions for
Eligible Customers. Energy-efficient products, services, and education for customers who meet
income requirements and heat with electricity.
Marketing
Idaho Power ran a multi-faceted advertising campaign in the spring (May and June) and fall
(October and November) to raise and maintain awareness of the company’s energy efficiency
programs for residential customers and to demonstrate that saving energy does not have to be
challenging. The campaign used radio, television, newspaper ads, digital ads, sponsorships,
Facebook ads, and boosted posts aimed at a variety of customer demographics across the
service area. New in 2022, the company added podcast advertising, college sports
sponsorships, and two new seasonally relevant contests: Smart Summer Savings Giveaway and
Kitchen Gadgets Galore Winter Giveaway.
Described below are Idaho Power’s marketing efforts to promote energy-saving tips and the
company’s energy efficiency programs, along with resulting data. Marketing tactics related to a
specific sector or program are detailed in those respective sections later in this report.
Email
Idaho Power continued its effort with email communication in 2022. The company emails only
customers who have supplied their addresses for other business purposes (signing up for
paperless billing, for example). Energy efficiency promotional emails included heating and
cooling tips, summer and winter contest promotion, seasonal energy efficiency tips, and various
program promotions. Detailed information can be found in respective program sections.
Digital
During the spring campaign, web users were exposed to 4,410,758 display ads (animated GIF
image ads embedded on a website) based on their demographics, related to online articles they
viewed, or their use of a particular mobile web page or app. Users clicked the ads 4,009 times,
resulting in a click-through rate of 0.09%. In the fall, the display ads received
4,904,771 impressions and 4,925 clicks, resulting in a click-through rate of 0.08%.
Idaho Power began using Google search ads in 2018. When people search for terms related to
energy efficiency, energy efficiency programs, and individual program measures, the company’s
ads appear and drive them to the appropriate energy efficiency web page. These ads received
530,211 impressions and 54,374 clicks throughout the year.
Residential Sector Overview
Page 26 Demand-Side Management 2022 Annual Report
Podcasts
New in 2022, Idaho Power added podcast advertising to the media mix: 30-second Idaho Power
audio ads, called “dynamic ads,” were inserted into a listener’s podcast if they resided in the
company’s service area. The ads targeted customers by the type of listener rather than being
run on a specific show. Types of shows that featured Idaho Power ads appealed to listeners,
such as green-living enthusiasts, customers interested in home improvement/home repair,
and homeowners age 18 and over. The ads received 521,803 impressions in spring. Fall podcast
ads garnered 390,787 impressions.
Television
Idaho Power used network television and Hulu advertising for the spring and fall campaigns.
The company also used over-the-top (OTT) media. OTT is a type of streaming media that
delivers content to customers watching a certain online show. Most OTT providers have their
own app or website and are streamed through devices like Rokus, Apple TVs, or Amazon Fire
TVs. The network television campaigns focused on primetime and news programming that
reaches the highest percentage of the target market, adults aged 25 to 64.
During the spring campaign, an ad ran 816 times in the Boise, Pocatello, and Twin Falls media
markets on network television. The ad reached 30% of the Boise area target audience, 48% of
the Twin Falls area target audience, and 60% of the Pocatello area target audience. The target
audience saw the ad 16.5 times in Boise, 16.6 times in Twin Falls, and 17.5 times in Pocatello.
Hulu spring ads delivered 690,171 impressions with a 97.8% completion rate. OTT ads delivered
425,539 impressions with a 97.91% video completion rate. The spring campaign also used
Spanish network television ads: the Boise target audience saw 147 paid spots, and the Pocatello
market saw 49 spots. Spanish TV ads ran during the fall campaign as well; the Boise target
audience saw 86 paid spots, and the Pocatello audience saw 150 spots. Ad reach and frequency
information are not available for Spanish stations.
During the fall campaign, the TV spot ran 531 times in the Boise, Pocatello, and Twin Falls
media markets. The ads reached 30% of the Boise target audience, 43% of the Twin Falls
target audience, and 60% of the Pocatello target audience. The target audience saw the ad
4.5 times in Boise, 5.4 times in Twin Falls, and 5 times in Pocatello. Hulu ads received
699,807 completions. OTT ads delivered 536,610 impressions with a 97.5% video
completion rate.
Idaho Power also sponsored commercials on Idaho Public Television in the Boise and Pocatello
markets that ran a total of 56 times in the spring and 65 times in the fall.
In 2021, the television station began charging for each energy efficiency television segment.
Idaho Power paid for three segments in 2022 with topics that included energy-efficient spring
and fall tips and ways to beat the summer heat.
Residential Sector Overview
Demand-Side Management 2022 Annual Report Page 27
Radio
As part of its spring and fall campaigns, Idaho Power ran 30-second radio spots on major
commercial radio stations in the service area. To obtain optimal reach, the spots ran on several
station formats, including classic rock, news/talk, country, adult alternative, rock, sports,
and classic hits. The message was targeted toward adults ages 25 to 64 throughout
Idaho Power’s service area.
Results of the spots are provided for the three major markets: Boise, Pocatello, and Twin Falls
areas. During the spring campaign, Idaho Power ran 2,456 English radio spots. These spots
reached 46% of the target audience in Boise, 67% in Pocatello, and 66% in Twin Falls. The target
audience was exposed to the ad 7.6 times in Boise, 9.7 times in Pocatello, and 8.8 times in
Twin Falls. During the fall campaign, the company ran 2,246 English radio spots. These spots
reached 39.7% of the target audience in Boise, 57.8% of the target audience in Pocatello,
and 65.6% of the target audience in Twin Falls. The target audience was exposed to the
message 7.6 times in Boise, 8.6 times in Pocatello, and 9.6 times in Twin Falls during the fall
campaign.
In spring, Idaho Power also ran 419 ads on Spanish-speaking radio stations and 294 National
Public Radio (NPR) ads in the service area targeting adults ages 25 to 54. The fall campaign
included 372 Spanish ads and 317 NPR ads.
Idaho Power ran 30-second spots with accompanying visual banner ads on Pandora internet
radio, which mobile and web-based devices access. In the spring, records show
697,749 impressions and 89 clicks to the Idaho Power residential energy efficiency web page.
The fall ads yielded 692,623 impressions and 45 clicks. Ads also ran on Spotify internet radio
and yielded 288,504 impressions and 195 clicks in the spring and 374,041 impressions with
129 clicks in the fall.
Print
As part of the campaign, print advertising ran in the major daily and select weekly newspapers
throughout the service area. The company also ran ads in the Idaho Shakespeare Festival
program, Idaho Magazine, Boise Lifestyle and Meridian Lifestyle magazines, and IdaHome
Magazine. The spring ads highlighted individual energy efficiency tips, such as using the
power-save setting on electronics and running ceiling fans counterclockwise for summer.
The fall ads featured tips on minimizing gadgets (use one at a time) and using smart
power strips.
In 2022, Idaho Power updated the program information in a spiral-bound guide outlining each
of the residential energy efficiency programs, tips, and resources. The updated guide will be
included in the 2023 Welcome Kits. The previous edition of the guide was included in
Residential Sector Overview
Page 28 Demand-Side Management 2022 Annual Report
2021 Welcome Kits, provided to WAQC customers, and shared with customers who attended
events Idaho Power participated in before the COVID-19 restrictions.
Social Media
Three Facebook ads for the 2022 energy efficiency campaign received 90,664 impressions and
909 clicks per ad.
Throughout the year, Idaho Power used Facebook and Twitter posts and boosted Facebook
posts for various programs and easy energy efficiency tips for customers to implement at home
and at work.
Out-of-Home
In 2022, Idaho Power participated in several tactics referred to as out-of-home advertising.
Out-of-home advertising attempts to reach customers when they are outside of their homes.
The tactics helped maintain energy efficiency program awareness throughout the year. Tactics
included a full-side bus wrap on a Pocatello Regional Transit bus in Eastern Idaho.
Idaho Power sponsored the Boise Hawks (minor league baseball team) from May through
September. As part of the sponsorship package, Idaho Power received a 15-second digital ad on
the four screens within the stadium. The company’s energy efficiency ad was shown a total of
13,589 times during the 48-game season and the overall season attendance was 160,582.
Boise Hawks use a special TV system called In-Stadium Media (ISM), which can tell how often
spectators look at screens. The average interaction/engagement rate was 52%, which is above
the industry standard of 42%. Two 15-second Idaho Power commercials were also shown
during the Boise Hawks Facebook Live Broadcast for all games.
A Boise State University (BSU) sponsorship was also part of the marketing strategy in 2022.
Energy efficiency messaging was featured at Albertsons Stadium during football games and
included digital concourse signage, a game co-sponsorship and table, logo recognition on the
digital game program cover, and the Idaho Power logo included on promotional materials
leading up to the game. The BSU basketball sponsorship included a 30-second digital ribbon
board that rotated throughout the game.
Sponsoring sporting events at Idaho State University (ISU) was also part of the marketing plan.
The sponsorship included two permanent banners located in each end zone of Holt Arena,
which has an annual attendance of over 500,000. Idaho Power was also recognized during each
home football game by being the presenting sponsor of the “Idaho Power Helmet Shuffle
Game” shown on the big screen. ISU basketball games featured an Idaho Power animated
graphic (for two minutes of each game) featured on the LED courtside board.
Idaho Power used weather-triggered billboards in Boise, Pocatello, Nampa, and Caldwell.
These are electronic billboards operating in January and July with variable messaging based on
Residential Sector Overview
Demand-Side Management 2022 Annual Report Page 29
the outside temperatures. This tactic keeps energy efficiency top-of-mind and demonstrates
simple ways customers can reduce energy use during extreme weather.
Idaho Power also used static billboards to reach customers in rural areas. A Spanish billboard
was placed in Kimberly (near Twin Falls) and an English billboard was placed in Heyburn
(by Burley).
Public Relations
Many of the company’s PR activities focused on the residential sector. Energy-saving tips in
News Briefs, TV segments, news releases, and Connections newsletter articles aim to promote
incentive programs and/or educate customers about behavioral or product changes they can
make to save energy in their homes.
See the Program Performance section and the C&I Sector Overview for more 2022 PR activities.
Empowered Community
In 2015, Idaho Power created the Empowered Community, an online community of residential
customers, to measure customer perceptions on a variety of company-related topics,
including energy efficiency. The community has over 2,000 actively engaged members from
across Idaho Power’s service area. Idaho Power typically sends these members between six and
12 surveys per year. In 2022, Idaho Power included ten energy efficiency messages with survey
invitations resulting in nearly 13,500 touchpoints.
Recruitment for the Empowered Community is conducted annually to refresh the membership.
Throughout February and March 2022, various types of recruitment were conducted with
residential customers, including messages on paperless billing emails, a News Brief to local
media outlets, pop-up ads on My Account, direct emails, and social media posts. In 2022,
1,017 new members were added to Empowered Community.
Seasonal Sweepstakes
In 2022, Idaho Power ran two seasonally focused energy efficiency sweepstakes—the Smart
Summer Savings Summer Giveaway in August and the Kitchen Gadgets Galore Giveaway in
December. Both sweepstakes aimed to maintain awareness about energy efficiency and the
impact a small change can make.
The summer sweepstakes ran August 15 through 24 and received 2,774 entries.
Customers were asked to comment—through social media or on the Idaho Power website—
with a way they saved energy during the hot summer months. In return, participants were
entered to win one of 10 smart thermostats. The sweepstakes was promoted with email
messaging to 287,449 customers, and social media posts reached 9,108 customers,
receiving 697 engagements (likes, comments, shares). The sweepstakes was also promoted on
idahopower.com through a pop-up ad on the My Account homepage.
Residential Sector Overview
Page 30 Demand-Side Management 2022 Annual Report
The winter sweepstakes ran December 2 through 16 and received 10,428 entries. Customers
were asked to comment—through social media or on the Idaho Power website—with a way
they saved energy in the cold winter months. In return, participants were entered to win one of
five kitchen gadget bundles that included an air fryer, pressure cooker, electric tea kettle and
smart coffee pot. The sweepstakes was promoted with email messaging to 307,431 customers
and paid social media posts reached 1,300 customers, receiving 424 post engagements.
The sweepstakes was also promoted through a pop-up ad on the company’s My Account
homepage. It was featured in News Briefs to media outlets and was promoted on
idahopower.com.
Customer Satisfaction
Idaho Power conducts the Burke Customer Relationship Survey each year. In 2022, on a scale of
zero to 10, residential survey respondents rated Idaho Power 7.88 regarding offering programs
to help customers save energy, and 7.80 related to providing customers with information on
how to save energy and money.
Twenty-one percent of residential respondents indicated they have participated in at least one
Idaho Power energy efficiency program. Of the residential survey respondents who have
participated in at least one Idaho Power energy efficiency program, 93% were “very” or
“somewhat” satisfied with the program.
Idaho Power customer awareness of energy efficiency programs is among the highest in the
nation: 65.2% of the residential respondents in the J.D. Power and Associates 2022 Electric
Utility Residential Customer Satisfaction Study indicated they were aware of Idaho Power’s
energy efficiency programs, and on an overall basis, those customers were more satisfied with
Idaho Power than customers who were unaware of the programs. Idaho Power ranked third
out of 17 utilities included in the West Midsize Segment of this study.
See the individual program sections for program-specific customer satisfaction survey results.
Field Staff Activities
In 2022, Idaho Power’s residential and commercial energy advisors and EOEAs continued
connecting with customers through in-person meetings, presentations, and events to promote
energy efficiency programs and offerings. More than 90% of these interactions were in person.
The year also saw a return of the large legacy events including home and garden shows, as well
as career, STEM, and science fairs. Energy advisors dedicated a larger percentage of their time
to presentations and events at secondary schools, colleges, universities, and trade schools, as
well as civic and community audiences.
Idaho Power continued to focus on the training and development of its energy advisors to
expand their knowledge, skills, and abilities related to energy efficiency programs,
Residential Sector Overview
Demand-Side Management 2022 Annual Report Page 31
new technologies, and serving customers. One of the highlights during the year was an offering
of a residential building science class by an external trainer who shared insights and
perspectives about windows, insulation, building envelope, appliances, HVAC, and other
residential measures. Idaho Power also held specific training classes on lighting, building
envelope, HVAC, pumps, motors, and refrigeration.

Residential Sector—A/C Cool Credit
Page 32 Demand-Side Management 2022 Annual Report
A/C Cool Credit
2022 2021
Participation and Savings
Participants (homes) 19,127 20,995
Energy Savings (kWh) n/a n/a
Demand Reduction (MW)* 20.1/26.8 26.7/29.4
Program Costs by Funding Source
Idaho Energy Efficiency Rider $429,722 $420,376
Oregon Energy Efficiency Rider $24,491 $25,366
Idaho Power Funds $375,558 $306,247
Total Program Costs—All Sources $829,771 $751,989
Program Levelized Costs
Utility Levelized Cost ($/kWh) n/a n/a
Total Resource Levelized Cost ($/kWh) n/a n/a
Benefit/Cost Ratios
Utility Benefit/Cost Ratio n/a n/a
Total Resource Benefit/Cost Ratio n/a n/a
*Maximum actual demand reduction/maximum potential demand reduction. Demand response program reductions are reported with 9.7% peak loss assumptions.
Description
Originating in 2003, A/C Cool Credit is a voluntary, dispatchable demand response program for
residential customers in Idaho and Oregon. Using communication hardware and software,
Idaho Power cycles participants’ central A/C units or heat pumps off and on via a direct
load-control device installed on the A/C unit. This program enables Idaho Power to reduce
system capacity needs during periods of high energy demand or for other system needs.
Customers’ A/C units are controlled using switches that communicate by powerline carrier
(PLC) using the same system used by Idaho Power’s advanced metering infrastructure (AMI).
The switch is installed on each participating customer’s A/C unit and allows Idaho Power to
control the unit during a cycling event.
The cycling rate is the percentage of an hour the A/C unit is turned off by the switch.
For instance, with a 50% cycling rate, the switch will cycle the A/C unit off for about 30
(nonconsecutive) minutes of each hour. Idaho Power tracks the communication levels to
validate whether the signal reaches the switches. Switch communication may be interrupted
for a variety of reasons: the switch may be disconnected, an A/C unit may not be powered on,
the switch may be defective, or the participant’s household wiring may prevent
communication. Sometimes it is difficult for the company to detect why the switch is
not communicating.
Residential Sector—A/C Cool Credit
Demand-Side Management 2022 Annual Report Page 33
These are the program event guidelines:
• June 15 through September 15 (excluding weekends and holidays)
• Up to four hours per day
• A maximum of 16 hours per week and 60 hours per season
• At least three events per season
At the end of the season, Idaho Power or a third party evaluates the events to determine peak
demand savings.
Program Activities
In 2022, a new tariff was filed and approved to update the cycling season guidelines so the
program could run from June 15 to September 15. Before the updates, the cycling season ran
from June 15 to August 15. The extended cycling season proved beneficial when there were
higher than average temperatures during the first half of September, which resulted in events
being called on three days that wouldn’t have been available prior to the change.
In 2022, 19,127 customers participated in the program, with 217 in Oregon and 18,910 in
Idaho. Thirteen cycling events occurred, and all were successfully deployed. Table 8 shows each
event with the cycling percentage, the maximum temperature during the event, and the
maximum load reduction. The cycling rate was 55% for five of the events and 50% for the
remaining eight events, and the communication level exceeded 90% for each event.
Idaho Power calculated the maximum potential capacity in 2022 to be 26.8 MW at the
generation level. This estimate of the program capacity is based on the maximum per-unit
reduction ever achieved at the generation level of 1.4 kilowatt (kW) per participant.
Customers receive a $5.00 incentive for each month of participation between June 15 and
September 15, resulting in a total annual incentive potential of $20.00. The credits appear on
their July through October bill statements.
Table 8. A/C Cool Credit demand response event details
Event Date Event Time
Cycling
Rate
High
Temperature
Maximum Load
Reduction (MW)
July 7 6–9 p.m. 55% 94°F 11.4
July 24 4–8 p.m. 50% 101°F 16.7
July 28 4–8 p.m. 50% 103°F 18.1
July 29 4–8 p.m. 50% 104°F 20.1
August 1 6–9 p.m. 55% 102°F 18.7
August 8 5–8 p.m. 55% 102°F 16.4
August 9 5–8 p.m. 55% 98°F 16.8
August 17 6–10 p.m. 50% 102°F 14.5
August 31 6–10 p.m. 50% 105°F 14.9
September 1 5–8 p.m. 55% 97°F 15.7
Residential Sector—A/C Cool Credit
Page 34 Demand-Side Management 2022 Annual Report
Event Date Event Time Cycling Rate High Temperature Maximum Load Reduction (MW)
September 2 5–9 p.m. 50% 100°F 15.5
September 6 5–9 p.m. 50% 100°F 12.9
September 7 5–9 p.m. 50% 104°F 17.1

Throughout 2022, Idaho Power representatives continued site visits to check switches and
equipment to improve communication levels. COVID-19-related safety protocols remained in
place, including calling each customer before the visit to explain the process and safety
measures and not visiting any site where the customer was uncomfortable with the process.
The company will continue work to ensure devices associated with the program are
communicating on an ongoing basis.
During the site visits, Idaho Power representatives placed informational stickers on devices that
included a safety warning regarding risk of electric shock if the sealed demand response unit
were opened, and a toll-free phone number customers could call with questions.
Marketing Activities
Idaho Power actively marketed the A/C Cool Credit program in 2022.
The company mailed information to existing participants before the start of the 2022 season to
describe the program specifics and parameter changes—specifically the extended program
season and the additional month to receive an additional $5.00 incentive. A postcard was also
sent to participants reminding them of the upcoming season.
In the spring and throughout the summer, the company used postcards, phone calls, direct-mail
letters, and home visits (leaving door hangers for those not home) to recruit customers moving
into houses with existing switches and previous program participants who moved into new
homes without switches. The company also sent recruitment letters to select customers who
are homeowners and have not participated previously. In total, 81,391 direct-mail letters were
sent. In addition to the letters, follow-up emails (to customers with emails on file) were sent a
few weeks after the letter, reminding customers to sign up.
The program was promoted on a KTVB channel 7 segment, where an Idaho Power
representative talked with the show host about the benefits of the program. Idaho Power’s
summer Energy Efficiency Guide featured a promotional blurb on the program, encouraging
customers to visit the website and sign up.
Participating customers received a thank you and a credit reminder message on their summer
bills, and Idaho Power concluded the season by sending a thank-you postcard to participants.
Residential Sector—A/C Cool Credit
Demand-Side Management 2022 Annual Report Page 35
Cost-Effectiveness
Idaho Power determines cost-effectiveness for its demand response program using the
approved method for valuing demand response under IPUC Order No. 35336 and approved by
the OPUC on February 8, 2022, in Docket No. ADV 1355. Using financial and alternate resource
cost assumptions from the 2021 Integrated Resource Plan, the defined cost-effective threshold
for operating Idaho Power’s three demand response programs for the maximum allowable
60 hours is $82.91 per kW under the current program parameters.
The A/C Cool Credit program was dispatched for 13 events (totaling 47 event hours)
and achieved a maximum demand reduction of 20.1 MW with a maximum potential capacity of
26.8 MW. The total expense for 2022 was $829,771 and would have remained the same if the
program had been fully used for 60 hours because there are no additional variable incentives
paid for events called beyond the three minimum required events. Using the total cost and the
maximum potential capacity results in a program cost of $30.99 per kW. This is less than the
threshold, and therefore, the program was cost-effective.
A complete description of the cost-effectiveness of Idaho Power’s demand response programs
is included in Supplement 1: Cost-Effectiveness.
Evaluations
In 2021, Idaho Power contracted a third party to conduct an impact evaluation of the A/C Cool
Credit Program. Following are the recommendations of the evaluations and Idaho Power’s
response to each.
Utilize a mixed model or regression model to estimate saving for the programs. Idaho Power has
adopted the mixed-model approach for calculating load reduction for the program.
Utilize proxy event days to estimate bias and error when determining which model to select for
estimating baseline usage. Idaho Power has adopted this approach for calculating load
reduction for the program.
The evaluators recommend calling DR events on days with the highest forecasted Cooling
Degree Days to maximize program demand reductions. Idaho Power has updated its program
curtailment calculator to incorporate forecasted hourly Cooling Degree Days. This calculator
provides system operators an estimate of the demand reduction that can be attained by calling
an A/C Cool Credit event that day. However, while potential curtailment is an important metric,
the decision to call an event is ultimately based on a wide variety of factors relating to
the overall electrical system needs, and not just for the goal of maximizing program
load reductions.
In 2022, Idaho Power performed an internal review to evaluate the demand reduction over the
course of the 13 event days. The demand reduction was calculated by comparing the actual
Residential Sector—A/C Cool Credit
Page 36 Demand-Side Management 2022 Annual Report
average load for participating customers on each of the 13 event days to a corresponding
baseline. The baseline is calculated using a mixed model approach, in which five possible
statistical baseline models are tested for each household and the best fit model is selected
based on performance across a set of proxy event days.
The fourth event on July 29 achieved the highest peak demand reduction of 1.05 kW per
participant for a total peak reduction of 20.1 MW with line losses.
For 2022, the maximum potential capacity of the program was calculated to be 26.8 MW.
This is based on 1.4 kW per participant which the company has achieved in the past with 65%
cycling on a very hot day.
The complete report on load reduction is available in Supplement 2: Evaluation.
2023 Plans
Idaho Power will continue to actively market the A/C Cool Credit program to solicit new
participants with a strong focus on recruiting customers that reside at a residence that
currently has a switch that was installed for a previous occupant.
The company will explore opportunities to expand the A/C Cool Credit program by evaluating
the potential for a Bring-Your-Own-Thermostat program option.

Residential Sector—Easy Savings: Low-Income Energy Efficiency Education
Demand-Side Management 2022 Annual Report Page 37
Easy Savings: Low-Income Energy Efficiency Education
2022 2021
Participation and Savings
Participants (coupons) 267 0
Energy Savings (kWh) 22,755 0
Demand Reduction (MW) n/a n/a
Program Costs by Funding Source
Idaho Energy Efficiency Rider $0 $0
Oregon Energy Efficiency Rider $0 $0
Idaho Power Funds $152,718 $145,827
Total Program Costs—All Sources $152,718 $145,827
Program Levelized Costs
Utility Levelized Cost ($/kWh) $1.448 n/a
Total Resource Levelized Cost ($/kWh) $1.448 n/a
Benefit/Cost Ratios
Utility Benefit/Cost Ratio n/a n/a
Total Resource Benefit/Cost Ratio n/a n/a

Description
As a result of IPUC Case No. IPC-E-08-10 and Order Nos. 30722 and 30754, Idaho Power
committed to fund energy efficiency education for low-income customers and provided
$125,000 to Community Action Partnership (CAP) agencies in its service area annually, on a
prorated basis. These orders specified that Idaho Power provide educational information to
Idaho customers who heat their homes with electricity.
From 2009 to 2017, using CAP agency personnel, the program distributed energy-saving kits
(ESK) and corresponding educational materials to participants in the Low-Income Home Energy
Assistance Program (LIHEAP) who heat their homes with electricity. In 2017, with input from a
planning committee consisting of representatives from the Community Action Partner
Association of Idaho (CAPAI), CAP agencies, the IPUC, and Idaho Power, this program
discontinued kit distribution and offered a pilot incentive: a coupon for a free electric HVAC
tune-up and one-on-one education with the goal of helping low-income customers learn ways
to reduce their energy costs and have a maintained HVAC system.
To provide services for the program, regional HVAC company owners sign contractor guidelines
and acknowledge the two-fold goal of the program—customer education and equipment
tune-up. During the customer visit, HVAC contractors perform the tune-up and teach residents
how to change furnace filters. They also explain how regular maintenance improves overall
performance and answer questions about the specific heating equipment and ways to save
Residential Sector—Easy Savings: Low-Income Energy Efficiency Education
Page 38 Demand-Side Management 2022 Annual Report
energy. The contractor leaves behind information for a customer satisfaction survey that can be
completed online or mailed to CAPAI. Respondents are entered into a drawing for a gift card
provided by CAPAI.
Program Activities
The planning committee and contractors met virtually throughout 2021 to plan 2022 program
updates. The group agreed to the following improvements that were implemented in 2022:
• Eligibility was expanded beyond only LIHEAP recipients to include all income-qualified
Idaho Power customers with electric heat regardless of whether they had received
LIHEAP assistance.
• In addition to providing HVAC system tune-ups and educating customers on their
systems, HVAC contractors provided new energy saving items during their visits. By year
end, the program accomplished the following:
• Provided either a box of disposable furnace filters or individual washable furnace
filters to 247 customers after showing them how to change or wash the filters and
explaining the importance of clean furnace filters to HVAC operation
• Installed 147 dusk-to-dawn LED bulbs in porch light fixtures
• Wrapped pipes of 56 water heaters
• Left 150 packages of dryer balls
• Unwrapped and tested 175 air fryers with customer’s commitment to use them at
least twice per week in place of their ovens
• Unwrapped and tested 41 counter-top microwaves with customers while including
explanations of energy savings potential
Idaho Power sent coupons specific to each regional CAP agency for the 2022 program at the
end of 2021. The company also sent helpful energy efficiency education materials for regional
HVAC contractors to share with customers. A total of 267 coupons were redeemed by the end
of the 2022 program year.
Marketing Activities
Prior to 2022, Idaho Power sent a direct-mail postcard (Figure 8) to Idaho residential customers
who previously received energy assistance to encourage them to take advantage of the
program in 2022. Additionally, Facebook posts about the program were used during summer
2022 to promote coupon redemption.
The Easy Savings program is included under Savings for Your Home on the Idaho Power website
in the Income-Qualified Customers section.
Residential Sector—Easy Savings: Low-Income Energy Efficiency Education
Demand-Side Management 2022 Annual Report Page 39

Figure 8. Direct-mail postcard to Idaho residential customers for Easy Savings
Cost-Effectiveness
Because the Easy Savings program is primarily an educational and marketing program,
the company does not apply traditional cost-effectiveness tests to it.
For the HVAC tune up coupons redeemed in 2022, the program claimed approximately 61 kWh.
For the pipes wrapped, the program claimed approximately 75 kWh. The savings are a weighted
average of single family, multifamily, and manufactured home types from the 2022 energy
efficiency potential study. The savings are weighted using the 2022 housing types from both the
WAQC and Weatherization Solutions for Eligible Customers programs. The RTF provides
deemed savings for direct-install LED lightbulbs. For the 800-lumen dusk-to-dawn exterior
lights, the program claimed approximately 15 kWh.
2023 Plans
Each agency’s portion of the annual $125,000 payment will be made available in early 2023,
once committee meetings have been completed and contractor guidelines are signed.
Agencies will begin 2023 with their portion of this payment added to any unspent portion of
the previous year’s payments. One agency overspent their portion of the annual Easy Savings
funding in 2022. They plan to use 2023 Idaho Power funding to pay contractors for work done
in 2022 for the program. This agency also received funding transferred from another CAP
agency’s unused portion of their Easy Savings allotment for 2022.
Participating contractors will continue to discuss the importance of HVAC maintenance and
incorporate education about saving energy with coupon recipients. They will answer questions
about other ways to save energy in their homes.
Residential Sector—Educational Distributions
Page 40 Demand-Side Management 2022 Annual Report
Educational Distributions
2022 2021
Participation and Savings
Participants (kits/giveaways) 49,136 47,027
Energy Savings (kWh) 3,741,954 2,930,280
Demand Reduction (MW) n/a n/a
Program Costs by Funding Source
Idaho Energy Efficiency Rider $1,061,898 $433,963
Oregon Energy Efficiency Rider $24,866 $15,826
Idaho Power Funds $49 $0
Total Program Costs—All Sources $1,086,813 $449,790
Program Levelized Costs
Utility Levelized Cost ($/kWh) $0.037 $0.019
Total Resource Levelized Cost ($/kWh) $0.037 $0.019
Benefit/Cost Ratios
Utility Benefit/Cost Ratio 1.31 2.39
Total Resource Benefit/Cost Ratio 1.62 3.10

Description
Designated as a specific program in 2015, the Educational Distributions effort is administered
through the REEEI and seeks to use low- and no-cost channels to deliver energy efficiency items
with energy savings directly to customers. The goal for these distributions is to drive behavioral
change and create awareness of, and demand for, energy efficiency programs in Idaho Power’s
service area.
Idaho Power selects items for distribution if the initial analysis indicates the measure is either
currently cost-effective or expected to be cost-effective. Typically, selected items have
additional benefits beyond traditional energy savings, such as educating customers about
energy efficiency, expediting the opportunity for customers to experience newer technology,
or allowing Idaho Power to gather data or validate potential energy savings resulting from
behavior change.
Idaho Power recognizes the need to educate and guide customers to promote behavioral
change and awareness and will plan program activities accordingly. Items may be distributed
at events and presentations, through direct-mail, or during home visits conducted by
energy advisors.
Nightlights as Giveaways
Nightlights are a popular giveaway item with Idaho Power customers and provide another
opportunity to share information about energy efficient LED technology and safe,
Residential Sector—Educational Distributions
Demand-Side Management 2022 Annual Report Page 41
energy-efficient ways to provide nighttime lighting. Energy advisors are encouraged to use
nightlights as a bridge to these discussions.
Student Energy Efficiency Kit Program
The SEEK program provides fourth- to sixth-grade students in schools in Idaho Power’s service
area with quality, age-appropriate instruction regarding the wise use of electricity. Each child
who participates receives an energy efficiency kit. The products in the kit are selected
specifically to encourage energy savings at home and engage families in activities that support
and reinforce the concepts taught at school.
Once a class enrolls in the program, teachers receive curriculum and supporting materials.
Students receive classroom study materials, a workbook, and a take-home kit containing
the following:
• Three LED lightbulbs
• A high-efficiency showerhead
• An LED nightlight
• A furnace filter alarm
• A digital thermometer for measuring water and refrigerator/freezer temperatures
• A water flow-rate test bag
• A shower timer
• Sticker and magnet pack (containing reminders about energy efficiency)

Figure 9. Student Energy Efficiency Kit
Residential Sector—Educational Distributions
Page 42 Demand-Side Management 2022 Annual Report
At the end of the program, students and teachers return feedback to Idaho Power’s vendor
indicating how the program was received and which measures were installed. The vendor uses
this feedback to provide a comprehensive program summary report showing program results
and savings.
Unlike most residential programs offered by Idaho Power, SEEK results are reported on a
school-year basis, not by calendar year.
Welcome Kits
Idaho Power uses a vendor to mail Welcome Kits to brand new customers between 35 and
45 days after electric service begins at their residence. Each kit contains four LED lightbulbs,
two nightlights, a greeting card, and a small flipbook containing energy-saving tips and
information about Idaho Power’s energy efficiency programs. The kits are intended to
encourage first-time customers to adopt energy-efficient behaviors early in their new homes.

Figure 10. Welcome Kit
Program Activities
Nightlights as Giveaways
Idaho Power continued to distribute LED nightlights to engage customers in discussions around
energy-efficient behavior changes and home upgrades.
In-person events rebounded slowly but steadily throughout the year, affording Idaho Power
staff and energy advisors the opportunity to distribute 5,920 nightlights along with an
educational message. Nightlights were distributed to business and community leaders at civic
Residential Sector—Educational Distributions
Demand-Side Management 2022 Annual Report Page 43
events, aging customers at senior centers, secondary students at career fairs and during
presentations, as well as many other groups at presentations and events throughout
Idaho Power’s service area.

Figure 11. Nightlights as giveaways
Student Energy Efficiency Kit Program
During the 2021–2022 school year, the vendor was responsible for SEEK recruiting activities.
Idaho Power EOEAs continued to promote the program during their school visits and
interactions with fourth- to sixth-grade teachers. The new curriculum, focusing on digital
engagement, was well received and SEEK enrollments were strong. The vendor delivered a
record 12,595 kits to 338 classrooms in 174 schools within Idaho Power’s service area.
This resulted in 2,349 MWh of savings.
Welcome Kits
Idaho Power continued to contract with a third-party vendor to distribute energy efficiency
kits to the company’s first-time customers. In 2022, after collaboration with EEAG, the kit
contents were adjusted to improve cost-effectiveness. Rather than two 800-lumen lightbulbs,
Residential Sector—Educational Distributions
Page 44 Demand-Side Management 2022 Annual Report
two 1,600-lumen LED lightbulbs and one nightlight, each recipient received four 1,100-lumen
lightbulbs and two nightlights.
The company sent nearly 31,000 Welcome Kits to customers in 2022—down slightly from the
quantity delivered in the previous two years. Idaho Power continues to receive positive
customer feedback indicating these kits are well-received.
Marketing Activities
Nightlights as Giveaways
Nightlights are not marketed as a separate measure, but energy advisors used them to facilitate
energy efficiency conversations during customer visits. Nightlights have also become an
outstanding way to engage customers at events and presentations as energy advisors report
they are a sought-after item.
Student Energy Efficiency Kit Program
During the 2021–2022 school year, the vendor staff handled most of the marketing and
recruitment of teachers via email and phone calls to the eligible schools. Idaho Power EOEAs
continued to promote the program through the Community Education Guide and in
conversations with teachers throughout the year.
Welcome Kits
The Welcome Kits are not requested by customers; therefore, they are not marketed. Instead,
each week Idaho Power sends a list of new customers to the vendor to fulfill the order. The kits
are, however, used to cross-market other programs through the inclusion of a small flipbook
containing energy-saving tips and information about Idaho Power’s energy efficiency programs.
Cost-Effectiveness
In situations where Idaho Power managed energy efficiency education and distribution through
existing channels, the cost-effectiveness calculations were based on the actual cost of the
items. If outside vendors were used to assist with distribution, the cost-effectiveness
calculations include all vendor-related charges.
The UCT and TRC for the program are 1.31 and 1.62 respectively.
Nightlights as Giveaways
Idaho Power used the third-party evaluator’s calculated savings of 12 kWh per nightlight as
explained in the Welcome Kit cost-effectiveness section.
Student Energy Efficiency Kit Program
The cost-effectiveness analysis for the SEEK offering was based on the savings reported by the
kit provider during the 2021–2022 school year. The kit provider calculated the annual savings
based on information collected from the participants’ home surveys and the installation rate of
the kit items. Questions on the survey included the number of individuals in each home,
Residential Sector—Educational Distributions
Demand-Side Management 2022 Annual Report Page 45
water heater fuel type, flow rate of old showerheads, and the wattage of any replaced
lightbulbs. The response rate for the survey was approximately 63%. The survey gathers
information on the efficiency level of the existing measure within the home and which measure
was installed. The energy savings will vary for each household based on the measures offered
within the kit, the number of items installed, and the existing measure that was replaced.
Based on the feedback received from the 2021–2022 school year, the savings for each kit was
approximately 187 kWh annually per household on average, and the program saved
2,349,312 kWh annually. A copy of the report is included in Supplement 2: Evaluation.
Welcome Kits
For the four 1100-lumen LED lightbulbs included in the kit, Idaho Power used the RTF’s
giveaway deemed savings value of 4.79 kWh per lightbulb. For the nightlight, Idaho Power used
the third-party evaluator’s calculated savings of 12 kWh per nightlight, which was identified
using survey data as part of a 2020 evaluation. The annual savings for each kit is 43.16 kWh.
With the implementation of Energy Independence and Security Act of 2007 (EISA) after June 30,
2023, Idaho Power will no longer claim savings for the screw-in LEDS.
In 2022, the Welcome Kits were not fully cost-effective due to additional erosion of lighting
savings. After consulting the EEAG in 2021, the decision was made to keep this educational
program, but to only include the cost-effective portion associated with those energy savings in
the Educational Distribution program; the remainder of the kit costs are included in the REEEI
budget (see Other Programs and Activities section).
2023 Plans
Nightlights as Giveaways
Nightlights will continue to be the primary opportunity to garner savings in conjunction with
educational discussions and customer conversations. Field staff will look for opportunities to
discuss enhancements in LED technology (dusk-to-dawn sensors, etc.) and savings, encourage
in-home adoption of LED lighting, and promote the use of LED nightlights as an energy efficient,
safe nighttime lighting option.
Student Energy Efficiency Kit Program
Idaho Power will continue to offer the SEEK program. The company will work with the vendor
to implement process and curriculum enhancements based on suggestions received from
teachers, students, and parents.
The company will continue to leverage the positive relationships Idaho Power’s EOEAs have
within the schools to maintain program participation levels.
Welcome Kits
Idaho Power will continue to offer Welcome Kits to first-time customers. For the first half of
2023, the kit configuration will continue to take advantage of the RTF savings associated with
Residential Sector—Educational Distributions
Page 46 Demand-Side Management 2022 Annual Report
1,100-lumen lightbulbs. On June 30, in conjunction with the elimination of lighting savings due
to EISA standards, the kit will be reconfigured—rather than four 1,100-lumen lightbulbs, each
kit will contain two 800-lumen lightbulbs. The Welcome Kits will cross-promote other energy
efficiency programs and educate and encourage new customers to adopt energy-efficient
behaviors upon moving into their new homes. The Educational Distributions program will
continue to count the savings and pay for the cost-effective energy-saving portion of each kit,
while the remaining costs associated with the kits will be included in Idaho Power’s REEEI
efforts.
Other Educational Distributions
Idaho Power will continue to look for opportunities to engage customers with new technologies
that stress the importance of energy-efficient behaviors at home. Idaho Power will continue
with its efforts to identify a marketplace platform that will engage and educate customers while
promoting efficient technologies that may not fold neatly into other program offerings.

Residential Sector—Energy Efficient Lighting
Demand-Side Management 2022 Annual Report Page 47
Energy Efficient Lighting
2022 2021*
Participation and Savings
Participants (lightbulbs) 370,739 0
Energy Savings (kWh) 1,728,352 0
Demand Reduction (MW) n/a n/a
Program Costs by Funding Source
Idaho Energy Efficiency Rider $505,430 $41,438
Oregon Energy Efficiency Rider $29,475 $2,194
Idaho Power Funds $76 0
Total Program Costs—All Sources $534,982 $43,631
Program Levelized Costs
Utility Levelized Cost ($/kWh) $0.030 n/a
Total Resource Levelized Cost ($/kWh) $0.040 n/a
Benefit/Cost Ratios
Utility Benefit/Cost Ratio 1.68 n/a
Total Resource Benefit/Cost Ratio 1.52 n/a
* Expenses incurred in 2021 in preparation for the relaunch of the program in 2022.
Description
The Energy Efficient Lighting program follows a markdown model that provides incentives
directly to manufacturers or retailers, with discounted prices passed on to the customer at the
point of purchase. The benefits of this model are low administration costs, better availability of
products to the customer, and the ability to provide an incentive for specific products.
The program goal is to help Idaho Power’s residential customers afford more efficient
lighting technology.
ENERGY STAR® lightbulbs are a more efficient alternative to standard incandescent and halogen
incandescent lightbulbs. Lightbulbs come in a variety of wattages, colors, and styles,
including lightbulbs for three-way lights and dimmable fixtures. ENERGY STAR lightbulbs use
70 to 90% less energy and last 10 to 25 times longer than traditional incandescent lightbulbs.
Idaho Power pays the program contractor a fixed amount for each kWh of energy savings
achieved. A portion of the funding Idaho Power provides is used to buy down the price of the
product, and a portion is applied to program administration, marketing, and retailer
promotions. Promotions include special product placement, additional discounts, and other
retail merchandising tactics designed to increase sales.
In addition to managing the program’s promotions, the program contractor is responsible for
contracting with retailers and manufacturers, providing marketing materials at the point of
purchase, and supporting and training retailers.
Residential Sector—Energy Efficient Lighting
Page 48 Demand-Side Management 2022 Annual Report
Program Activities
After the BPA-sponsored Simple Steps program ended in September 2020, Idaho Power
pursued the start of its own lighting buydown program. Shelf studies showed that specific retail
channels in the region were still selling inefficient lighting products. The new lighting buydown
program, launched in late December 2021, provides ENERGY STAR LED lightbulb and light
fixture incentives at grocery, dollar, mass merchandise, and small hardware stores, and
provides ENERGY STAR LED light fixture incentives at membership club and do-it-yourself
hardware stores. By following this model, Idaho Power was able to achieve higher savings by
focusing on sales at retailers that traditionally offered more inefficient lighting products,
helping to ensure the program remained cost-effective.
In 2022, LED lightbulbs comprised 74% of the program’s sales for the year, a significant
decrease from the 93% of lightbulb sales in 2020. LED fixtures comprised approximately 26% of
overall program sales.
In 2022, Idaho Power worked with 11 participating retailers, representing 100 individual store
locations in its service area. Of those participating retailers, 66% of sales were from grocery,
dollar, and mass-merchandise stores, 23% from do-it-yourself hardware stores, 9% from small
hardware stores, and 2% from membership clubs. Many rural sales came from these smaller
retailers that serve hard-to-reach customers. It was important to include several store types
across Idaho Power’s service area to ensure all customers have access to efficient
lighting options.

Figure 12. Lighting shelf store display
Residential Sector—Energy Efficient Lighting
Demand-Side Management 2022 Annual Report Page 49
Marketing Activities
In 2022, the program contractor promoted discounts with special product placement and signs.
Monthly visits to check stock and ensure point-of-purchase signs were placed on qualifying
products were conducted. In addition, a Facebook and Twitter post went out in March using
updated graphics. A lighting tip was also included in the August Home Energy Report.

Figure 13. Home Energy Report tip

Figure 14. Lighting post
The company continued to host an Energy Efficient Lighting program website and made
available a Change a Light program brochure. The brochure is distributed at community events
to help discuss energy-efficient lighting with customers and to help them select the right
lightbulb for their needs.
Residential Sector—Energy Efficient Lighting
Page 50 Demand-Side Management 2022 Annual Report
Cost-Effectiveness
The UCT and TRC ratios for the program are 1.68 and 1.52, respectively. In September 2020,
the RTF updated the savings assumptions for residential lighting. At the time of the update,
the US Department of Energy (DOE) had issued a Final Rule that essentially circumvented the
previous 45 lumen-per-watt backstop for general service incandescent lamps. As a result,
the RTF workbook version 9.0 (and subsequent updates) assumed no federal standards were in
place and the analysis was based on the NEEA’s 2019 lighting market shelf study. Due to the
lower savings in the workbook, the BPA decided not to resume the Simple Steps program.
As described at the November 2020 EEAG meeting, Idaho Power reached out to the Energy
Trust of Oregon (ETO) to learn more about the retail lighting program the organization was
planning to launch to replace the Simple Steps program. Based on its 2019 lighting market shelf
study, NEEA found that 100% of lightbulbs sold in membership clubs were LEDs while only 46%
of the lightbulbs sold in grocery, dollar, and mass-merchandise stores were LED. RTF blended
this information to determine the current market baseline for the region. ETO decided to focus
their new retail lighting program on the grocery, dollar, mass-merchandise stores retail channel
because of the higher probability of selling inefficient lightbulbs and the potential to move the
market further.
Idaho Power received ETO’s modified RTF lighting workbook version 9.3 in 2021. By updating
the market baseline, the annual savings for general purpose lightbulbs in the 250–1,049 lumen
range increased from 0.91 kwh to 4.50 kWh. The annual savings for reflector lightbulbs in the
250–1,049 lumen range increased from 1.15 kWh to 4.65 kWh. Idaho Power worked with the
third-party implementer to design a retail lighting program targeted to grocery, dollar,
mass-merchandise, and small hardware stores. Additionally, LED fixtures were included in the
program and offered across all retail channels.
In January 2021, Executive Order 13990 instructed all agencies to review existing regulations
issued or adopted between January 2017 and January 2021. The DOE re-evaluated its
prior determination and proposed codifying the 45 lumen-per-watt backstop requirement.
In April 2022, the DOE issued a Final Rule that reinstituted EISA and the expanded general
service lamp definition and the 45 lumen-per-watt backstop effective July 2022. The DOE
enacted a progressive enforcement policy with different ramp up times for both
manufacturers/importers and retailers/distributors. For the distribution and sale of
non-compliant lightbulbs, warnings would be issued from January 1 to February 28, 2023.
Reduced penalties would be issued between March 1 to June 30, 2023, with full enforcement
and penalties issued as of July 1, 2023.
The RTF reviewed and updated the savings assumptions for residential lighting in
September 2022. Per the Northwest Power and Conservation Council (NWPCC) policy, the RTF
Residential Sector—Energy Efficient Lighting
Demand-Side Management 2022 Annual Report Page 51
modeled savings based on the current effective standards. With the exception of some compact
fluorescent lightbulbs, there are not many “minimally compliant” options available. Based on
the market data, it was determined the baseline would be comprised almost entirely of LEDs.
As a result, the RTF removed the retail and by-request delivery channels. Idaho Power will begin
using the newest RTF workbook version 11.0 after June 30, 2023.
For detailed cost-effectiveness assumptions, metrics, and sources, see Supplement 1:
Cost-Effectiveness.
2023 Plans
Idaho Power, with input and support from EEAG, decided to continue offering the lighting
buydown program through June 30, 2023. After that date, the DOE will begin enforcing federal
EISA lighting standards with financial penalties to those retailers that continue to sell inefficient
lightbulbs that do not meet the new 45 lumen-per-watt requirement. It is assumed that after
that date, most retailers will no longer sell inefficient lightbulbs, negating the need for a
program to influence lighting purchasing decisions. Before the July 1 enforcement date, it is
assumed that many retailers will have inefficient inventory to offload, thus making an incentive
to purchase efficient lightbulbs more valuable. Idaho Power will perform periodic reviews of
participating retailers across its service area to validate if inefficient lightbulbs are still sold. If it
is determined that a retailer is no longer offering inefficient lightbulbs, the retailer will be
removed from the program.

Residential Sector—Energy House Calls
Page 52 Demand-Side Management 2022 Annual Report
Energy House Calls
2022 2021
Participation and Savings
Participants (homes) 52 11
Energy Savings (kWh) 54,516 14,985
Demand Reduction (MW) n/a n/a
Program Costs by Funding Source
Idaho Energy Efficiency Rider $36,734 $17,375
Oregon Energy Efficiency Rider $1,378 $882
Idaho Power Funds $51 $0
Total Program Costs—All Sources $38,163 $18,257
Program Levelized Costs
Utility Levelized Cost ($/kWh) $0.062 $0.105
Total Resource Levelized Cost ($/kWh) $0.062 $0.105
Benefit/Cost Ratios
Utility Benefit/Cost Ratio 0.70 0.43
Total Resource Benefit/Cost Ratio 0.77 0.50

Description
Initiated in 2002, the Energy House Calls program gives homeowners of electrically heated
manufactured homes an opportunity to reduce electricity use by improving the home’s
efficiency. Specifically, this program provides free duct-sealing and additional efficiency
measures to Idaho Power customers living in Idaho or Oregon who use an electric furnace or
heat pump. Participation is limited to one service call per residence for the lifetime of
the program.
Services and products offered through the Energy House Calls program include duct testing and
sealing according to Performance Tested Comfort System (PTCS), standards set and maintained
by BPA; installing LED lightbulbs; testing the temperature set on the water heater; installing
water heater pipe covers when applicable; installing one bathroom faucet aerator, one kitchen
faucet aerator; and leaving two replacement furnace filters with installation instructions,
as well as energy efficiency educational materials appropriate for manufactured
home occupants.
Idaho Power provides contractor contact information on its website and marketing materials.
The customer schedules an appointment directly with one of the certified contractors in their
region. The contractor verifies the customer’s initial eligibility by testing the home to determine
if it qualifies for duct-sealing. Additionally, contractors have been instructed to install LED
lightbulbs only in exterior, moderate- and high-use areas of the home; to replace only
Residential Sector—Energy House Calls
Demand-Side Management 2022 Annual Report Page 53
incandescent and halogen lightbulbs; and to install bathroom aerators and showerheads only if
the upgrade can be performed without damaging a customer’s existing fixtures.
The actual energy savings and benefits realized by each customer depend on the measures
installed and the repairs and/or adjustments made. Although participation in the program is
free, a typical cost for a similar service call would be $400 to $600, depending on the
complexity of the repair and the specific measures installed.
Program Activities
Energy House Calls is one of Idaho Power’s longest-running energy efficiency programs,
available to electrically heated manufactured homes only and limited to one visit per home for
the life of the program. With a limited number of available homes that meet the eligibility
criteria, the program has experienced a steady and sustained decline in participation indicating
market saturation. Due to the program becoming non-cost-effective, with the support of EEAG,
the program was closed to new participants as of June 30, 2022.
Contractors were given until December 31, 2022, to service all customers that enrolled prior to
the June 30 closing, including any remaining from the backlog of projects that had accumulated
while the program in-home work was temporarily suspended due to COVID-19 in 2020 and
2021. While not everyone from the backlog of customers decided to move forward with their
participation in the program, contractors contacted every customer to ensure they were
informed about the program closing and had ample opportunity to have work done before the
December 31 deadline.
In 2022, 52 homes received products and/or services through the program, resulting in
54,516 kWh savings. Of the participating homes, 43% were in Idaho Power’s South–East Region,
19% were in the Capital Region, and 38% were in the Canyon–West Region.

Figure 15. Participation in the Energy House Calls program, 2012–2022
Residential Sector—Energy House Calls
Page 54 Demand-Side Management 2022 Annual Report

Figure 16. Participation in the Energy House Calls program, by region
Duct-Sealing
Some customers who applied for the Energy House Calls program could not be served because
their ducts did not require duct-sealing or could not be sealed for various reasons. These jobs
were billed as a test-only job. On some homes, it was either too difficult to seal the ducts,
or the initial duct blaster test identified the depressurization to be less than 150 cubic feet per
minute (cfm) making duct-sealing unnecessary. Additionally, if after sealing the duct work the
contractor was unable to reduce leakage by 50%, the contractor would bill the job as a test-only
job. Prior to 2015, these test-only jobs were not reported in the overall number of jobs
completed for that year because they included no kWh savings. In 2022, because Idaho Power
offered direct-install measures in addition to the duct-sealing component, all homes were
reported. While some homes were not duct-sealed, all would have had some of the
direct-install measures included, which would allow Idaho Power to report kWh savings for
those homes. Of the 52 homes that participated in 2022, six were serviced as test-only.
If a home had a blower door and duct blaster test completed, and the contractor determined
that only duct-sealing was necessary, it was billed as a test and seal. For a multi-section home
with an x-over duct system (one that transfers heated or cooled air from one side to the other)
that needed replacing in addition to the duct-sealing, it was charged as an x-over. When a
home required that the existing belly-return system be decommissioned and a new return
installed along with the duct-sealing, it was billed as a complex system. A complex system that
also requires the installation of a new x-over as well as duct-sealing is billed as a complex
system and x-over job. Figure 17 shows the job type totals (test and seal versus x-over) for the
2022 Energy House Calls program.
38%
19%
43%
Canyon-West Capital South-East
Residential Sector—Energy House Calls
Demand-Side Management 2022 Annual Report Page 55

Figure 17. Energy House Calls participation by job type
Direct-Install Measures
In 2022, contractors installed 265 LED lightbulbs, no showerheads, one bathroom aerator,
three kitchen aerators, and pipe wrap on 21 water heater pipes.
Marketing Activities
Because the program became non-cost-effective and was ending on June 30, 2022,
all marketing efforts were suspended for 2022. Idaho Power added a disclaimer on the Energy
House Calls program website once the program ended advising that the program had ended
but that there were other assistance programs available for duct-sealing through the WAQC or
Weatherization Solutions for Eligible Customers programs, or duct-sealing measures included in
the Heating & Cooling Efficiency Program (H&CE Program).
Cost-Effectiveness
The UCT and TRC ratios for the program are 0.70 and 0.77, respectively.
The RTF is the source of all savings assumptions for the program. Savings for the LED lightbulbs
increased from 5.65 kWh to 12.12 kWh based on updated lighting assumptions. In 2021,
the RTF reviewed aerator savings. Because of the uncertainty around the relationship between
hot water savings and the savings associated with aerators, the RTF deactivated the measure.
Therefore, there are no savings associated with the aerators in 2022.
In 2022, Idaho Power used the same RTF savings for duct-sealing in manufactured homes as
were used in 2021. The savings were approximately 1,081 kWh per home. In December 2021,
the RTF reviewed and updated the savings associated with manufactured home duct-sealing
based on program evaluations around the region. The updated manufactured duct-sealing
savings is approximately 888 kWh per home. Due to the timing of the adoption of the new
workbook, Idaho Power did not use the updated workbook to calculate savings for the program
in 2022. However, the new workbook was used to analyze the future cost-effectiveness for the
program. Due to the declining savings of both the duct-sealing and direct-install items as well as
0
5
10
15
20
25
30
35
40
Complex System Test and Seal Test Only (Leaky, Hard to
Seal, Out of Scope)
Test Only (Not Leaky)X-over
Residential Sector—Energy House Calls
Page 56 Demand-Side Management 2022 Annual Report
the increasing costs associated with offering a free service for program participants, it was
determined the program would continue to be non-cost-effective in its current format.
With the support of EEAG, the program was closed to new participants as of June 30, 2022.
The updated manufactured home duct-sealing savings of 888 kWh per home will be used for
future participants of the Heating & Cooling Efficiency Program (H&CE Program).
For more detailed information about the cost-effectiveness savings and assumptions,
see Supplement 1: Cost-Effectiveness.
2023 Plans
With the Energy House Calls program ending, eligibility for the duct-sealing measure incentive
within the H&CE Program has expanded to include customers that reside in an all-electric
manufactured home. Additionally, both the WAQC and Weatherization Solutions for Eligible
Customers programs include duct-sealing as approved measures when needed.

Residential Sector—Heating & Cooling Efficiency Program
Demand-Side Management 2022 Annual Report Page 57
Heating & Cooling Efficiency Program
2022 2021
Participation and Savings
Participants (projects) 1,080 1,048
Energy Savings (kWh) 1,310,260 1,365,825
Demand Reduction (MW) n/a n/a
Program Costs by Funding Source
Idaho Energy Efficiency Rider $636,597 $600,636
Oregon Energy Efficiency Rider $28,960 $34,522
Idaho Power Funds $459 $25
Total Program Costs—All Sources $666,016 $635,182
Program Levelized Costs
Utility Levelized Cost ($/kWh) $0.050 $0.044
Total Resource Levelized Cost ($/kWh) $0.180 $0.155
Benefit/Cost Ratios*
Utility Benefit/Cost Ratio 0.98 1.14
Total Resource Benefit/Cost Ratio 0.30 0.36
*2021 and 2022 cost-effectiveness ratios include evaluation. If evaluation expenses were removed from the program’s cost-effectiveness,
the 2021 UCT and TRC would be 1.19 and 0.36, respectively, and the 2022 UCT and TRC would be 1.00 and 0.30, respectively.
Description
Initiated in 2007, the objective of the H&CE Program is to provide customers with
energy-efficient options for space heating and cooling and water heating. The program
provides incentives to residential customers, builders, landlords, and installation contractors in
Idaho Power’s service area for the purchase and proper installation of qualified heating and
cooling equipment and services. Measures, conditions, and incentives/stipends for existing
homes and for new homes are summarized in tables 9 and 10, respectively.
See idahopower.com/heatingcooling for a complete description of the program.
Residential Sector—Heating & Cooling Efficiency Program
Page 58 Demand-Side Management 2022 Annual Report
Table 9. Measures, conditions, and incentives—existing homes
Existing Equipment Requirement New Equipment or Services Customer Incentive Contractor Stipend
New Equipment or Services
Requirements1
Ducted air-source heat pump Ducted air-source heat pump $ 250 $ 50 Minimum efficiency 8.5 HSPF
Oil or propane heating system Ducted air-source heat pump 400 50 Minimum efficiency 8.5 HSPF
Natural gas not available
Electric (forced-air or zonal) heating system) Ducted air-source heat pump 800 50 Minimum efficiency 8.5 HSPF
Ducted air-source heat pump Ducted open-loop water-source
heat pump
500 50 Minimum efficiency 3.5 COP
Electric (forced-air or zonal), oil, or propane
heating system
Ducted open-loop water-source
heat pump
1,000 50 Minimum efficiency 3.5 COP
Natural gas not available when existing
equipment is oil or propane heating system
Air-source heat pump Ducted ground-source heat pump2 1,000 Minimum efficiency 3.5 COP
Electric zonal system, electric furnace, or an
oil or propane furnace
Ducted ground-source heat pump2 3,000 Natural gas not available when existing
equipment is oil or propane heating system
Minimum efficiency 3.5 COP
n/a Central A/C2 50 Minimum 15 SEER but <17; minimum 12 EER
n/a Central A/C2 150 Minimum 17 SEER; minimum 13 EER
Zonal electric heating system Ductless air-source heat pump 750 Minimum one indoor unit in main living area
Zonal electric heating system Ductless air-source heat pump 750 Minimum one indoor unit in main living area
Electric forced-air heating system or heat
pump
Duct-sealing services (single family
or manufactured home2)
350
Permanent split capacitor air handler motor Electronically commutated motor 50 1503 Oil, propane or natural gas forced-air heat,
electric forced-air heat, or heat pump
n/a Evaporative cooler 150 2,500 CFM minimum airflow
Electric storage water heater Heat pump water heater 300 Tank size less than or equal to 55 gallons
Electric heating system Smart thermostat 75 Internet connected
Zonal or central A/C or heat pump Whole-house fan 200 2,000 CFM minimum airflow
1See idahopower.com/heatingcooling for full requirements
2Idaho customers only
3Contractor incentive
HSPF = Heating Seasonal Performance Factor
COP = Coefficient of Performance
SEER = Seasonal Energy Efficiency Ratio

Residential Sector—Heating & Cooling Efficiency Program
Demand-Side Management 2022 Annual Report Page 59
Table 10. Measures, conditions, and incentives—new homes
New Equipment Customer Incentive Contractor Stipend Requirements
Ducted air-source heat pump $ 400 $ 50 Minimum efficiency 8.5 HSPF;
natural gas not available
Ducted open-loop water-source heat pump 1,000 50 Minimum efficiency 3.5 COP;
natural gas not available
Ducted ground-source heat pump1 3,000 Minimum efficiency 3.5 COP;
natural gas not available
Central A/C1 50 Minimum 15 SEER but <17;
minimum 12 EER
Central A/C1 150 Minimum 17 SEER; minimum 13 EER
1Idaho customers only
Idaho Power requires licensed contractors to perform the installation services related to these
measures, except evaporative coolers, heat pump water heaters, and smart thermostats.
To qualify for the ducted air-source heat pump (ASHP), ducted open-loop water source heat
pump, ductless ASHP, and duct-sealing incentives, an authorized participating contractor must
perform the work. To be considered a participating contracting company, an employee from
the contracting company must first complete Idaho Power’s required training regarding
program guidelines and technical information on HVAC equipment.
A third-party contractor reviews and submits incentive applications for payment using a
program database portal developed by Idaho Power. The third-party contractor also provides
technical and program support to customers and their contractors and performs on-site and
off-site verifications.
Program Activities
Program performance is substantially dependent on the contractors’ abilities to promote and
leverage the heat pump measures offered. Idaho Power developed participating contractors
currently in the program while adding three new contractors in 2022. The program specialist
frequently engaged with contractors to discuss the program and provided six on-site training
sessions with technical and market information.
In 2020, Idaho Power conducted an exercise described as journey mapping: a team of
employees met periodically for three months to develop improvements to the program that
would improve the customer experience when participating in the program. Recommendations
included creating new layouts for the program’s 10 online PDF application forms. Idaho Power
updated one of the 10 forms in 2021 and completed updates to the remaining nine forms
in 2022.
Idaho Power began offering two new measures through the program on July 1, 2022.
The measures provided a cash incentive to Idaho customers who installed a central A/C or a
ground-source heat pump. The incentives apply to both existing homes and new construction.
Residential Sector—Heating & Cooling Efficiency Program
Page 60 Demand-Side Management 2022 Annual Report
During the development stage of these measures, the company provided updates and
requested input from EEAG at quarterly meetings. EEAG’s feedback regarding these measures
was positive.
The number of H&CE Program incentives paid in 2022 are listed in Table 11.
Table 11. Quantity of H&CE Program incentives in 2022
Incentive Measure Project Quantity
Ducted Air-Source Heat Pump ......................................................... 181
Open Loop Water-Source Heat Pump ............................................. 3
Ductless Heat Pump ........................................................................ 243
Evaporative Cooler .......................................................................... 14
Whole-House Fan ............................................................................ 113
Electronically Commutated Motor .................................................. 28
Duct-Sealing .................................................................................... 2
Smart Thermostat ........................................................................... 449
Heat Pump Water Heater ................................................................ 26
Central A/C ...................................................................................... 19
Ground-Source Heat Pump ............................................................. 2

Marketing Activities
Idaho Power used multiple marketing tactics for its H&CE Program promotion in 2022.
Idaho Power sent two program-related postcards to a targeted customer group determined
to use electric heat: 8,088 customers received postcards in February and September.
The company mailed a bill insert to 306,888 residential customers in April and
298,861 residential customers in October.
In February, the company emailed information about the H&CE Program to approximately
180,938 residential customers. The promotion was opened by over 89,318 customers and
received approximately 2,039 clicks to the H&CE Program website. Idaho Power also sent an
email promotion in August to 209,830 residential customers; the email was opened by
107,549 customers and received 4,987 clicks to the web page.
In February and September, Idaho Power used an ad agency to send digital display ads to
customers based on their internet browsing preferences. Using Google Analytics, the ad agency
determined the ads resulted in 1,539,162 impressions and 17,535 clicks to the H&CE Program
web page in February and 3,046,748 impressions and 2,319 clicks in September. (An impression
is a count of every time the ad is seen; a single person who sees the ad 10 times counts as
10 impressions.)
Residential Sector—Heating & Cooling Efficiency Program
Demand-Side Management 2022 Annual Report Page 61
A pop-up ad in the company’s My Account platform—a portal where customers login to see
their energy usage and bill information—was also used in February. Customers who logged into
My Account saw a promotion for the H&CE Program pop up on their screens. A total of
77,646 customers were shown the pop-up and 2,052 clicked through to learn more.
Program information was also included in energy efficiency collateral mailed in the new
customer Welcome Kits. The program was also featured on Idaho Power’s website homepage
in February.
The spring/summer edition of the 2022 Energy Efficiency Guide distributed through local
newspapers featured an article on whole house fans. The Home Energy Report listed heating
and cooling tips on the back page throughout the year (see the HER Program section). The two
new measures listed above, central A/C and ducted ground-source heat pump, were also added
to the suite of program collateral.
Additionally, the program specialist continued to distribute flyers, called tech sheets,
to interested customers and contractors. The eight different flyers are especially beneficial as
sales tools for contractors, for use at trade shows, and as mailers to customers without internet
access who seek program and individual cash incentive information.
Cost-Effectiveness
In 2022, the H&CE Program had a UCT of 0.98 and TRC of 0.30. In 2022, the program incurred
evaluation expenses related to the impact and process evaluation that occurred in late 2021.
If the amount incurred for the evaluation was removed from the program’s cost-effectiveness,
the UCT would be 1.00, while the TRC would be 0.30.
Overall, while participation increased slightly from 1,048 participants in 2021 to
1,080 participants in 2022, the total savings decreased by 55,565 kWh year over year.
The decrease in overall savings was largely due to the lower participation in the electronically
commutated motor (ECM) measure and the reduction in connected thermostat savings in
response to the evaluation recommendation to not claim savings for ASHPs that claim
additional commissioning, controls, and sizing (CCS) savings. Savings were also reduced for
evaporative coolers in response to the evaluation recommendation to adjust the savings with a
net-to-gross (NTG) factor of 44.4%. These reductions in savings were slightly offset by the
increase in participation in the ductless heat pump (DHP) measure and the addition of two new
measures in 2022, ground-source heat pumps and high-efficiency A/Cs.
The RTF is the source of most measure savings assumptions within the program. In general,
most savings assumption did not change in 2022 over 2021 with the exception of a few
measures in response to recommendations by the evaluators in the recent impact evaluation.
More information regarding those recommendations and adjustment are described in the
Evaluation section below. Some measures within the program do not pass the UCT; however,
Residential Sector—Heating & Cooling Efficiency Program
Page 62 Demand-Side Management 2022 Annual Report
these measures, with the exception of DHPs, would pass the UCT if administration costs were
not included in the measure’s cost-effectiveness. Most measures are not cost-effective from a
TRC perspective. The program itself has a cost-effectiveness exception with the OPUC under
UM 1710. Due to the changes to federal standards for ASHP, the program will be modified in
2023 to incorporate the updated savings assumptions, new measures, and recommendations
from the 2021 evaluation.
For detailed information about the cost-effectiveness savings, sources, calculations,
and assumptions, see Supplement 1: Cost-Effectiveness.
Evaluations
In 2021, Idaho Power contracted with a third-party consultant to conduct impact and process
evaluations for the 2020 program year of the H&CE Program in the Idaho and Oregon service
area. The complete analysis report was published in the 2021 Supplement 2: Evaluation.
Below are the impact and process evaluation recommendations made by the evaluators
followed by a description of how Idaho Power responded in 2022.
Applications/Processing
It was recommended Idaho Power: require customers to fill out application forms consistently
for all projects; review each application to ensure information requested on the application
forms is provided and that it meets the requirements; improve methods when collecting
information using the web and application forms; verify information customers provide on the
whole-house fan application forms and ensure those forms are enforced. Idaho Power requires
customers to consistently provide information requested on the application forms, per the
Terms and Conditions. Idaho Power cannot always control what customers input on the forms;
follow-up and verification is performed only on the critical data. Idaho Power will continue
reviewing all application forms for any missing or inaccurate information and obtain missing or
inaccurate information from the customer or the installing contractor if used. Idaho Power will
continue comparing all information provided to ensure it meets the measure requirements.
Idaho Power routinely improves the Idaho Power program website and the application forms to
promote optimal usability.
Savings Assumptions/Calculations
The evaluators recommended Idaho Power round up savings values to the nearest kWh for
Regional Technical Forum (RTF) approved measures. Idaho Power has received conflicting
recommendations from past evaluators to use RTF deemed savings values to two decimal
places. Idaho Power has done so for all RTF-sourced deemed savings values. The company has
decided not to apply this recommendation to maintain consistency across all programs.
It was recommended Idaho Power apply a 44.4% NTG to the claimed savings of the evaporative
cooler incentive to account for displaced refrigerated air. The evaluators referenced a Technical
Residential Sector—Heating & Cooling Efficiency Program
Demand-Side Management 2022 Annual Report Page 63
Reference Manual from Public Company of New Mexico 2015. They also recommend Idaho
Power establish a Net to Gross specific to the Idaho Power service area. Idaho Power has
applied the 44.44% NTG for the evaporative coolers that had an incentive in 2022. When the
program is updated in 2023, the application will be updated to ask questions around the
displaced refrigerated air in order for the company to calculate the actual NTG percentage for
the offering.
The evaluators recommended Idaho Power continue to use the literature review workpaper
provided by the IDL when claiming savings for the ECM incentive. Idaho Power will continue to
use the IDL workpaper along with an Idaho Power savings calculator.
The evaluators recommended Idaho Power integrate the modeling results contained in the
workpaper provided by the IDL when claiming savings for the whole-house fan incentive.
Idaho Power has started collecting the data necessary in its application forms to implement this
method. The company reviewed modeling the savings results using the IDL workpaper and
found the results to be similar to the 446 kWh currently being claimed for the measure.
Another recommendation was that Idaho Power ensure the measure level savings applied to the
heat pump water heater matches the RTF workbook interactive components such as cooling and
heating interactions. The savings calculation was updated before reporting the DSM 2021
Annual Report savings to match the savings as shown in the RTF workbook version 5.3.
They were used again in 2022.
The evaluators recommended Idaho Power refrain from claiming smart thermostat savings for
smart thermostats that get connected to heat pumps that are installed to Performance Tested
Comfort System (PTCS) standards and Idaho Power is claiming the PTCS savings. Idaho Power
has removed smart thermostat savings that are included with heat pump installations in which
PTCS savings are also claimed.
Another recommendation was that Idaho Power use the evaluator’s billing analysis to claim
savings for ducted air-source heat pumps upgrade measure as the alternative to the current
savings which combined the RTF’s ducted air-source heat pump upgrades with the RTF’s
deactivated CCS savings workbook. The savings from the billing analysis differed significantly
from the RTF deemed savings value. The savings for ASHP upgrades alone range from 20 to
107 kWh annually. CCS savings are additive and would increase the upgrade savings to 556 to
1,002 kWh. The billing analysis conducted by the evaluators showed that savings were
approximately 1,263 kWh. While the evaluators were unable to separate the estimated savings
between the ASHP upgrade and the CCS savings, the analysis seems to indicate that CCS savings
are occurring. For 2022, Idaho Power continued to use the RTF savings and CCS savings. Due to
the changes in federal standards that went into effect in January 2023, Idaho Power will
remove the upgrades as a standalone measure from the program in 2023.
Residential Sector—Heating & Cooling Efficiency Program
Page 64 Demand-Side Management 2022 Annual Report
The evaluators recommended Idaho Power continue to use the RTF’s savings values for the
ducted air-source heat pump conversion measure. In addition, due to the RTF deactivation of
the CCS workbook and the results of the Evaluator’s billing analysis, the Evaluators recommend
that Idaho Power not claim additional savings for those projects. While the billing analysis
conducted for the ASHP conversions could not show significant savings for CCS, the billing
analysis for ASHP upgrades showed significantly higher savings than the RTF upgrade savings
with CCS. That particular billing analysis seemed to indicate CCS savings are occurring.
Additionally, Bonneville Power Administration (BPA) is continuing to use deactivated CCS saving
for ASHPs that undergo PTCS. Idaho Power will continue to follow BPA’s PTCS specifications for
CCS. For 2022, Idaho Power used the savings from the RTF workbook version 5.1 and CCS
savings. Due to the changes in federal standards that went into effect in January 2023, the RTF
updated the ASHP workbook. With the recently updated RTF workbook version 7.1, the ASHP
included a mix of program practices, which includes programs with and without CCS
requirements, into the development of the deemed savings values. Going forward, Idaho Power
will not be adding CCS savings since it will be embedded in the ASHP savings from the RTF.
Training
The evaluators recommended Idaho Power provide additional training to the Participating
Contractors administering the ducted air-source heat pump measure to ensure requirements are
being met for the Performance Tested Comfort System savings adder from the RTF. Idaho Power
will continue providing additional training to contractors to help them meet program
requirements for this measure.
It was recommended Idaho Power reach out to existing contractors using trainings, in-person
visits, and other methods to maintain and develop relationships. Idaho Power continues to
provide trainings and arrange visits with contractors to maintain and grow the relationships.
Idaho Power’s relationships with the contractors has been a strong asset to the program’s
performance.
The evaluators recommended Idaho Power provide additional efforts to provide educational
training to build contractor awareness of the program and its requirements. Idaho Power will
continue to provide training to existing and new contractors to increase their participation in
the program. Idaho Power understands the reasons for a contractor’s lack of participation can
be complex. The program does require contractors to have existing technical knowledge of heat
pumps to perform the program requirements. To help address that need, Idaho Power works
directly with contractors to increase their technical knowledge. As additional Idaho Power
resources become available, those resources will be made available to assist contractors.
The evaluators recommended Idaho Power provide instructional education for homeowners
self-installing smart thermostats through the program. It was also recommended that the
incentive be increased to encourage the homeowners to have their smart thermostat installed
Residential Sector—Heating & Cooling Efficiency Program
Demand-Side Management 2022 Annual Report Page 65
properly to their equipment. Idaho Power provides educational guidance on the measure web
landing page describing the importance of setting up key energy impacting features on these
thermostats. An increase in the incentive amount is not planned. This is due to
cost-effectiveness constraints and the belief that the homeowner’s technical ability is not
proportional to the incentive amount.
Marketing/Outreach/Incentives
Another recommendation was that Idaho Power invest in more marketing and outreach with
timing sensitive to customer’s propensity to be engaged in home upgrade projects. A focus on
Smart Thermostats was also recommended. Idaho Power believes the amount and types of
marketing tactics being used by the program are correct and have appropriate timing.
Measure level and portfolio-level tactics are used. Idaho Power continues to adjust the
program’s marketing tactics and frequency to maximize the effectiveness of the
messaging content.
It was recommended Idaho Power create a qualified products list for the smart thermostat
incentive to ensure the features required by the RTF are present on the thermostat brands and
models that receive the incentive. The smart thermostat products available and their features
are evolving constantly, rendering a qualified products list impractical. Idaho Power does
consider all information provided by the RTF and will adjust this measure as necessary.
Additionally, with the recent updates to smart thermostat savings from the RTF, the retail
do-it-yourself option will need to be modified or removed from the program offering.
Another recommendation was that Idaho Power increase the customer incentive amounts for
existing measures and expand the number of measures offered. An increase to the contractor
stipend was also recommended for heat pump installations. Idaho Power continues to expand
the program measures, most recently with two new measures added July 1, 2022.
Incentive amounts and contractor stipends are periodically reviewed. Idaho Power will
continue to review these incentives and stipend amounts and will adjust them as necessary,
considering cost-effectiveness of the measure and the program as a whole.
It was recommended Idaho Power engage with the RCEAs to obtain their help in promoting the
program. Idaho Power has engaged with its residential and commercial energy advisors on this
program and will continue to do so in the future; residential and commercial energy advisors
have been and continue to be a helpful resource to keep vendors and customers informed
about the program measures.
The evaluators recommended working with the supply chain to understand the local availability
of ducted heat pumps and their associated HSPFs. An incentive for distributors was
recommended to motivate distributors to encourage contractors to install higher efficient units.
Idaho Power interacts with and understands the local heat pump supply chain and their mix of
Residential Sector—Heating & Cooling Efficiency Program
Page 66 Demand-Side Management 2022 Annual Report
heat pumps and associated HSPFs. Idaho Power does not believe a distributor tier incentive is
needed to motivate contractors into selling higher efficiency DHPs because the installing
contractors already determine what the best solution is for their customer’s individual needs.
RTF Workbooks
The evaluators recommended Idaho Power continue to require additional documents to verify
the components for PTCS certification to ensure future RTF workbooks remain applicable.
This recommendation applies to the ducted ASHP measure. Idaho Power will continue to
require and collect this information using the required program forms. For example, the
evaluator suggested collecting additional documents listing heat pump British thermal units
(BTU) outputs at 17° F and 47° F. These outputs are contained in the required Air-Conditioning,
Heating, and Refrigeration Institute (AHRI) Certificate of Product Ratings. The program forms
were updated in 2022 and reflect the new PTCS standard released in April 2022 by the BPA.
The evaluators recommended Idaho Power continue analyzing impacts of the RTF’s
commissioning, controls, and sizing (CCS) workbook through measurement or billing analysis
until the RTF presents a new workbook to replace the workbook deactivated in 2020.
[This recommendation applies to the ducted ASHP measure.] With the recently updated RTF
workbook version 7.1, a mix of program practices were embedded in the savings, including
programs with and without CCS requirements. However, the program will continue to require
the participating contractors to adhere to CCS as it has since the inception of the measure. In
early 2023 the program will broadcast the new BPA CCS specifications that were launched April
2022. This will involve contractor training, incentive application form redesign, and internal
systems and website edits. BPA continues to advocate for proper CCS and continues to research
its impact on savings. Idaho Power will look to the BPA research to see what can be done for
CCS going forward.
Another recommendation was that Idaho Power continue to use the RTF Connected Thermostat
workbook to evaluate savings for the Smart Thermostat measure. The evaluators suggested
revisiting the billing analysis provided by the evaluators when additional self-installed incentives
are processed. Idaho Power will continue to use the most recently acknowledged RTF workbook
at the time of program planning for the following year. The RTF recently updated the connected
thermostat workbook in January 2022 and reduced the savings for self-installed thermostats
from a simple average of 718 kWh to 295 kWh. These revised savings are more closely aligned
to the savings the evaluators found in the billing analysis. In 2023, Idaho Power will determine
how the program will need to be modified in the future to address the lower savings from the
self-installed smart thermostats.
2023 Plans
Idaho Power will continue to provide program training to existing and prospective contractors
to assist them in meeting program requirements and further their product knowledge.
Residential Sector—Heating & Cooling Efficiency Program
Demand-Side Management 2022 Annual Report Page 67
Training remains an important part of the program because it creates the opportunity to invite
additional contractors into the program, is a refresher for contractors already participating in
the program, and helps them increase their customers’ participation while improving the
contractors’ work quality and program compliance.
Idaho Power’s primary goals in 2023 are to develop contractors currently in the program while
adding new contractors. To meet these goals, the program specialist will frequently interact
with contractors in 2023 to discuss the program.
The 2023 marketing strategy will include bill inserts, direct-mail, social media, digital and search
advertising, and email marketing to promote individual measures as well as the
overall program.

Residential Sector—Home Energy Audit
Page 68 Demand-Side Management 2022 Annual Report
Home Energy Audit
2022 2021
Participation and Savings
Participants (homes) 425 37
Energy Savings (kWh) 28,350 3,768
Demand Reduction (MW) n/a n/a
Program Costs by Funding Source
Idaho Energy Efficiency Rider $184,650 $70,448
Oregon Energy Efficiency Rider $0 $0
Idaho Power Funds $208 $0
Total Program Costs—All Sources $184,858 $70,448
Program Levelized Costs
Utility Levelized Cost ($/kWh) $0.771 $2.173
Total Resource Levelized Cost ($/kWh) $1.000 $2.328
Benefit/Cost Ratios
Utility Benefit/Cost Ratio n/a n/a
Total Resource Benefit/Cost Ratio n/a n/a
Description
Under the Home Energy Audit program, a certified, third-party home performance specialist
conducts an in-home energy audit to identify areas of concern and provide specific
recommendations to improve the efficiency, comfort, and health of the home. The audit
includes a visual inspection of the crawlspace and attic, a health and safety inspection, and a
blower door test to identify and locate air leaks. The home performance specialist collects
information on types and quantities of appliances and lighting in each home, then determines
which available energy efficiency measures are appropriate. Homeowners and/or landlords
approve all direct-install measures prior to installation, which could include the following:
• Up to 20 LED lightbulbs
• One high-efficiency showerhead
• Pipe insulation from the water heater to the home wall (approximately 3 feet [ft])
• Tier 2 Advanced Power Strip
The home performance specialist collects energy-use data and records the quantity of
measures installed during the audit using specialized software. After the audit, the auditor
writes up the findings and recommendations, and the software creates a report for
the customer.
To qualify for the Home Energy Audit program, a participant must live in Idaho and be the
Idaho Power customer of record for the home. Renters must have prior written permission
Residential Sector—Home Energy Audit
Demand-Side Management 2022 Annual Report Page 69
from the landlord. Single family site-built homes, duplexes, triplexes, and fourplexes qualify,
though multifamily homes must have discrete heating units and meters for each unit.
Manufactured homes, new construction, or buildings with more than four units do not qualify.
Interested customers fill out an application online. If they do not have access to a computer,
or prefer talking directly to a person, Idaho Power accepts applications over the phone.
Participants are assigned a home performance specialist based on geographical location to save
travel time and expense.
Participating customers pay $99 (all-electric homes) or $149 (other homes: gas, propane,
or other fuel sources) for the audit and installation of measures, with the remaining cost
covered by the Home Energy Audit program. The difference in cost covers the additional testing
necessary for homes that are not all-electric. These types of energy audits normally cost $300
or more, not including the select energy-saving measures, materials, and labor. The retail cost
of the materials available to install in each home is approximately $145.
Program Activities
Two home performance specialist companies served the program in 2022 and completed
425 energy audits. The number and percentage of audited homes per heating fuel type
are listed in Table 12.
Table 12. Number and percentage of audited homes per heating fuel type
Fuel Type Number of Homes Percent
Electric ................................................... 168 39.53%
Natural Gas ............................................ 237 55.76%
Oil .......................................................... 2 0.47%
Pellets .................................................... 7 1.65%
Propane ................................................. 7 1.65%
Wood ..................................................... 4 0.94%

Quality assurance (QA) for the program has been suspended since 2020 due to COVID-19
restrictions and the ramp-up time to complete projects in the pipeline as a result. The QA for
2022 projects will occur in 2023, and Idaho Power is exploring the potential to transition to a
survey format to both work through the pipeline of QAs and reduce program costs.
Marketing Activities
To allow contractors to work through the long waitlist of interested customers that was created
when in-home work was suspended in 2020 and 2021, Home Energy Audit marketing was
limited in 2022.
Residential Sector—Home Energy Audit
Page 70 Demand-Side Management 2022 Annual Report
Although there was still a waitlist throughout 2022, a bill insert was sent to 295,109 residential
customers in July to help maintain program visibility. Website updates were made throughout
the year to keep program details up to date.
Customers who enrolled in the Home Energy Audit program throughout the year were asked
where they heard about the program. Responses included the following: information in the
mail, 19.81%; family member or friend, 14.45%; Idaho Power employee, 13.29%; social media,
3.50%; other, 47.78%; did not reply, 1.17%.
Cost-Effectiveness
One of the goals of the Home Energy Audit program is to increase participants’ understanding
of how their home uses energy and to encourage their participation in Idaho Power’s energy
efficiency programs. Because the Home Energy Audit program is primarily an educational and
marketing program, the company does not use the traditional cost-effectiveness tests.
For the items installed directly in the homes, Idaho Power used the RTF savings for direct-install
lightbulbs, which range from 4.73 to 14.21 kWh per year. This was a slight change over the
2021 lightbulb savings, which ranged from 4.68 to 17.59 kWh per year depending on lightbulb
type and installation location.
In Idaho Power’s Energy Efficiency Potential Study, it is estimated that pipe wraps save 76 kWh
per year. Savings for pipe wrap are counted for homes with electric water heaters.
While Idaho Power does not calculate a cost-effectiveness ratio for the Home Energy Audit
program, the savings benefits and costs associated with direct-install measures have been
included in the sector and portfolio cost-effectiveness. Idaho Power also converted the 76 kWh
of pipe wrap savings to 2.59 therms and those gas savings are included in the sector and
portfolio cost-effectiveness as non-energy benefits.
2023 Plans
The program will be lightly marketed in 2023 while contractors continue to work through the
waitlist. Once most customers have been served, Idaho Power will resume recruiting
participants through small batches of targeted direct-mailings, social media posts, advertising,
and bill inserts. Additional digital advertising may be considered if the program needs to be
strategically promoted in specific regions.

Residential Sector—Home Energy Report Program
Demand-Side Management 2022 Annual Report Page 71
Home Energy Report Program
2022 2021
Participation and Savings
Participants (homes) 104,826 115,153
Energy Savings (kWh)* 20,643,379 15,929,074
Demand Reduction (MW) n/a n/a
Program Costs by Funding Source
Idaho Energy Efficiency Rider $964,709 $970,197
Oregon Energy Efficiency Rider $0 $0
Idaho Power Funds $82 $0
Total Program Costs—All Sources $964,791 $970,197
Program Levelized Costs
Utility Levelized Cost ($/kWh) $0.044 $0.057
Total Resource Levelized Cost ($/kWh) $0.044 $0.057
Benefit/Cost Ratios**
Utility Benefit/Cost Ratio 0.71 0.57
Total Resource Benefit/Cost Ratio 0.79 0.62
*2021 reported savings of 16,767,446 kWh discounted by 5% to account for potential double-counting of savings from other programs. 2022 reported savings of 20,734,611 kWh discounted by 0.44% based on evaluated double-counting estimate
**Home Energy Report Program cost-effectiveness also calculated on a program life-cycle basis to account for savings persistence once
treatment ends. The program has a life cycle UCT and TRC of 1.17 and 1.29, respectively.

Description
The objective of the HER Program is to encourage customers to engage with their home’s
electricity use with a goal to produce average annual behavioral savings of 1 to 3%. The
program also promotes customer use of online tools and participation in other energy
efficiency programs. Idaho Power works with a third-party contractor to operate the program.
Participants receive periodic reports with information about how their homes’ energy use
compares with similar homes. The Home Energy Reports also give a breakdown of household
energy use and offer suggestions to help customers change their energy-related behaviors.
The program contractor estimates energy savings by completing a statistical comparison of the
energy used by customers who receive the reports against the energy used by a control group.
Since the savings estimates rely on the integrity of the experimental design, participants in both
the treatment (those receiving reports) and the control group are selected through a process
of randomization.
Program Activities
In 2022, all HER Program participants received quarterly reports in the months of February,
May, August, and November.
Residential Sector—Home Energy Report Program
Page 72 Demand-Side Management 2022 Annual Report
In addition to showing participants how their energy compared relative to similar homes,
each quarterly report delivered in 2022 addressed weather-related usage, as appropriate, along
with other tips related to appliances, lighting, and always-on devices. The February reports
recommended either ways to reduce electric heating costs or ways to cut energy costs
associated with laundry and small kitchen appliances. In May, customers with significant A/C
use during the previous summer received tips to reduce upcoming cooling bills while others
learned about energy audits. The August reports were, once again, segmented between
participants with significant A/C use and those whose energy use was less affected by weather.
In November, customers with electric space heating received information regarding their
previous winter’s use along with heating tips while the remaining customers were divided into
those using electric hot water heaters and those who did not.
In an effort to increase customer engagement and program savings, Idaho Power began
sending email reports (eHER), in addition to paper reports, to participants for whom Idaho
Power had an email address on file. Over 52,000 eHERs were delivered in August, compared to
just 53 in May. The open rate was high (49%), and the call-in rate remained low. Following the
August reports, 185 participants permanently switched to email only delivery.
In 2022, as in 2021, the savings results for the pilot participants identified as electric heating
customers were not statistically significant as stand-alone cohorts; however, these participants
did contribute to the overall program savings. The participants joining the program in 2020
once again saw increases in both their savings percentage and kWh savings per customer,
increasing from 0.98% to 1.35% and from 144.28 kWh to 206.61 kWh, respectively. On average,
the combined group of active participants used an average of 200.74 fewer kWh per home than
their control group counterparts. When viewed in aggregate, the estimated savings for all
program participants was about 1.31% below their respective control groups, for a total
reported savings of 20,474,995 kWh. The small group of customers who received their last
report in February of 2020 continued to demonstrate persistent savings. With their residual
savings included, total 2022 reported program savings came to 20,734,611 kWh. On average,
program participants are providing savings at between 56 to 267 kWh annually per home.
Idaho Power’s customer solutions advisors responded to 409 HER Program-related phone calls
during the year. Given that 505,735 reports were delivered, this represents a call rate of just
under 0.08%. The participant-driven opt-out rate was down from 0.17% in 2021 to 0.08% in
2022—significantly lower than the industry average of 1%. Overall attrition in 2022 was
6.92%—down slightly from 7.82% in 2021 (includes opt-outs, move-outs, etc.).
Residential Sector—Home Energy Report Program
Demand-Side Management 2022 Annual Report Page 73

Figure 18. Page 1 of a sample Home Energy Report
Marketing Activities
Because the HER Program is based on a randomized control trial (RCT) methodology,
the reports cannot be requested by customers, therefore the program is not marketed.
The periodic reports were, however, used to cross-market Idaho Power’s other energy
efficiency programs (i.e., Home Energy Audits, H&CE Program, and ENERGY STAR® lighting), as
well as Account Alerts and My Account.
Residential Sector—Home Energy Report Program
Page 74 Demand-Side Management 2022 Annual Report
Cost-Effectiveness
HER Program savings are calculated each year using measured usage of the customers receiving
the reports relative to a statistically similar control group that does not receive the reports.
Due to the potential of double-counting savings from other programs, Idaho Power discounts
the HER Program savings of 20,734,611 kWh by 0.44% to report savings of 20,643,379 kWh.
This percentage was reviewed as part of the 2022 impact evaluation. Based on the reported
savings of 20,643 MWh, the UCT and TRC for the program are 0.71 and 0.79, respectively,
for 2022. If the amount incurred for the 2022 evaluation was removed from the program’s cost-
effectiveness, the UCT would be 0.74, while the TRC would be 0.81.
Due to the continuous nature of the HER Program with costs and savings extending over
numerous years for the same participants, a program life cost-effectiveness is used to
understand the cost-effectiveness of the program as a whole. The analysis uses 2020 as the
start year and assumes the program continues to send reports until the current contract ends in
2023. Savings per participant decrease at 20% per year from 2024 through 2026, at which point
it is assumed the treatment no longer impacts the participants. Total participation also declines
at 10% per year, which is the approximate observed annual attrition for the program.
The life-time analysis has been updated to incorporate the 2022 program performance and
updated 2023 savings projections from the third party. In late 2022, the IPUC and the OPUC
formally acknowledged Idaho Power’s 2021 IRP. The demand-side management avoided costs
from the 2021 IRP are used to provide the monetary value for the energy savings in 2023
and beyond.
In February 2022, the RTF proposed guidelines for reviewing cost-effectiveness for behavioral
programs. The company reviewed these guidelines and incorporated the concepts into the
lifetime cost-effectiveness analysis. This lifetime analysis calculates UCT and TRC ratios of
1.17 and 1.29, respectively.
For more detailed information about the cost-effectiveness savings and assumptions,
see Supplement 1: Cost-Effectiveness.
Evaluations
In 2022, Idaho Power contracted a third-party evaluator to conduct an impact evaluation
for the HER Program. The evaluation report for the HER Program was completed in
September 2022. See Supplement 2: Evaluation for the complete report.
Recommendations were as follows:
The evaluators recommend that Idaho Power and the implementer continue to prioritize the
validity of each treatment and control group in order to maintain ability to estimate program
savings. Previous changes throughout the program have resulted in maintenance of group
validity due to additional steps relating to randomization, validity checks, and prioritization of
Residential Sector—Home Energy Report Program
Demand-Side Management 2022 Annual Report Page 75
statistical validity. The evaluators recommend IPC continue such efforts to ensure future
program savings are evaluable and quantifiable. Idaho Power and the implementer are aware
of the complexity involved in the various control and treatment groups established during the
pilot program and 2020 expansion and will continue to maintain the validity of each group
according to industry best practices as established by the National Renewable Energy
Laboratory’s (NREL) Behavioral Programs Guide.
Although the pilot phase of the program indicated that low to medium annual energy users
displayed low propensity for energy savings, the evaluators found that these users (group T5)
have displayed high persistence savings in recent years. Therefore, the evaluators recommend
that Idaho Power allow customers with low to medium annual energy use to be eligible for
participation in the program for any and all future group expansions. At present, the company
does not have plans to expand the program; however, Idaho Power will closely monitor the
persistent savings for T5 and use those findings to inform decisions surrounding any
future expansion.
The evaluators recommend that Idaho Power continue to include customers that have converted
from I01 rate schedule (general residential rate) to I06 rate schedule (customer generation rate)
in the T1 through T6 groups and refrain from reallocating them to another treatment group.
This will ensure that all legacy groups remain statistically valid and evaluable. Idaho Power will
continue to include I06 customers in their original T1/C1 through T6/C6 groups for evaluation
purposes. When a HER participant transitions from the I01 to the I06 rate schedule, however,
quarterly HERs will be discontinued as the home comparison no longer applies. This is
consistent with current practice.
The evaluators recommend that if a group is designed for the program in the future, that the
lack of benchmarking characteristics is not used as a prerequisite for participation. This will
ensure that the maximum number of customers are eligible for the Home Energy Report
Program and therefore the program retains higher potential for total program energy savings.
Idaho Power will take this recommendation under consideration. The delivery of accurate and
useful information is critical to a positive customer experience. Further, the implementer has
requirements regarding adequately sized benchmark groups. If a future expansion occurs,
Idaho Power will consult industry best practices and confer with the selected implementer,
as well as other stakeholders.
2023 Plans
Idaho Power plans to continue to deliver Home Energy Reports to active program participants
on a quarterly schedule with reports arriving in February, May, August, and November.
Participants with high A/C use or winter heating will also receive seasonal reports in either
May or November, as appropriate.
Residential Sector—Home Energy Report Program
Page 76 Demand-Side Management 2022 Annual Report
As Home Energy Reports delivery is slated to end at the conclusion of 2023 under the current
contract, Idaho Power will actively review the program’s cost-effectiveness, overall savings, and
customer experience with an eye to selecting the best option(s) going forward.
Residential Sector—Multifamily Energy Savings Program
Demand-Side Management 2022 Annual Report Page 77
Multifamily Energy Savings Program
2022 2021
Participation and Savings
Projects (units [buildings]) 97 [3] 0
Energy Savings (kWh) 41,959 0
Demand Reduction (MW) n/a n/a
Program Costs by Funding Source
Idaho Energy Efficiency Rider $32,634 $65,525
Oregon Energy Efficiency Rider $1,474 $3,449
Idaho Power Funds $72 $0
Total Program Costs—All Sources $34,181 $68,973
Program Levelized Costs
Utility Levelized Cost ($/kWh) $0.096 n/a
Total Resource Levelized Cost ($/kWh) $0.096 n/a
Benefit/Cost Ratios
Utility Benefit/Cost Ratio 0.49 n/a
Total Resource Benefit/Cost Ratio 0.68 n/a
Description
The Multifamily Energy Savings Program provides for the direct installation of energy-saving
products in multifamily dwellings with electrically heated water in Idaho and Oregon.
These energy-saving products are installed by an insured contractor hired by Idaho Power at no
cost to the property owner, manager, or tenant. Idaho Power defines a multifamily dwelling as
a building consisting of five or more rental units. The products installed include the following:
ENERGY STAR® LED lightbulbs, high-efficiency thermostatic shower valve (TSV) showerheads,
kitchen and bathroom faucet aerators, and water heater pipe insulation.
To ensure energy savings and eligibility, Idaho Power pre-approves each building and the
contractor who will install the energy efficiency measures. Upon approval, the no-cost, direct
installation is scheduled, and a tailored door hanger is placed on tenants’ apartments to explain
the schedule and process of the installation.
Program Activities
Due to the program becoming not cost-effective and with the support of EEAG, the program
was closed December 31, 2022. Before its closing, three direct-installation projects were
completed in 2022. One each in the South–East, Canyon–West, and Capital regions for a
combined total of 92 units and five common-area spaces.
Residential Sector—Multifamily Energy Savings Program
Page 78 Demand-Side Management 2022 Annual Report
Marketing Activities
Idaho Power continued to run three alternating, clickable ads on its Landlord/Property Manager
Requests web page that linked users to the Multifamily Energy Savings Program web page.
A marketing video placed at the top of the Multifamily Energy Savings Program web page also
continued to run in 2022. The video explains the eligibility requirements, the no-cost
direct-install measures available to landlords/tenants, the installation process, and the
potential for residents to save on their monthly bills and to be more comfortable in their
homes. At the end of the video, company contact information is provided.
In April, the program specialist participated in the Idaho Apartment Association Conference and
Trade Show to market the program to property owners and managers; Idaho Power placed a
print ad in the trade show program
Cost-Effectiveness
The UCT and TRC of the program are 0.49 and 0.68, respectively.
Due to the reduction of savings for the deemed measure options, the program in its current
format is unable to remain cost-effective going forward. The RTF is the source of savings for
many of the measures in the program. Based on the RTF version 9.4 lighting workbook,
these savings now range between 4.73 to 13.81 kWh. To improve the accuracy of the data
being collected, Idaho Power modified the installation worksheets. For lightbulbs installed in
interior locations, Idaho Power had previously used a simple blend of savings for high- and
moderate-use direct-install savings. With the updated savings worksheets, Idaho Power is able
to directly assign the appropriate RTF direct-install savings. Additionally, some lightbulbs were
installed in common areas, such as laundry rooms, hallways, and stairways. The updated
worksheet was used to calculate the lighting savings for each install based on information
around the existing lamp and the location of the installation. However, there are still challenges
related to the other direct-install items with the company no longer able to claim savings for
faucet aerators and the integrated showerhead with the TSV claiming only 50 kWh of
annual savings.
Idaho Power shared these challenges with EEAG in 2021 and 2022. The company held a small
subcommittee meeting in early 2022 to discuss the savings assumptions around the program
and alternatives to the current direct-install retrofit model. The company was directed to reach
out to the ETO to learn more about their multifamily program. ETO faced similar
cost-effectiveness challenges with their direct-install multifamily program and suspended it in
2020. Based on the inability to run the direct-install program cost-effectively, Idaho Power
announced to EEAG its intent to close the program in 2022. A prescriptive-based incentive
program is being explored as an alternative cost-effective option for customers.
Residential Sector—Multifamily Energy Savings Program
Demand-Side Management 2022 Annual Report Page 79
For more detailed information about the cost-effectiveness savings and assumptions,
see Supplement 1: Cost-Effectiveness.
2023 Plans
Due to the closing of the program as of December 31, 2022, there are no activities planned for
2023, however, Idaho Power continues to pursue alternative program options for multifamily
residences and believes it will have some type of new offering available in 2023.

Residential Sector—Oregon Residential Weatherization
Page 80 Demand-Side Management 2022 Annual Report
Oregon Residential Weatherization
2022 2021
Participation and Savings
Participants (audits/projects) 7 0
Energy Savings (kWh) 0 0
Demand Reduction (MW) n/a n/a
Program Costs by Funding Source
Idaho Energy Efficiency Rider $0 $0
Oregon Energy Efficiency Rider $8,825 $4,595
Idaho Power Funds $0 $0
Total Program Costs—All Sources $8,825 $4,595
Program Levelized Costs
Utility Levelized Cost ($/kWh) n/a n/a
Total Resource Levelized Cost ($/kWh) n/a n/a
Benefit/Cost Ratios
Utility Benefit/Cost Ratio n/a n/a
Total Resource Benefit/Cost Ratio n/a n/a

Description
Idaho Power offers free energy audits for electrically heated customer homes within the
Oregon service area. This is a program required by Oregon Revised Statute (ORS) 469.633
and has been offered under Oregon Tariff Schedule 78 since 1980. Upon request, an energy
audit contractor hired by Idaho Power visits the customer’s home to perform a basic energy
audit and to analyze it for energy efficiency opportunities. An estimate of costs and savings
for recommended energy-efficient measures is given to the customer. Customers may choose
either a cash incentive or a 6.5%-interest loan for a portion of the costs for
weatherization measures.
Program Activities
Seven audits were completed in 2022. None of the audit customers chose to pursue energy
efficiency upgrades.
Marketing Activities
In October, Idaho Power sent 10,336 Oregon residential customers an informational brochure
about energy audits and home weatherization financing.
Cost-Effectiveness
The Oregon Residential Weatherization program is a statutory program described in Oregon
Schedule 78, which includes a cost-effectiveness definition of this program. Pages three and
Residential Sector—Oregon Residential Weatherization
Demand-Side Management 2022 Annual Report Page 81
four of Schedule 78 identify the measures determined to be cost-effective and the specified
measure life cycles for each. This schedule also includes the cost-effective limit (CEL) for
measure lives of 7, 15, 25, and 30 years.
2023 Plans
Idaho Power will continue to market the program to customers with a bill insert/brochure.

Residential Sector—Rebate Advantage
Page 82 Demand-Side Management 2022 Annual Report
Rebate Advantage
2022 2021
Participation and Savings
Participants (homes) 97 88
Energy Savings (kWh) 255,541 235,004
Demand Reduction (MW) n/a n/a
Program Costs by Funding Source
Idaho Energy Efficiency Rider $157,746 $164,243
Oregon Energy Efficiency Rider $9,762 $8,950
Idaho Power Funds $115 $0
Total Program Costs—All Sources $167,622 $173,193
Program Levelized Costs
Utility Levelized Cost ($/kWh) $0.043 $0.046
Total Resource Levelized Cost ($/kWh) $0.104 $0.088
Benefit/Cost Ratios
Utility Benefit/Cost Ratio 1.18 1.13
Total Resource Benefit/Cost Ratio 0.54 0.66

Description
Initiated in 2003, the Rebate Advantage program helps Idaho Power customers in Idaho and
Oregon with the initial costs associated with purchasing new, energy-efficient, ENERGY STAR®
qualified manufactured homes. This enables the homebuyer to enjoy the long-term benefit of
lower electric bills and greater comfort. The program also provides an incentive to the sales
consultants to encourage more sales of ENERGY STAR qualified homes and more discussion of
energy efficiency with their customers during the sales process.
In addition to offering financial incentives, the Rebate Advantage program educates
manufactured home buyers and retailers about the benefits of owning energy-efficient models.
The Northwest Energy-Efficient Manufactured Housing Program™ (NEEM), a consortium of
manufacturers and state energy offices in the Northwest, establishes quality control (QC) and
energy efficiency specifications for qualified manufactured homes and tracks their production
and on-site performance. NEEM adds the classification Eco-Rated™ for homes produced by
factories that have demonstrated a strong commitment to minimizing environmental impacts
from the construction process.
In 2019, NEEM created the most stringent manufactured home energy standard in the country,
the ENERGY STAR with NEEM 2.0 specification, which was later renamed the ENERGY STAR with
NEEM+ certification. NEEM+ standards are engineered to save approximately 30% more energy
than ENERGY STAR standards. As a result, NEEM+ delivers the highest possible energy savings
Residential Sector—Rebate Advantage
Demand-Side Management 2022 Annual Report Page 83
and the highest level of overall comfort. These homes are built to specifications tailored to the
Northwest climate.
Program Activities
In 2022, for each home sold under this program, the residential customer incentive was $1,000
and the sales staff incentive was $200. Idaho Power paid 97 incentives on new manufactured
homes, which accounted for 255,541 annual kWh savings. This included 91 homes sited in
Idaho and six sited in Oregon. Of the 97 homes in the program, 25 were NEEM+, 61 were
ENERGY STAR, and 11 were Eco-Rated.
Marketing Activities
Idaho Power continued to support manufactured home dealerships by providing them with
program marketing collateral.
In April and October, Idaho Power promoted the Rebate Advantage program with a bill insert
sent to 306,888 and 298,681 customers, respectively. The insert had information about the
potential energy and cost savings and referred customers to the program website.
In July, the company ran programmatic display ads that garnered 661,299 impressions and
463 clicks through to the website.
In the September issue of Idaho Power’s Get Your Home Ready for Fall all-customer energy
efficiency tips email, the Rebate Advantage program was featured in a digital banner ad.
When clicked, it would take customers to the Rebate Advantage web page.
Cost-Effectiveness
The UCT and TRC for the program are 1.18 and 0.54, respectively.
In 2022, Idaho Power used the same savings and assumptions source as were used in 2021.
However, the number of NEEM 2.0 certified homes increased from 13 homes in 2021 to 25
homes in 2022. Manufactured homes certified under NEEM have higher savings than
ENERGY STAR certified manufactured homes and are more expensive. This accounts for the
slight increase in UCT and decrease in TRC as compared to 2021.
For detailed information for all measures within the Rebate Advantage program,
see Supplement 1: Cost-Effectiveness.
2023 Plans
Idaho Power plans to review the cost-effectiveness and feasibility of the updated Housing and
Urban Development (HUD)/ENERGY STAR v3.0 manufactured homes code that goes into effect
on May 31, 2023, in conjunction with NEEM and NEEA.
Idaho Power will continue to support manufactured home dealers by providing them with
program materials. The company will also distribute a bill insert to Idaho and Oregon
Residential Sector—Rebate Advantage
Page 84 Demand-Side Management 2022 Annual Report
customers and explore digital advertising to promote the program to potential manufactured
home buyers.

Residential Sector—Residential New Construction Program
Demand-Side Management 2022 Annual Report Page 85
Residential New Construction Program
2022 2021
Participation and Savings
Participants (homes) 109 90
Energy Savings (kWh) 337,562 389,748
Demand Reduction (MW) n/a n/a
Program Costs by Funding Source
Idaho Energy Efficiency Rider $236,962 $246,245
Oregon Energy Efficiency Rider -$1,356* $1,356
Idaho Power Funds $126 $0
Total Program Costs—All Sources $235,732 $247,600
Program Levelized Costs
Utility Levelized Cost ($/kWh) $0.045 $0.039
Total Resource Levelized Cost ($/kWh) $0.110 $0.082
Benefit/Cost Ratios
Utility Benefit/Cost Ratio 1.45 1.64
Total Resource Benefit/Cost Ratio 0.84 0.99
*2021 Oregon activity of $1,356 was reversed and charged to the Idaho Rider in the first quarter of 2022.
Description
The Residential New Construction Program launched in March 2018 as a pilot, replacing the
ENERGY STAR® Homes Northwest Program, and transitioned to a regular program in 2021.
The Residential New Construction Program offers builders a cash incentive to build energy
efficient, single-family, all-electric homes that use heat pump technology in Idaho Power’s
Idaho service area. These homes must meet strict requirements that make them 10%, 15%,
or 20% more energy efficient than homes built to standard state energy code.
The RTF and NEEA have created specific modeling requirements and program guidelines to
ensure the program provides reliable energy savings for utilities across the northwest.
These homes feature high-performance HVAC systems, high-efficiency windows,
increased insulation values, and tighter building shells to improve comfort and save energy.
Idaho Power claims energy savings based on each home’s individual modeled savings.
Builders must contract with a Residential Energy Services Network (RESNET)-certified rater to
ensure the home design will meet program qualifications. The rater will work with the builder
from the design stages through project completion; perform the required energy modeling
(REM) using REM/Rate modeling software; perform site inspections and tests; and enter,
maintain, and submit all required technical documentation in the REM/Rate modeling software
and the NEEA-maintained AXIS database. This data is used to determine the energy savings and
the percent above code information needed to certify the home.
Residential Sector—Residential New Construction Program
Page 86 Demand-Side Management 2022 Annual Report
Program Activities
Participating residential builders who built homes at least 10% above the standard state energy
code, as determined by the REM/Rate energy modeling software and AXIS database output,
were incentivized as follows:
• 10 to 14.99% above code: $1,200 incentive
• 15 to 19.99% above code: $1,500 incentive
• 20% or more above code: $2,000 incentive
In 2022, the company paid incentives for 109 newly constructed energy-efficient homes in
Idaho, and the homes accounted for 337,562 kWh of energy savings.
Idaho Power continued its contract with Washington State University Energy Program to
perform both file and field QA services on home energy ratings performed by the program
raters. The university’s contract also includes new rater training/on-boarding as well as working
with current rater technical problems/issues.
Marketing Activities
Idaho Power participated in the Snake River Valley Building Contractors Association (SRVBCA)
and the Building Contractors Association of Southwestern Idaho (BCASWI) Builders’ Expos and
sent marketing materials to the winter and fall Idaho Building Contractors Association (IBCA)
Board Meetings.
Idaho Power supported 2022 Parade of Homes events with full-page ads in the Parade of
Homes magazines of the following BCAs: The Magic Valley Builders Association (MVBA), the
BCASWI, the SRVBCA, and the Building Contractors Association of Southeast Idaho (BCASEI).
A print ad appeared in the April construction issue of the Idaho Business Review publication.
A digital app ad and company listing was also included as part of the advertising package with
the MVBA.
The company sent a bill insert to 305,714 Idaho customers in May to promote the program.
The program brochure was left at the City of Boise permitting office as a hard copy handout.
Cost-Effectiveness
The savings for the 109 energy-modeled homes average approximately 3,097 kWh per home
depending on which efficiency upgrades were included, a decrease over the average
energy-modeled savings of 4,331 kWh per home in 2021. The decrease was largely due to a
couple of factors: a lower percentage of homes built in 2022 (30%) were built 20% or more
above code, relative to homes built in 2021 (63%); and a lower percentage of homes built in
2022 were detached single-family homes (8%), relative to homes built in 2021 (33%).
Residential Sector—Residential New Construction Program
Demand-Side Management 2022 Annual Report Page 87
Single-family homes tend to have larger savings when compared to attached townhomes
and condos.
While savings are custom calculated for each of the 109 modeled homes, the incremental costs
over a code-built home are difficult to determine. The RTF’s single-family new construction
workbook was used as a proxy for the incremental costs and non-energy benefits (NEB).
The UCT and TRC ratios for the program are 1.45 and 0.84, respectively.
2023 Plans
Idaho Power plans to continue to promote this program to Idaho builders and new home
buyers. These marketing efforts include ads in Parade of Homes magazines for the BCASWI,
SRVBCA, MVBA, and the BCASEI. A bill insert is planned for spring 2023. The company also plans
to continue supporting the general events and activities of the IBCA and its local affiliates.
Social media and other advertising will be considered based on past effectiveness.

Residential Sector—Shade Tree Project
Page 88 Demand-Side Management 2022 Annual Report
Shade Tree Project
2022 2021
Participation and Savings
Participants (trees) 1,874 2,970
Energy Savings (kWh)* 39,595 44,173
Demand Reduction (MW) n/a n/a
Program Costs by Funding Source
Idaho Energy Efficiency Rider $128,673 $184,680
Oregon Energy Efficiency Rider $0 $0
Idaho Power Funds $183 $0
Total Program Costs—All Sources $128,856 $184,680
Program Levelized Costs
Utility Levelized Cost ($/kWh) $0.218 $0.269
Total Resource Levelized Cost ($/kWh) $0.218 $0.269
Benefit/Cost Ratios*
Utility Benefit/Cost Ratio 1.02 1.07
Total Resource Benefit/Cost Ratio 1.21 1.21
* Incremental savings for trees planted between 2013–2018 not claimed in previous years.
Description
Idaho Power’s Shade Tree Project operates in a small geographic area each spring and fall,
offering no-cost shade trees to Idaho residential customers. Participants enroll using the online
Energy-Saving Trees tool and pick up their tree at specific events or have trees delivered to
their doors. Unclaimed trees are donated to cities, schools, and other non-profit organizations.
Using the online enrollment tool, participants locate their home on a map, select from a list of
available trees, and evaluate the potential energy savings associated with planting in different
locations. During enrollment, participants learn how trees planted to the west and east save
more energy over time than trees planted to the south and north.
Ensuring the tree is planted properly helps it grow to provide maximum energy savings. At the
tree pick-up events, participants receive additional education on where to plant trees for
maximum energy savings and other tree care guidance from local experts. These local
specialists include city arborists from participating municipalities, Idaho Power utility arborists,
county master gardeners, and College of Southern Idaho (CSI) horticulture students.
Each fall, Idaho Power sends participants from the previous two offerings a newsletter filled
with reminders on proper tree care and links to resources, such as tree care classes and
educational opportunities in the region. This newsletter was developed after the 2015 field
audits identified common customer tree care questions and concerns.
Residential Sector—Shade Tree Project
Demand-Side Management 2022 Annual Report Page 89

Figure 19. Shade Tree Project pick-up event
According to the DOE, a well-placed shade tree can reduce energy used for summer cooling by
15% or more. Utility programs throughout the country report high customer satisfaction with
shade tree programs and an enhanced public image for the utility related to sustainability and
environmental stewardship. Other utilities report energy savings between 40 kWh per year
(coastal climate, San Diego) and over 200 kWh per year (Phoenix) per tree planted. Of the trees
planted in 2022, it is estimated that each tree will save approximately 28 kWh per year by 2032
and 44 kWh per year by 2042. The estimated savings for each tree is adjusted to reflect the
estimated survivorship of the tree.
To be successful, trees should be planted to maximize energy savings and ensure survivability.
Two technological developments in urban forestry—the state sponsored Treasure Valley Urban
Tree Canopy Assessment and the Arbor Day Foundation’s Energy-Saving Trees tool—provide
Idaho Power with the information to facilitate a shade tree project.
Residential Sector—Shade Tree Project
Page 90 Demand-Side Management 2022 Annual Report

Figure 20. Excerpt from spring direct-mail letter
Program Activities
While preparing for the 2022 season, it was not known if COVID-19 might impact in-person pick
up events as it had in 2020 and 2021. The decision was made to offer hybrid events in 2022,
which would allow customers to choose to receive their trees at an in-person event or have
their trees shipped directly to their home. By offering hybrid events, Idaho Power was able to
limit the number of people coming to collect their trees and ensure that the events were held
in a safe manner should COVID-19 social distancing protocols need to be enforced. It also
allowed an option for those customers that might not feel comfortable attending an in-person
offering to still participate and receive their free trees.
The spring offering was made available to those customers that live in the Treasure Valley and
the fall offering was available for those customers that reside in the Magic Valley. For each
event, Idaho Power offered 500 3-gallon trees to be picked up at an in-person event and
500 1-gallon trees to be shipped directly to customers homes. Idaho Power collaborated with
the Arbor Day Foundation to provide and ship the delivery trees. After the fall offering,
there were over 100 trees that had not been reserved or were unclaimed. A small,
impromptu offering in November was made available to customers in the Treasure Valley
during which 47 of the leftover trees were claimed.
Idaho Power continues to track the program data in the DSM database. The database is also
used to screen applicants during enrollment to determine whether participants meet the
eligibility requirements for the project, such as residential status within the eligible counties.
Participation in the program remains two trees per address for the life of the program.
Residential Sector—Shade Tree Project
Demand-Side Management 2022 Annual Report Page 91
Marketing Activities
At the start of both the spring and fall campaigns, the company sent direct-mail letters to select
customers, explaining the benefits of shade trees and encouraging program enrollments.
In spring 2022, Idaho Power sent two “enrollment open” emails encouraging customers in the
Treasure Valley to sign up for trees; for those who chose the delivery option, Idaho Power sent
“get ready” emails that included tree care tips and links to educational resources, and for those
who chose the pick-up option, Idaho Power sent reminder emails that included pick-up event
details and links to tree care resources. Idaho Power did the same for fall enrollment,
except the emails were sent to Magic Valley and Wood River Valley customers. Due to slow
enrollments in the fall campaign, Idaho Power sent additional emails after deciding to open
enrollment to Ada County customers. To help with slow enrollment during the fall campaign,
the program was promoted on Facebook and Twitter, and described in News Briefs, sent to
regional news outlets to spread the word about the available trees.

Figure 21. Shade Tree Project social media post
Cost-Effectiveness
For the Shade Tree Project, Idaho Power uses the Arbor Day Foundation’s software,
which calculates energy savings and other non-energy impacts based on tree species and
orientation/distance from the home. This software tool, i-Tree, estimates these benefits for
Residential Sector—Shade Tree Project
Page 92 Demand-Side Management 2022 Annual Report
years 5, 10, 15, and 20 after the tree planting year. However, the savings estimates assume
each tree is planted as planned and does not consider survivorship. Idaho Power contracted
with a third party to develop a model to calculate average values per tree using the tool data
and calculated a realization rate based on the survival rate. Unlike traditional energy-savings
measures in which the annual savings remain flat throughout the measure life and only
first-year savings are reported, the savings for trees grow as the tree grows when using the
realization rate based on survival. The calculator was used to estimate the 39,595 kWh of
incremental claimable savings in 2022 for the trees planted between 2013 and 2018.
The cost-effectiveness for the program is based on the modeled savings for the trees
distributed in 2022 and costs incurred during 2022. Of the tree distributed in 2022, 843 were
distributed at in-person events and 1,031 were delivered directly to customers by mail.
The trees delivered through the mail are estimated to be approximately one year younger than
the trees distributed at the in-person events, which the calculator was based on. To adjust for
this, the year the company could begin claiming savings was pushed out a year, thus the trees
delivered by mail in 2022 will begin saving 17,656 kWh in 2027 while the trees distributed in
person will begin saving 8,486 kWh in 2026 and 9,026 kWh in 2027. The cost-effectiveness
calculations also include a NTG factor of 124%, which accounts for the spillover associated with
the trees shading a neighboring home as well as various non-energy impacts related to the
improved air quality, avoided stormwater runoff, and winter heating detriment. It is estimated
that these trees will save 80,521 kWh in 2062. Based on the model, the project has a UCT of
1.02 and a TRC ratio of 1.21.
For more detailed information about the cost-effectiveness savings and assumptions,
see Supplement 1: Cost-Effectiveness.
Customer Satisfaction
After each offering, a survey was emailed to participants. The survey asked questions related to
the program marketing, tree-planting education, and participation experience with the
enrollment and tree delivery processes. Results are compared, offering to offering, to look for
trends to ensure the program processes are still working to identify opportunities for
improvement. Because this was Idaho Power’s first year shipping the trees directly to
customers, Idaho Power is also comparing customer satisfaction results from participants who
picked up trees at in-person events in the past. Data is also collected about where and when
the participant planted the tree. This data will be used by Idaho Power to refine
energy-saving estimates.
In total, the survey was sent to 970 Shade Tree Project participants and 362 responses were
received, for a response rate of 37%. Some highlights included the following:
Residential Sector—Shade Tree Project
Demand-Side Management 2022 Annual Report Page 93
• Almost 45% of respondents heard about the program from an Idaho Power email,
and over 29% learned of the program from a friend or relative.
• Almost 79% of respondents were “very satisfied” with the information they received on
the planting and care of their shade tree while over 17% of respondents were
“somewhat satisfied.”
• Participants were asked how much they would agree or disagree they would
recommend the project to a friend. Nearly 91% of respondents said they “strongly
agree,” and over 7% said they “somewhat agree.”
• Participants were asked how much they would agree or disagree they were satisfied
with the overall experience with the Shade Tree Project. Almost 81% of respondents
indicated they “strongly agree,” and nearly 15% “somewhat agree” they were satisfied.
View the complete survey results in Supplement 2: Evaluation.
2023 Plans
Idaho Power plans to continue the Shade Tree Project in 2023, with the spring offering to
customers in the Portneuf Valley and the fall event to customers in the Treasure Valley. Due to
the general reduced satisfaction from direct-mail recipients and the easing of concerns over
COVID-19 restrictions, the direct-mail option will be discontinued in 2023 and only in-person
events will be held. The enrollment process will remain the same, using the Arbor Day
Foundation enrollment tool.
Idaho Power will continue to market the program through direct-mail, focusing on customers
identified as living in newly constructed homes and those identified using the Urban Tree
Canopy Assessment tool in the Treasure Valley. The program will explore the opportunity to be
promoted in the Home Energy Report. In addition, Idaho Power maintains a wait list of
customers who were unable to enroll because previous offerings were full. Idaho Power will
reach out to these customers through email for the 2023 offerings. Idaho Power will continue
to leverage allied interest groups and use social media and boosted Facebook posts if
enrollment response rates decline.

Residential Sector—Weatherization Assistance for Qualified Customers
Page 94 Demand-Side Management 2022 Annual Report
Weatherization Assistance for Qualified Customers
2022 2021
Participation and Savings
Participants (homes/non-profits) 147 162
Energy Savings (kWh) 272,647 291,105
Demand Reduction (MW) n/a n/a
Program Costs by Funding Source
Idaho Energy Efficiency Rider $0 $0
Oregon Energy Efficiency Rider $0 $0
Idaho Power Funds $1,281,495 $1,186,839
Total Program Costs—All Sources* $1,281,495 $1,186,839
Program Levelized Costs
Utility Levelized Cost ($/kWh) $0.338 $0.254
Total Resource Levelized Cost ($/kWh) $0.535 $0.374
Benefit/Cost Ratios
Utility Benefit/Cost Ratio 0.17 0.19
Total Resource Benefit/Cost Ratio 0.32 0.31
* 2021 and 2022 Total Program Costs include accounting accruals and reversals associated with unspent dollars carried over into the next year. These accruals and reversals have been removed from the cost-effectiveness and levelized cost calculations.
Description
The WAQC program provides financial assistance to regional CAP agencies in Idaho Power’s
service area. This assistance helps fund weatherization costs of electrically heated homes
occupied by qualified customers who have limited incomes. Weatherization improvements
enable residents to maintain a more comfortable, safe, and energy-efficient home while
reducing their monthly electricity consumption and are available at no cost to qualified
customers who own or rent their homes. These customers also receive educational materials
and ideas on using energy wisely in their homes. Regional CAP agencies determine participant
eligibility according to federal and state guidelines. The WAQC program also provides limited
funds to weatherize buildings occupied by non-profit organizations that serve primarily
special-needs populations, regardless of heating source, with priority given to electrically
heated buildings.
In 1989, Idaho Power began offering weatherization assistance in conjunction with the State of
Idaho Weatherization Assistance Program (WAP). In Oregon, Idaho Power offers weatherization
assistance in conjunction with the State of Oregon WAP. This allows CAP agencies to combine
Idaho Power funds with federal weatherization funds to serve more customers with special
needs in electrically heated homes.
Idaho Power has an agreement with each CAP agency in its service area for the WAQC program
that specifies the funding allotment, billing requirements, and program guidelines. Currently,
Residential Sector—Weatherization Assistance for Qualified Customers
Demand-Side Management 2022 Annual Report Page 95
Idaho Power oversees the program in Idaho through five regional CAP agencies: Eastern Idaho
Community Action Partnership (EICAP), El Ada Community Action Partnership (EL ADA),
Metro Community Services (Metro Community), South Central Community Action Partnership
(SCCAP), and Southeastern Idaho Community Action Agency (SEICAA). In Oregon,
Community Connection of Northeast Oregon, Inc. (CCNO), and Community in Action (CINA)
provide weatherization services for qualified customers.
The Idaho Department of Health and Welfare (IDHW) uses the DOE-approved energy audit
program (EA5) for the Idaho WAP and, therefore, the Idaho CAP agencies use the EA5.
Annually, Idaho Power verifies a portion of the homes weatherized under the WAQC program.
This is done through two methods. The first method uses a state monitoring process where
either an independent quality-control inspector or trained peers ensure measures were
installed to DOE and state WAP specifications. Utility representatives, weatherization personnel
from the CAP agencies, and CAPAI, review homes weatherized by each of the CAP agencies.
In 2022, eight Idaho Power funded homes were chosen for review.
For the second method, Idaho Power contracts with two companies that employ building
performance specialists to verify the installed measures. After verification, any required
follow-up is done by CAP agency personnel. In 2022, six homes were verified by Idaho Power’s
home verifiers.
Idaho Power reports the activities related to the WAQC program as set forth below in
compliance with IPUC Order No. 29505, as updated in Case No. IPC-E-16-30, Order No. 33702
and consolidates the WAQC Annual Report with Idaho Power’s Demand-Side Management
Annual Report each year.
Program Activities
Weatherized Homes and Non-Profit Buildings by County
In 2022, Idaho Power made $2,083,519 available to Idaho CAP agencies. Of the funds provided,
$934,615 were paid to Idaho CAP agencies, while $1,148,905 were accrued for future funding.
This relatively large carry over was caused by supply chain limitations and labor shortages
limiting the number of homes CAP agencies weatherized. Of the funds paid in 2022,
$849,650 directly funded audits, energy efficiency measures, and health and safety measures
for qualified customers’ homes (production costs) in Idaho, and $84,965 funded administration
costs to Idaho CAP agencies for those homes weatherized.
In 2022, Idaho Power funds provided for the weatherization of 147 homes and no non-profit
buildings in Idaho. Table 13 shows each CAP agency, the number of homes weatherized,
production costs, the average cost per home, administration payments, and total payments per
county made by Idaho Power.
Residential Sector—Weatherization Assistance for Qualified Customers
Page 96 Demand-Side Management 2022 Annual Report
Table 13. WAQC activities and Idaho Power expenditures by agency and county in 2022
Agency/County
Number of
Homes
Production
Cost
Average
Cost
Administration
Payment to Agency
Total
Payment
Idaho Homes
EICAP
Lemhi 6 $ 34,876 $ 5,813 $ 3,488 $ 38,364
Agency Total 6 $ 34,876 $ 3,488 $ 38,364
EL ADA
Ada 72 422,557 5,869 42,256 464,813
Elmore 8 52,174 6,522 5,217 57,391
Owyhee 10 65,230 6,523 6,523 71,754
Agency Total 90 $ 539,961 $ 53,996 $ 593,957
Metro Community Services
Adams 1 7,836 7,836 784 8,619
Boise 1 6,848 6,848 685 7,532
Canyon 19 97,333 5,123 9,733 107,066
Gem 2 15,374 7,687 1,537 16,911
Payette 4 29,365 7,341 2,936 32,301
Valley 2 13,725 6,863 1,373 15,098
Agency Total 29 $ 170,479 $ 17,048 $ 187,527
SCCAP
Blaine 1 8,634 8,634 863 9,498
Cassia 1 2,343 2,343 234 2,578
Jerome 4 18,113 4,528 1,811 19,924
Lincoln 2 9,045 4,523 905 9,950
Twin Falls 3 15,432 5,144 1,543 16,975
Agency Total 11 $ 53,567 $ 5,357 $ 58,924
SEICAA
Bannock 6 23,320 3,887 2,332 25,652
Bingham 2 7,487 3,744 749 8,236
Power 3 19,959 6,653 1,996 21,954
Agency Total 11 $ 50,766 $ 5,077 $ 55,842
Total Idaho Homes 147 $ 849,650 $ 84,965 $ 934,615
Non-Profit Buildings
Total Non-Profit Buildings 0 $ 0 $ 0 $ 0 $ 0
Oregon Homes
CCNO—Baker 0 0 0 0 0
Agency Total 0 0 0 $ 0 $ 0
CINA—Malheur 0 0 0 0 0
Agency Total 0 0 0 $ 0 $ 0
Total Oregon Homes 0 0 0 $ 0 $ 0
Total Program 147 $ 849,650 $ 84,965 $ 934,615
Note: Dollars are rounded.
Residential Sector—Weatherization Assistance for Qualified Customers
Demand-Side Management 2022 Annual Report Page 97
The base funding for Idaho CAP agencies is $1,212,534 annually, which does not include carry
over from the previous year. Idaho Power’s agreements with CAP agencies include a provision
that identifies a maximum annual average cost per home up to a dollar amount specified in the
agreement between each CAP agency and Idaho Power. The intent of the maximum annual
average cost allows the CAP agency flexibility to service some homes with greater or fewer
weatherization needs. It also provides a monitoring tool for Idaho Power to forecast year-end
outcomes. The average cost per home weatherized is calculated by dividing the total annual
Idaho Power production cost of homes weatherized by the total number of homes weatherized
that the CAP agencies billed to Idaho Power during the year. The maximum annual average cost
per home in the 2022 agreement was $6,000. In 2022, Idaho CAP agencies had a combined
average cost per home weatherized of $5,780.
CAP agency administration fees are equal to 10% of Idaho Power’s per-job production costs.
The average administration cost paid to agencies per Idaho home weatherized in 2022 was
$578. Not included in this report’s tables are additional Idaho Power staff labor, marketing,
and support costs for the WAQC program totaling just over $67,400 for 2022. These expenses
were in addition to the WAQC program funding requirements in Idaho specified in IPUC Order
No. 29505.
In compliance with IPUC Order No. 29505, WAQC program funds are tracked separately,
with unspent funds carried over and made available to Idaho CAP agencies in the following
year. In 2022, $870,985 in unspent funds from 2021 were made available for expenditures in
Idaho. Table 14 details the base funding and available funds from 2021, and the total amount of
2022 spending.
Table 14. WAQC base funding and funds made available in 2022
Agency

2022 Base
Available Funds
from 2021
Total 2022
Allotment

2022 Spending
Idaho
EICAP $ 12,788.00 $ 25,576.00 $ 38,364.00 $ 38,364.00
EL ADA 568,479.00 87,969.13 656,448.13 593,957.27
Metro Community Services 302,259.00 217,540.54 519,799.54 187,527.15
SCCAP 167,405.00 217,334.22 384,739.22 58,924.24
SEICAA 111,603.00 193,174.13 304,777.13 55,842.06
Non-profit buildings 50,000.00 129,391.44 179,391.44 0
Idaho Total $ 1,212,534.00 $ 870,985.46 $ 2,083,519.46 $ 934,614.72
Oregon
CCNO $ 6,750.00 $ 3,375.00 $ 10,125.00 $ 0
CINA 38,250.00 19,125.00 57,375.00 0
Oregon Total $ 45,000.00 $ 22,500.00 $ 67,500.00 $ 0

Residential Sector—Weatherization Assistance for Qualified Customers
Page 98 Demand-Side Management 2022 Annual Report
Because of supply chain issues and labor shortages, various weatherization department’s
production schedules were lower than normal, and less Idaho Power funding was spent in
2022. Unspent funding will be carried over to 2023.
Weatherization Measures Installed
Table 15 details home counts for which Idaho Power paid all or a portion of each measure’s
cost during 2022. The home counts column shows the number of times any percentage of that
measure was billed to Idaho Power during the year. If totaled, measure counts would be higher
than total homes weatherized because the number of measures installed in each home varies.
WAQC, like WAPs nationwide, are whole-house programs that offer several measures that have
costs but do not necessarily save energy, or for which the savings cannot be measured.
Included in this category are health and safety measures and home energy audits. Health and
safety measures are necessary to ensure weatherization activities do not cause unsafe
situations in a customer’s home or compromise a home’s existing indoor air quality (IAQ).
Idaho Power contributes funding for the installation of items that do not save energy, such as
smoke and carbon monoxide detectors, vapor barriers, electric panel upgrades, floor registers
and boots, kitchen range fans, and venting of bath and laundry areas. While these items
increase health, safety, and comfort and are required for certain energy-saving measures to
work properly, they increase costs of the job.
Table 15. WAQC summary of measures installed in 2022
Counts Production Costs
Idaho Homes
Audit 90 $ 10,242
Ceiling Insulation 29 28,888
LED lightbulbs 22 901
Doors 60 50,133
Ducts 14 7,708
Floor Insulation 24 32,126
Furnace Repair 4 3,015
HVAC Replacement 119 558,891
Health and Safety 17 12,815
Infiltration 85 12,957
Other 0 0
Pipes 7 760
Vents 4 482
Wall Insulation 2 563
Water Heater 4 3,726
Windows 70 126,443
Total Idaho Homes $ 849,650
Residential Sector—Weatherization Assistance for Qualified Customers
Demand-Side Management 2022 Annual Report Page 99
Counts Production Costs
Oregon Homes 0 0
Total Oregon Homes 0 0
Idaho Non-Profits 0 0
Total Idaho Non-Profit Measures 0 $ 0
Note: Dollars are rounded.
Re-Weatherization
Idaho Power identified a large increase in carry over funds to CAP agencies that had occurred
due to a combination of COVID-19 in-home activity restrictions, supply chain limitations and
labor shortages limiting the number of homes CAP agencies weatherized. In May 2022,
with support from EEAG, Idaho Power filed a proposal (IPC-E-22-15) with the IPUC designed to
address the increase by expanding eligibility for weatherization to include homes that had been
weatherized within the last rolling 14-year period but that had not received HVAC upgrades.
Because these homes are not eligible to receive federal funding for re-weatherization within a
rolling 14-year period based on DOE guidelines, Idaho Power’s proposal was to fund HVAC
upgrades at 100% of the cost for these jobs. In November 2022, the IPUC approved the
company’s application in Order No. 35583. No homes in this category were completed before
the end of the year.
Marketing Activities
Information about WAQC is available in a brochure (English and Spanish) and on the Income
Qualified Customers page of Idaho Power’s website. Idaho Power regional energy advisors and
EOEAs promote WAQC when working directly with customers in their communities, at fairs,
senior centers, and during other presentations in their regions. The CAP agencies also promote
the program through their outreach activities.
Cost-Effectiveness
In 2022, WAQC program cost-effectiveness was 0.17 from the UCT perspective and 0.32 from
the TRC perspective.
The savings values were updated in 2020 based on a billing analysis of program participants
conducted by a third party; there were no changes to the values used for reporting from
2020 to 2022. Idaho Power plans to update this billing analysis in 2023.
While final cost-effectiveness is calculated based on measured consumption data,
cost-effectiveness screening begins during the initial contacts between CAP agency
weatherization staff and the customer. In customer homes, the agency weatherization auditor
uses the EA5 tool to conduct the initial audit of the home. The EA5 tool is used to compare the
efficiency of the home prior to weatherization to the efficiency after the proposed
improvements and calculates the value of the efficiency change into a savings-to-investment
Residential Sector—Weatherization Assistance for Qualified Customers
Page 100 Demand-Side Management 2022 Annual Report
ratio (SIR). The output of the SIR is similar to the PCT ratio. If the EA5 computes an SIR of 1.0 or
higher, the CAP agency is authorized to complete the proposed measures. The weatherization
manager can split individual measure costs between Idaho Power and other funding sources
with a maximum charge of 85% of total production costs to Idaho Power. Using the audit tool
to pre-screen projects ensures each weatherization project will result in energy savings.
The 2022 cost-effectiveness analysis continues to incorporate the following directives from
IPUC Order No. 32788:
• Applying a 100% NTG value to reflect the likelihood that WAQC weatherization projects
would not be initiated without the presence of a program
• Claiming 100% of project savings
• Including an allocated portion of the indirect overhead costs
• Applying the 10% conservation preference adder
• Claiming $1 of benefits for each dollar invested in health, safety, and repair measures
• Amortizing evaluation expenses over a three-year period
Finally, the cost-effectiveness calculation removes the impacts of any accruals and reversals
associated with unspent dollars carried over into the following year. In 2022, the amount
carried over into 2023 was $277,919. By leaving this amount in the cost-effectiveness
calculation, it would overstate expenses in 2022 while the subsequent reversal would
understate expenses in 2023. Idaho Power will continue to work with EEAG, as well as the
weatherization managers who oversee the weatherization work, to discuss ways to improve the
program. For further details on the overall program cost-effectiveness assumptions,
see Supplement 1: Cost-Effectiveness.
Customer Education and Satisfaction
The CAP agency weatherization auditor explains to the customer which measures are analyzed
and why. Further education is done as the crew demonstrates the upgrades and how they will
help save energy and provide an increase in comfort. Idaho Power provides each CAP agency
with energy efficiency educational materials for distribution to customers during home visits.
Any customers whose homes are selected for the company’s post-weatherization home
verification receive additional information and can ask the home verifiers more questions.
A customer survey was used to assess major indicators of customer satisfaction throughout the
service area. All program participants in all regions were asked to complete a survey after their
homes were weatherized. Survey questions gathered information about how customers
learned of the program, reasons for participating, how much customers learned about saving
energy in their homes, and the likelihood of household members changing behaviors to use
energy wisely.
Residential Sector—Weatherization Assistance for Qualified Customers
Demand-Side Management 2022 Annual Report Page 101
Idaho Power received survey results from 132 of 147 households weatherized by the program
in 2022. Some highlights include the following:
• Over 48% of respondents learned of the program from a friend or relative, and almost
17% learned of the program from an agency flyer. Over 14% learned of the program
from the Idaho Power website.
• Over 48% of the respondents reported their primary reason for participating in the
weatherization program was to reduce utility bills, almost 20% wanted to improve the
comfort of their home, and almost 18% had concerns about their existing furnace.
• Over 23% reported they learned how air leaks affect energy usage, and almost 23%
indicated they learned how to use energy wisely during the weatherization process.
• Over 15% of respondents said they learned how to program the new thermostat.
Most respondents (over 98%) reported they were likely to change habits to save energy,
and over 99% reported they have shared all the information about energy use with
members of their household.
• Over 92% of the respondents reported they think the weatherization they received will
significantly affect the comfort of their home, and almost all (99.12%) said they were
“very satisfied” with the program.
• Over 19% of the respondents reported the habits they were most likely to change to
save energy was turning the thermostat down in winter and up in the summer.
Turning off lights when not in use was reported by over 19% of the respondents, and
washing full loads of clothes was reported by over 15% as a habit they and members of
the household were most likely to adopt to save energy.
A summary of the survey is included in Supplement 2: Evaluation.
2023 Plans
In 2023, Idaho Power will continue to provide financial assistance to CAP agencies while
exploring changes to improve program delivery. The company will also continue to provide the
most benefit possible to special-needs customers while working with Idaho and Oregon WAP
personnel. Since the retirement of the Idaho state WAP energy audit tool (EA5) in late 2022,
CAP agency personnel will invoice Idaho Power with a new job cost calculator starting in 2023.
The job cost calculator will be filled with information from the new state audit tool, ECOS.
Idaho Power plans to continue to verify approximately 5% of the homes weatherized under the
WAQC program via home-verification companies and the Idaho and Oregon state
monitoring process.
In 2023, Idaho Power will support the whole-house philosophy of the WAQC program and
Idaho and Oregon WAP by continuing to allow a $6,000 annual maximum average per-home
Residential Sector—Weatherization Assistance for Qualified Customers
Page 102 Demand-Side Management 2022 Annual Report
cost. The company will continue to work with CAPAI, CAP agencies, and IDHW to develop
recommendations and ideas to help improve the program for customers with special needs.
In Idaho during 2023, Idaho Power expects to contribute the base amount plus available funds
from 2022 of just under $1,148,905 to total $2,361,439 in weatherization measures and agency
administration fees. Of this amount, approximately $229,391 will be provided in the non-profit
pooled fund to weatherize buildings housing non-profit agencies that primarily serve qualified
customers in Idaho, with an allowance for annual unused non-profit funds to be used toward
additional residential weatherization projects.
The newly approved re-weatherization option will be implemented in 2023. A list of customers
that received weatherization within a prior 14-year rolling period but did not receive HVAC
system replacements are being provided to weatherization managers. From these lists,
weatherization managers will contact customers and work with HVAC contractors to determine
whether HVAC upgrades are warranted and identify the type of system that would work best in
the qualified home. Based on Idaho state WAP guidelines, the HVAC contractor may replace the
HVAC system of the previously weatherized home and have the completed home inspected by
the entity that issues the permit. Re-weatherization jobs will be invoiced to Idaho Power
separately from regular WAQC jobs and will be paid with funds from each CAP Agency’s
individual portion of the annual WAQC amount which includes carry over of unused funds from
previous years. Re-weatherized homes will be reported in the company’s annual DSM report as
a portion of the individual WAQC report.
Idaho Power will continue to maintain the program content on its website and include it with
other marketing collateral.

Residential Sector—Weatherization Solutions for Eligible Customers
Demand-Side Management 2022 Annual Report Page 103
Weatherization Solutions for Eligible Customers
2022 2021
Participation and Savings
Participants (homes) 27 7
Energy Savings (kWh) 48,233 12,591
Demand Reduction (MW) n/a n/a
Program Costs by Funding Source
Idaho Energy Efficiency Rider $198,198 $54,793
Oregon Energy Efficiency Rider $0 $0
Idaho Power Funds $7,590 $2,863
Total Program Costs—All Sources $205,788 $57,656
Program Levelized Costs
Utility Levelized Cost ($/kWh) $0.307 $0.317
Total Resource Levelized Cost ($/kWh) $0.307 $0.317
Benefit/Cost Ratios
Utility Benefit/Cost Ratio 0.15 0.15
Total Resource Benefit/Cost Ratio 0.23 0.28

Description
Weatherization Solutions for Eligible Customers is an energy efficiency program designed to
serve Idaho Power residential customers in Idaho whose income falls between 175% and 250%
of the current federal poverty level. Initiated in 2008, the program is designed to mirror the
WAQC program. These customers often do not have disposable income to invest in energy
efficiency upgrades, and they typically live in housing similar to WAQC customers.
The program also benefits certain customers on the state weatherization waiting list.
When customer income overlaps both programs, this program may offer an earlier
weatherization date than state WAP, resulting in less wait time for the customer and quicker
energy savings.
Potential participants are interviewed by a participating contractor to determine household
occupant income eligibility, as well as to confirm the home is eligible. If the home is a rental,
the landlord must agree to maintain the unit’s current rent for a minimum of one year, and to
help fund a portion of the cost of weatherization. If the customer is eligible, an auditor inspects
the home to determine which upgrades will save energy, improve indoor air quality, and/or
provide health and safety measures for the residents. To be approved, energy efficiency
measures and repairs must have an SIR of 1.0 or higher, interact with an energy-saving
measure, or be necessary for the health and safety of the occupants.
Residential Sector—Weatherization Solutions for Eligible Customers
Page 104 Demand-Side Management 2022 Annual Report
The Weatherization Solutions for Eligible Customers program uses a home audit tool called the
HAT14.1 that is similar to the EA5 audit tool used in WAQC. The home is audited for energy
efficiency measures, and the auditor proposes upgrades based on the SIR ratio calculated by
HAT14.1. As in WAQC, if the SIR is 1.0 or greater, the contractor is authorized to upgrade that
measure. Measures considered for improvement are window and door replacement; ceiling,
floor, and wall insulation; HVAC repair and replacement; water heater repair and replacement;
and pipe wrap. Also included is the potential to replace lightbulbs and refrigerators.
Contractors invoice Idaho Power for the project costs, and if the home is a rental, a minimum
landlord payment of 10% of the cost is required.
Idaho Power’s agreement with contractors includes a provision that identifies a maximum
annual average cost per home. The intent of the maximum annual average cost is to allow
contractors the flexibility to service homes with greater or fewer weatherization needs. It also
provides a monitoring tool for Idaho Power to forecast year-end outcomes.
Program Activities
Due to extended COVID-19 labor shortages, some contractors continued to experience
hardships hiring and training weatherization crew members resulting in lower production
numbers in 2022. Contractors weatherized 27 Idaho homes for the program: two in CAP’s
eastern region, 23 in CAP’s south-central region, and two in Idaho Power’s Capital region.
Of those 27 homes weatherized, 18 were single-family, seven were manufactured homes,
and two were multi-family units. Contractors reported increased costs for materials and
equipment from previous years.
Two independent companies performed random verifications of weatherized homes and visited
with customers about the program. In 2022, seven homes were verified and of those
verifications, one job required the Contractor to return to perform minor repairs.
Marketing Activities
The program was not marketed in 2022 to allow contractors time to work through their existing
waiting lists, which are a result of worker shortages, supply chain restrictions, and the high
volume of WAQC applicants on regional CAP Agency waiting lists.
Cost-Effectiveness
In 2022, the Weatherization Solutions for Eligible Customers program cost-effectiveness was
0.15 from the UCT perspective and 0.23 from the TRC perspective.
Weatherization Solutions for Eligible Customers projects, similar to WAQC program guidelines,
benefit from a pre-screening of measures through a home audit process. The home audit
process ensures an adequate number of kWh savings to justify the project and provides more
consistent savings for billing analysis. See WAQC cost-effectiveness for a discussion of the audit
Residential Sector—Weatherization Solutions for Eligible Customers
Demand-Side Management 2022 Annual Report Page 105
and prescreening process, which is similar for both programs. In 2023, Idaho Power plans to
conduct a billing analysis of program participants to update the savings assumptions associated
with the program.
For further details on the overall program cost-effectiveness assumptions, see Supplement 1:
Cost-Effectiveness.
Customer Satisfaction
A customer survey was used to assess major indicators of customer satisfaction with the
program throughout the service area. Program participants were asked to complete a survey
after their homes were weatherized. Survey questions gathered the following information:
• How customers learned of the program
• Reasons for participating
• How much customers learned about saving energy in their homes
• The likelihood of household members changing behaviors to use energy wisely
Idaho Power received survey results from 21 of 27 households weatherized by the program in
2022. Some highlights include the following:
• Over 21% of respondents learned of the program from a friend or relative, and another
almost 11% learned of the program from a letter in the mail. Several people cited
learning about the program through a bill stuffer.
• Over 63% of the respondents reported their primary reason for participating in the
weatherization program was to reduce utility bills, and over 21% wanted to improve the
comfort of their home.
• Over 20% reported they learned how air leaks affect energy usage, and the same
percentage indicated they learned how insulation affects energy usage.
• Over 19% of respondents said they learned how to use energy wisely. 100% reported
they were very likely to change habits to save energy, and 100% reported they have
shared all the information about energy use with members of their household.
• Over 84% of the respondents reported they think the weatherization they received will
significantly affect the comfort of their home, and 100% said they were “very satisfied”
with the program.
• Almost 41% of the respondents reported the habit they were most likely to change was
unplugging electrical equipment when not in use, and over 9% said that washing full
loads of clothes was a habit they were likely to adopt to save energy. Turning the
thermostat up in the summer and down in the winter was reported by almost 5% of the
respondents as a habit they and members of the household were most likely to adopt to
save energy.
A summary of the survey is included in Supplement 2: Evaluation.
Residential Sector—Weatherization Solutions for Eligible Customers
Page 106 Demand-Side Management 2022 Annual Report
2023 Plans
It is anticipated that program activity may be lower than normal again in 2023 due to worker
shortages, supply chain restrictions, and the high volume of WAQC applicants on regional CAP
Agency waiting lists.
Idaho Power will update brochures as necessary to help spread the word about the program in
all communities in 2023. If needed, additional marketing for the program may include bill
inserts, emails, News Briefs, website updates, and ads in various regional publications,
particularly those with a senior and/or low-income focus. Social media posts and boosts,
coordinated partner content, and employee education may be used to increase awareness.
Regional marketing and targeted digital ads will be considered based on need as evidenced by
any regional contractor’s waiting list for Weatherization Solutions for Eligible
Customers services.
C&I Sector Overview
Demand-Side Management 2022 Annual Report Page 107
Commercial & Industrial Sector Overview
In 2022, Idaho Power’s C&I sector consisted of 77,306 commercial, governmental, school,
and small business customers. The number of customers increased by 1,284 or 1.7% versus
2021. Energy use per month for customers in this sector is not as homogenous as other
customer sectors and can vary by several hundred thousand kWh each month depending on
customer type. In 2022, the commercial sector represented 27% of Idaho Power’s total retail
annual electricity sales.
Industrial and special contract customers are Idaho Power’s largest individual energy
consumers. In 2022, there were 125 customers in this category, representing approximately
22.2% of Idaho Power’s total retail annual electricity sales.
Idaho Power’s C&I sector has many energy efficiency programs available to commercial,
industrial, governmental, schools, and small business customers. The suite of options can help
businesses of all sizes implement energy efficiency measures.
Table 16. Commercial/Industrial sector program summary, 2022
Total Cost Savings
Program Participants Utility Resource
Annual Energy
(kWh)
Peak Demand
(MW)*
Demand Response
Flex Peak Program ....................................... 159 $ 519,618 $ 519,618 24.5/30
Total ...................................................................................................... $ 519,618 $ 519,618 24.5/30
Energy Efficiency
CIEE
Custom Projects ...................................... 106 8,919,927 25,715,468 56,157,060
Green Motors Initiative—Industrial ......... 9

0 3,424 19,851
New Construction .................................... 88 2,780,507 3,641,930 27,615,777
Retrofits .................................................. 525 4,870,916 13,402,016 22,890,678
Commercial Energy-Saving Kits ...................... 334 22,770 22,770 48,758
Small Business Direct Install ........................... 680 1,345,429 1,345,429 3,228,365
Total ...................................................................................................... $ 17,939,548 $ 44,131,037 109,960,489
Notes:
See Appendix 3 for notes on methodology and column definitions.
Totals may not add up due to rounding.
*

Commercial and Industrial DSM Programs
C&I Energy Efficiency—Custom Projects. For projects not covered by the New Construction or
Retrofits options, Custom Projects offers incentives for qualifying large, custom energy
efficiency projects and energy-management measures, such as strategic energy management
C&I Sector Overview
Page 108 Demand-Side Management 2022 Annual Report
(SEM) cohorts, tune-ups, system optimization, and recommissioning. Additionally,
Idaho business customers who wish to find ways to save energy and to quantify their savings
can obtain a scoping assessment and detailed assessment through this option.
C&I Energy Efficiency—New Construction. This option offers specific incentives for designing
and building better-than-code energy-efficient features into a new construction,
major renovation, addition, expansion, or change-of-space project. A Professional Assistance
Incentive (PAI) is available for the architect or engineer on the project through this option.
C&I Energy Efficiency—Retrofits. This option offers prescriptive incentives for energy-saving
retrofits to existing equipment or facilities.
Green Motors Initiative (GMI). Under the GMI, service center personnel are trained and
certified to repair and rewind motors to improve reliability and efficiency. If a rewind returns a
motor to its original efficiency, the process is called a “Green Rewind.” By rewinding a motor
under this initiative, customers may save up to 40% of the cost of a new motor.
Commercial Energy-Saving Kits. This program offers free commercial kits filled with products
and tips to help businesses save energy. The commercial kit is assembled and delivered directly
to Idaho Power’s business customers by a third-party vendor.
Flex Peak Program. A demand response program that pays an incentive to C&I customers who
voluntarily reduce energy use during periods of high energy demand or for other system needs.
Small Business Direct Install (SBDI). SBDI targets typically hard-to-reach small business
customers. SBDI is implemented by a third-party contractor that provides turn-key services.
Idaho Power pays 100% of the cost to install eligible measures for customers who use less than
25,000 kWh annually. SBDI is offered to eligible customers in a strategic geo-targeted approach.
Oregon Commercial Audits. This statutory-required program offers free energy audits,
evaluations, and educational products to Oregon customers to help them achieve
energy savings.
Marketing
In 2022, Idaho Power continued to market the programs listed above, targeting the following
customers: commercial, industrial, government, schools, small businesses, architects,
engineers, and other design professionals.
Bill Inserts
A bill insert highlighting how Idaho Power’s incentives can save customers money was
included in 33,030 business customer bills in March, and a version of the insert was included in
39,407 bills in July.
C&I Sector Overview
Demand-Side Management 2022 Annual Report Page 109
Print and Digital Advertising
In 2022, the print ads focused on promoting offered incentives and their availability to
businesses of all sizes. The company also continued to promote energy efficiency with
messages around safe, reliable, affordable, and clean energy in select publications.
Print ads ran in the Idaho Business Review in April, May, August, September, October,
and November. Also, ads ran in the Building Owners and Managers Association (BOMA)
membership directory and symposium program, Idaho Business Review Top Projects Awards
publication, and the Idaho Association of General Contractors membership directory.
Additionally, Idaho Power sponsored the Construction section in the Idaho Business Review’s
Book of Lists, which included an ad, company logo in the table of contents, and an article
highlighting Idaho Power and the company’s energy efficiency programs.
Idaho Power continued using search engine marketing to display Idaho Power’s C&I Energy
Efficiency Program near the top of the search results with the paid search terms when
customers search for energy efficiency business terms. These ads received 145,184 impressions
and 18,086 clicks.
Newsletters
Idaho Power produces a monthly newsletter called Connections that is distributed to all
customers and covers a variety of topics. The February issue was dedicated to small-business-
related energy efficiency topics, including the Zeppole energy efficiency story, energy-saving
resources for small businesses, and the impact small businesses have at Idaho Power.
Idaho Power produces and distributes Energy@Work, a quarterly newsletter about
Idaho Power company information and energy efficiency topics for business customers.
In 2022, newsletters were delivered electronically.
• The spring issue was sent to 16,557 customers in March. The issue focused on the
demand response program changes and energy efficiency incentives that benefited
customers in Blackfoot and Sun Valley.
• The summer issue, sent to 16,995 customers in June, focused on celebrating dairy
month, City of Boise and Lamb Weston receiving an incentive for their energy efficiency
projects, and 2022 training opportunities.
• The fall issue was sent to 17,407 customers in September. The issue included a thank
you to participants in the Flex Peak demand response program, an article
about providing businesses with reliable and affordable energy, and information about
the industrial Wastewater Energy Cohort and commercial ESKs.
• The winter issue was sent to 17,690 customers in December. The issue included articles
about Idaho Power’s mobile app that helps small businesses, Idaho Power support for
Agropur’s energy-saving projects, and workshops for school cohort participants.
C&I Sector Overview
Page 110 Demand-Side Management 2022 Annual Report
Airport Advertising
To reach business customers, Idaho Power continued to display two backlit ads throughout the
airport in 2022. The ad promotes how Idaho Power helps power businesses and is displayed in
the main concourse walkway for increased visibility. Additionally, an ad on alternating airport
display boards highlighted the company’s clean energy goal—Clean Today. Cleaner
Tomorrow.®—and the role energy efficiency plays in achieving that goal.
Radio
Idaho Power sponsored messages on public radio stations in Boise, Twin Falls, and Pocatello
from August through October. The company ran a total of 402 messages in Boise and Twin Falls,
and 786 messages in Pocatello.
Social Media
Idaho Power continued using regular LinkedIn posts focused on energy-saving tips,
program details, incentives, and training opportunities. When appropriate, these messages
were also shared on Idaho Power’s Facebook and Twitter pages.
Public Relations
Idaho Power provides PR support to customers who want to publicize the work they have done
to become more energy efficient. Upon request, Idaho Power creates large-format checks used
for media events and/or board meetings. Idaho Power will continue to assist customers with PR
opportunities by creating certificates for display within their buildings and speaking at press
events, if requested.
These opportunities were available in 2022, after years of postponement due to the pandemic.
Idaho Power produced checks and supported PR efforts for several companies, including City of
Blackfoot, City of Ketchum, Micron, Lamb Weston, Power County Hospital, City of Twin Falls,
Kuna Joint School District, Materne, Agropur, Ford Idaho Center, and Boise School District.
Association and Event Sponsorships
Idaho Power’s C&I Energy Efficiency Program typically sponsors a number of associations and
events. In 2022, some of the events were back to an in-person format.
The company sponsored the BOMA Commercial Real Estate Symposium February 14–15 and
placed an ad and article in the event program. During the event, a company executive was a
speaker on a panel, slides were presented with key company facts that rotated on the screen
before the event, and Idaho Power had a booth with materials promoting energy efficiency.
Takeaway brochures were placed at each table.
Idaho Power remained a sponsor of the Idaho Business Review’s Top Projects Awards held in
October in Boise. The company logo was used throughout the event, an Idaho Power employee
C&I Sector Overview
Demand-Side Management 2022 Annual Report Page 111
spoke during the event as a long-standing judge, and company materials were placed at
the tables.
Idaho Power sponsored the Edison Electric Institute (EEI) National Accounts Workshop held in
October in Indianapolis. Promotion included the company logo, a booth with brochures and
materials, and program descriptions on the EEI online marketplace.
Customer Satisfaction
Idaho Power conducts the Burke Customer Relationship Survey each year. In 2022, on a scale of
zero to 10, small business survey respondents rated Idaho Power 8.04 regarding offering
programs to help customers save energy, and 7.82 related to providing customers with
information on how to save energy and money. Twelve percent of small business respondents
indicated they have participated in at least one Idaho Power energy efficiency program. Of the
small business survey respondents who have participated in at least one Idaho Power energy
efficiency program, 85% are “very” or “somewhat” satisfied with the program.
In 2022, on a scale of zero to 10, large C&I survey respondents rated Idaho Power 9.06
regarding offering programs to help customers save energy, and 8.73 related to providing
customers with information on how to save energy and money. Thirty-eight percent of large
C&I respondents indicated they have participated in at least one Idaho Power energy efficiency
program. Of the large C&I survey respondents who have participated in at least one Idaho
Power energy efficiency program, 98% are “very” or “somewhat” satisfied with the program.
Training and Education
In 2022, Idaho Power engineers, program staff, field representatives, and hired consultants
continued to provide technical training and education to help customers learn how to identify
opportunities to improve energy efficiency in their facilities. The company has found that these
activities increase awareness and participation in its energy efficiency and demand response
programs and enhance customer program satisfaction. To market this service and distribute
the training schedule and resources, Idaho Power used its website, email, and the
Energy@Work newsletter.
During each training session, a program engineer gave an overview of the C&I Energy Efficiency
Program incentives available to customers.
As part of the training and education outreach activity, Idaho Power collaborated with and
supported stakeholders and organizations, such as Integrated Design Lab (IDL) and the
American Society of Heating, Refrigeration, and Air Conditioning Engineers (ASHRAE). Using
Idaho Power funding, IDL performed several tasks aimed at increasing the energy efficiency
knowledge of architects, engineers, trade allies, and customers. Specific activities included
C&I Sector Overview
Page 112 Demand-Side Management 2022 Annual Report
sponsoring a BSUG, conducting Lunch & Learn sessions at various design and engineering firms,
and offering the Energy Resource Library (ERL).
Idaho Power delivered six equivalent full-time days of live, online technical training sessions in
2022 at no cost to the customers over the course of 11 days. Topics included the following:
• HVAC System Testing for Energy Efficiency
• Motors and VFDs
• Fan System Training
• Chilled Water System and Cooling Towers
• Energy Management Systems
• Compressed Air Training
The level of participation in 2022 remained high, with 216 individuals signing up and
150 attending the technical sessions. Due to the virtual nature of the course delivery, in some
cases there were multiple attendees at a single login location. Customer feedback indicated the
average satisfaction level was 87%. Idaho Power’s average cost to deliver the technical trainings
in 2022 was approximately $4,567 per class. Idaho Power surveyed customers to obtain
feedback on the training program. After reviewing the results of the survey, Idaho Power plans
to implement suggestions to continue providing valuable training to meet customers’ needs.
Additionally, Idaho Power offered four live, online technical training sessions to industrial
wastewater customers, and extended invitations to those outside of the cohort participants.
Topics included the following:
• Water Energy Basics
• Wastewater Typical No-/Low-Cost Opportunities
• Pumps and Efficiency
• Activated Sludge Basics
Industrial wastewater trainings were attended by 50 participants. Cohort members and other
operators were invited and offered continuing education units for industrial wastewater
professionals. Each course is designed to study improved operation, quality, and energy
performance for different systems.
Aside from the classes listed above, Idaho Power also partnered with the NEEC to administer a
Building Operator Certification Level I Course that began in November 2021 and continued
through May 2022. Idaho Power sponsored 17 customers who signed up for the training and
paid $900 of the $1,895 tuition cost upon completion.
C&I Sector Overview
Demand-Side Management 2022 Annual Report Page 113
Field Staff Activities
Energy efficiency opportunities continue to be an important factor for most businesses.
Many of our large commercial customers have been approached to evaluate other creative
solutions to manage their energy, such as installing solar coupled with batteries. The energy
advisors have had many opportunities to help evaluate these solutions on behalf of customer
requests and generally the least-cost option continues to be energy efficiency. Idaho Power’s
energy efficiency programs are designed to accommodate all possible efficiency opportunities,
ranging from equipment improvements to a variety of business cohorts that offer support and
ongoing training for a long-term, more sustainable approach to energy efficiency.
Idaho Power has trained friendly and engaged energy advisors in each region and while market
uncertainty has slowed some projects, the energy advisors continue to support and influence
participation. For a time during COVID-19, Idaho Power’s energy advisors were performing
most of their annual visits online or by phone. In general, the energy advisors returned to
in-person site visits in 2022. They have, however, found that a combination of in-person and
web meetings offers more customer flexibility. The company continued to offer online technical
training to commercial building engineers, trade allies, and other stakeholders to help them be
successful with the ongoing promotion of energy efficiency opportunities.

C&I Sector—Commercial and Industrial Energy Efficiency Program
Page 114 Demand-Side Management 2022 Annual Report
Commercial and Industrial Energy Efficiency Program
2022 2021
Participation and Savings*
Participants (projects) 728 1,021
Energy Savings (kWh)** 106,683,366 92,465,723
Demand Reduction (MW) n/a n/a
Program Costs by Funding Source***
Idaho Energy Efficiency Rider $16,301,140 $14,375,182
Oregon Energy Efficiency Rider $266,764 $742,013
Idaho Power Funds $3,445 $9,630
Total Program Costs—All Sources $16,571,349 $15,126,824
Program Levelized Costs
Utility Levelized Cost ($/kWh) $0.016 $0.017
Total Resource Levelized Cost ($/kWh) $0.043 $0.043
Benefit/Cost Ratios
Utility Benefit/Cost Ratio 2.86 2.86
Total Resource Benefit/Cost Ratio 1.33 1.46
*Metrics for each option (New Construction, Custom Projects, and Retrofits) are reported separately in the appendices and in Supplement 1: Cost-Effectiveness.
**2021 total includes 20,430 kWh of energy savings from four GMI projects. 2022 total includes 19,851 kWh of energy savings from 9 GMI
projects.
***2021 and 2022 dollars include totals for New Construction, Custom Projects, and Retrofits.
Description
Three major program options targeting different energy efficiency projects are available to
commercial, industrial, governmental, schools, and small business customers in the company’s
Idaho and Oregon service areas: Custom Projects, New Construction, and Retrofits.
Idaho Power has found providing facility energy assessments, customer technical training, and
education services are key to encouraging customers to consider energy efficiency
modifications. The 2022 activities and results not already described in the C&I Sector Overview
are described below.
Custom Projects
The Custom Projects option provides incentives for energy efficiency modifications to new and
existing facilities. The goal is to encourage energy savings in Idaho and Oregon service areas by
helping customers implement energy efficiency upgrades or energy management projects.
Additionally, Idaho Power operates SEM cohorts under the Custom Projects option.
Incentives reduce customers’ payback periods for custom modifications and promote
energy-saving operations that might not otherwise be completed. The Custom Projects option
also offers energy assessment services and customer training to help identify and evaluate
potential energy-saving modifications or projects.
C&I Sector—Commercial and Industrial Energy Efficiency Program
Demand-Side Management 2022 Annual Report Page 115
Interested customers submit a pre-approval application to Idaho Power for potential
modifications identified by the customer, Idaho Power, or a third-party consultant. Idaho Power
reviews each application and works with the customer and vendors to provide or gather
sufficient information to support the estimated energy-savings calculations, then pre-approves
the project. Then, the customer moves forward with the project. In some cases, large,
complex projects may take as long as two or more years to complete.
Once the project is completed, customers submit a payment application, and each project is
reviewed to ensure energy savings are achieved. Idaho Power engineering staff or a third-party
consultant verifies the energy-savings methods and calculations. Through this verification
process, the final energy savings and the project costs are estimated.
On the larger and more complex projects, Idaho Power or a third-party consultant conducts
on-site power monitoring and data verification (M&V) before and after project implementation
to confirm energy savings are obtained and are within program guidelines. If changes in project
scope take place, Idaho Power recalculates energy savings and incentive amounts based on the
actual installed equipment and performance.
New Construction
The New Construction option enables customers in Idaho Power’s Idaho and Oregon service
areas to incorporate energy-efficient design features and technologies into new construction,
expansion, or major remodeling projects. Initiated in 2004, the New Construction option
currently offers incentives for 33 energy-saving building and design features related to efficient
lighting, lighting controls, building shell, HVAC equipment, HVAC controls, variable speed drives,
refrigeration, compressed air equipment, appliances, and other equipment. A complete list of
the measures offered through New Construction is included in Supplement 1:
Cost-Effectiveness. The customer may otherwise lose savings opportunities for these types of
projects. The new construction and major renovation project design and construction process
often encompasses multiple calendar years. In addition to the customer incentive, a PAI is
available to architects and/or engineers for supporting technical aspects and documentation of
a project.
Retrofits
The Retrofits option is Idaho Power’s prescriptive measure option for existing facilities that
offers incentives to customers in Idaho and Oregon for a defined list of energy efficiency
upgrade measures. Eligible measures cover a variety of energy-saving opportunities in lighting,
HVAC, building shell, food service equipment, and other commercial measures. A complete list
of the measures offered through Retrofits is included in Supplement 1: Cost-Effectiveness.
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Page 116 Demand-Side Management 2022 Annual Report
Program Activities—Custom Projects
The Custom Projects option provides incentives for both custom capital projects and
energy-management projects.
Incentive levels for custom capital projects remained the same in 2022, at $0.18 per kWh of
estimated kWh savings for one year, up to 70% of the project cost.
Idaho Power provides incentives for conducting pressurized, underground water leak
assessments and fixing those leaks. The program reimburses $1,000 per five miles of pipe
detected for a third-party leak assessment in addition to the standard capital project incentive
of $0.18 per kWh of first-year savings for repair.
The energy management incentive of $0.025 per first-year kWh saved, up to 100% of the
eligible costs (added in 2020), also remained the same in 2022. Compared to typical custom
capital projects, energy management projects tend to have the following:
• A shorter measure life and a much lower cost
• O&M changes that save energy without interrupting the customer’s service or product
• Cost-effective energy savings from measures rooted in low-cost or no-cost
O&M improvements.
Compressed air system leak repairs are eligible under the energy management incentive at
$0.025 per kWh estimated to be saved in one year up to 100% of project cost. Customers can
use their own instrumentation or work with one of Idaho Power’s third-party consultants to
identify leaks. Energy savings achieved from fixing leaks can be quantified, and project costs are
calculated by factoring in the material cost to fix the leaks as well as any labor requirements.
Idaho Power funds the cost of engineering services, up to $4,500, for conducting energy
scoping assessments to encourage its larger customers to adopt energy efficiency
improvements. Idaho Power is currently contracted with six firms to provide scoping
assessments and general energy efficiency engineering support services through 2025. Two of
the firms are focused on energy modeling to support cohorts and other energy management
offerings. The other four firms provide a wide array of engineering services, including scoping
assessments, detailed assessments, energy modeling, and various SEM programs.
The Custom Projects option had a successful year with a total of 106 completed projects (5 of
which were in Oregon) and achieved energy savings of 56,157 MWh (Table 16), which is a 5%
increase compared to 2021. COVID-19 impacts continued to present challenges for projects in
2022, and many projects were slowed down by materials and labor issues.
Idaho Power also received 108 new applications in 2022, representing a potential of
64,775 MWh of savings on future projects.
C&I Sector—Commercial and Industrial Energy Efficiency Program
Demand-Side Management 2022 Annual Report Page 117
In 2022, Idaho Power contractors completed 26 scoping assessments on behalf of Idaho Power
customers. These assessments identified over 28,984 MWh of savings potential and will be
used to promote future projects.
Table 17. Custom Projects annual energy savings by primary option measure, 2022
Option Summary by Measure Number of Projects kWh Saved
Compressed Air ..................................... 11 8,111,646
Controls ................................................. 1 152,413
Energy Management ............................. 19 12,323,305
Fans ....................................................... 1 2,861,994
HVAC ..................................................... 8 4,049,007
Motors ................................................... 3 207,161
Other ..................................................... 9 6,196,494
Pump ..................................................... 5 1,706,036
Refrigeration.......................................... 26 8,070,096
VFD ........................................................ 23 12,478,908
Total* .................................................... 106 56,157,060
*Does not include GMI project counts and savings.
Custom Projects engineers and the key account energy advisors visited large C&I customers to
conduct initial facility walk-throughs, commercial/industrial efficiency program informational
sessions, and training on specific technical energy-saving opportunities. Virtual/remote
capabilities were implemented when health or safety restrictions were necessary. Idaho Power
also provided sponsorship for the 2022 ASHRAE Technical Conference that focused on
Integrating with Nature and had numerous energy efficiency related presentations. Custom
Projects engineers gave presentations on Idaho Power programs and offerings at the Cohort for
Schools Final Workshop, the Treasure Valley Water Summit, and two presentations at
Wastewater Cohort Workshops (virtual).
The Streamlined Custom Efficiency (SCE) offering works to keep vendor engagement high,
targeting projects that are typically too small to participate under the Custom Projects option.
Currently, the SCE offering provides custom incentives for refrigeration controllers for walk-in
coolers, process related VFDs, and other small, vendor-based projects that do not qualify for
prescriptive incentives.
Idaho Power contracted with a third party to manage SCE data collection and analysis for each
project. In 2022, the SCE offering processed 18 projects totaling 6,365 MWh of savings and
$667,555 in incentives.
Cohorts
Idaho Power has SEM cohorts to engage with customers in group settings, allowing interaction
and economies of scale in working with multiple customers on SEM.
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Page 118 Demand-Side Management 2022 Annual Report
The Water Supply Optimization Cohort (WSOC), Wastewater Energy Efficiency Cohort
(WWEEC), and the Continuous Energy Improvement (CEI) Cohort for Schools program offerings
are driving a significant number of new projects in addition to increasing vendor engagement
from the SCE offering while providing high levels of customer satisfaction. Reported cohort
savings correlate to energy management incentives; any capital projects promoted or identified
in SEM are reported and incentivized through the Custom Projects, New Construction or
Retrofits options of the C&I Program, not as a cohort savings number.
Cohorts are structured to offer three phases of support.
1. The active phase, typically the first two years of engagement with strong consultant
support, includes energy team development, energy policy development,
energy model creation, training and report-out workshops, energy champion and
team calls, and general energy awareness.
2. The maintaining phase includes medium consultant support and is typically years
three through five or six. This phase includes consultant maintenance of facility
energy models, monthly energy champion calls, report-out workshops, and ongoing
general development.
3. The sustaining phase is typically beyond year five or six where the participants
manage activities on their own including maintenance of energy models and ongoing
focus on energy-saving activities with little consultant support. Participants in this
phase have the option to participate in report-out workshops but cohort-related
energy savings are no longer claimed, and consultant support is minimal.
Water Supply Optimization Cohort (WSOC). The WSOC began in January 2016. The goal of the
cohort is to equip water professionals with the skills necessary to independently identify and
implement energy efficiency opportunities that produce long-term energy and cost savings. The
Eastern Idaho Water Cohort (EIWC) began in January 2018 with the goal to offer the WSOC to
the eastern part of Idaho Power’s service area. These two cohorts are collectively represented
under the WSOC offering, despite EIWC being two years junior to WSOC in terms of program
life.
Sixth-year incentives (WSOC) and savings totaled $3,723 and 238,929 kWh per year. For the
participants in EIWC, fourth-year incentives and savings totaled $1,921 and 488,318 kWh per
year. Combined, incentives and savings totaled $5,644 and 727,247 kWh per year.
Idaho Power continued the cohort for 10 of the original 15 WSOC participants and both EIWC
participants will be continuing in the offering. Two participants are in the maintaining phase
and 10 are in the sustaining phase. Idaho Power’s contractor periodically contacted participants
to check on project progress and opportunities and to address energy model data updates.
C&I Sector—Commercial and Industrial Energy Efficiency Program
Demand-Side Management 2022 Annual Report Page 119
Wastewater Energy Efficiency Cohort (WWEEC). In January 2014, Custom Projects launched
WWEEC, a two-year cohort training approach and incentives for low-cost or no-cost energy
improvements for 11 municipal wastewater facilities in Idaho Power’s service area. In 2016,
Idaho Power increased the duration of WWEEC to further engage customers. Five of the 11
original participants are now in the maintaining phase and six participants are in the sustaining
phase. In 2021, one facility re-engaged with the cohort after major renovations; the facility was
re-baselined and is currently in the active phase.
In 2022 (the sixth year), the consultant contacted the participants to check on progress,
discuss opportunities, and address energy model data updates.
Continuous Energy Improvement Cohort for Schools. The goal of this cohort is to equip school
district personnel with hands on training and guidance to help them get the most out of their
systems while reducing energy consumption. The fifth program year of the Cohort for Schools
ran from June 2021 through May 2022 to coincide with the standard school calendar; reported
energy savings are based on the program year.
Seven school districts participated in the program in 2022. Of those seven, five districts are
modeling all schools in their district. Two districts added two new facilities each in this program
year for a total of 46 facilities that were engaged with the offering during the 2022 program
year. The cohort is implemented by a third-party consultant that provided final savings reports
for each school district, which totaled 7,380,223 kWh and incentive checks were provided
totaling $129,398 for 2022.
Activities in 2022 included managing a register of energy efficiency opportunities for each
facility detailing low- and no-cost opportunities to reduce energy consumption. The consultant
worked with each participant to complete as many identified opportunities as possible.
Afterward, the consultant checked in monthly by phone to review opportunity register items
and to discuss current activities. Idaho Power provided program and incentive information,
both in hard copy and electronically, along with many other energy-saving resources pertinent
to school facilities.
A final program year workshop was held on September 15, 2022, where results were reported
for the program year. Districts shared successes, lessons learned, and other details pertinent to
their energy-saving journeys.
The 2022 to 2023 program year activities will continue until May 31, 2023. Idaho Power will
review final M&V reports to establish energy savings and eligible costs for the program year
activities and will distribute the corresponding incentives to participating school districts.
Green Motors Initiative
Idaho Power participates in the Green Motors Practices Group’s (GMPG) Green Motors
Initiative (GMI). Under the GMI, service center personnel are trained and certified to repair and
C&I Sector—Commercial and Industrial Energy Efficiency Program
Page 120 Demand-Side Management 2022 Annual Report
rewind motors to improve reliability and efficiency. If a rewind returns a motor to its original
efficiency, the process is called a “Green Rewind.” By rewinding a motor under this initiative,
customers may save up to 40% of the cost of a new motor. The GMI is available to
Idaho Power’s agricultural, commercial, and industrial customers.
Currently, nine motor service centers have signed on as GMPG members in Idaho Power’s
service area. Under the initiative, Idaho Power pays service centers $2.00 per horsepower (hp)
for each National Electrical Manufacturers Association (NEMA)-rated motor up to 5,000 hp that
receives a verified Green Rewind. Half of that incentive is passed on to the customer as a credit
on their rewind invoice. The GMPG requires all member service centers to sign and adhere to
the GMPG Annual Member Commitment Quality Assurance agreement. The GMPG is
responsible for verifying QA.
In 2022, a total of nine C&I customers’ motors were rewound, and the savings for the GMI was
19,851 kWh.
Program Activities—New Construction
In 2022, a total of 88 projects were completed, resulting in 27,615,777 kWh of energy savings in
Idaho and Oregon. New Construction had an 8% reduction in number of projects and a 57%
increase in total savings compared to 2021. The C&I construction industry was extremely active
in Idaho Power’s service area in 2022, although the industry is experiencing labor shortages and
supply chain issues that have delayed, slowed, and complicated some projects.
Maintaining a consistent offering is important for large projects with long construction periods;
however, changes are made to enhance customers’ choices or to meet new code changes.
Idaho Power strives to keep the New Construction option consistent by making changes
approximately every other year. The program offerings were last updated on June 15, 2021.
In addition to the customer incentive, a PAI is available to architects and/or engineers for
supporting technical aspects and documentation of a project. The PAI is equal to 20% of the
participant’s total incentive with a maximum allowed of $5,000 per application.
The PAI increases the engagement with architects and engineers and is most beneficial to small
and medium businesses as they prepare project documentation. These customers typically do
not have staff with a technical background in construction, which makes completing
applications and submitting documentation a challenge.
In 2022, a total of 43 projects, or 49% of the projects paid, received the PAI compared to 40
projects, or 42% of the total projects paid, in 2021. The PAI will continue to be offered due to
positive feedback from customers, architects, and engineers.
In 2022, Idaho Power collaborated with IDL and revised the on-site verification process.
The new process ensures that the final project documentation aligns with field installation
C&I Sector—Commercial and Industrial Energy Efficiency Program
Demand-Side Management 2022 Annual Report Page 121
before project payment. On-site project verification occurred on eight of the 88 projects, 9% of
the total projects completed.
The New Construction engineers and Idaho Power energy advisors continued outreach to
customers, professionals, and professional organizations throughout 2022. Meetings were held
with specific customers or professionals to build relationships with the local design community
and to discuss Idaho Power’s New Construction option as well as the overall C&I Energy
Efficiency Program. An Idaho Power representative attended eight Lunch and Learn sessions
provided by the IDL to provide energy efficiency program information to attendees.
Additionally, Idaho Power EOEAs and New Construction engineers presented program
information to one professional organization, two Pocatello design firms, two Twin Fall design
firms and three Boise area design firms with their clients. Energy efficiency program
information was also hand delivered to five Pocatello design firms. Idaho Power energy advisors
also provided energy efficiency program information during customer visits and calls.
See Supplement 2: Evaluation for the complete IDL report.
Program Activities—Retrofits
The Retrofits option achieved 22,890,678 kWh of energy savings in 2022, representing
525 projects. Lighting retrofits comprised most of the energy savings and project count.
Idaho Power offered two in-person technical lighting training classes for trade allies and large
customers on the topic of networked/luminaire level lighting controls. The company received
feedback that while there was interest in attending the training, many trade allies were too
busy to do so. Retrofits staff also provided virtual online training to trade allies, as requested.
The company posted a lighting tool tutorial to the Retrofits website for trade allies and
customers wanting to take part in a self-directed learning opportunity on how to use the
lighting tool.
Idaho Power continued its contracts with various consultants to provide ongoing program
support for lighting and non-lighting reviews and inspections, as well as trade ally outreach.
Marketing Activities
Idaho Power continued to primarily market the C&I Energy Efficiency Program as a single
offering to businesses.
See the C&I Sector Overview for the company’s additional efforts to market the C&I Energy
Efficiency Program. Below are the option-specific marketing efforts for 2022.
Custom Projects
In addition to program-level marketing activities, Idaho Power created multiple brochures
including a Custom Projects program overview, Industrial Wastewater Cohort brochure,
and Water Leaks brochure. Idaho Power continued to present large-format checks to interested
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Page 122 Demand-Side Management 2022 Annual Report
Custom Projects participants and publicized these events to local media, when applicable.
Several of these were facilitated by key account energy advisors in 2022.
In 2022, Idaho Power continued to promote GMI as part of the C&I Energy Efficiency Program
marketing efforts.
New Construction
The company continued to place banners on select construction sites highlighting that the
facility is being built or enhanced with energy efficiency in mind. A banner remained at
St. Luke’s McCall Medical Center throughout 2022.
Retrofits
The company placed two pop-up ads on My Account: one in February that resulted in
4,693 views and 52 clicks and the second in May that resulted in 7,096 views and 42 clicks from
business customers.
The company placed an ad twice in the Pocatello Chamber of Commerce newsletter in March
and ran a marquee on their website. In April, the company mailed 1,420 letters promoting
Retrofits to Boise Metro Chamber of Commerce members. Periodically, the company sent out
emails promoting the lighting incentives. The company’s customer solutions advisors then
followed up by making personal phone calls to customers who received the email.
Cost-Effectiveness
Custom Projects
Historically, all projects submitted through the Custom Projects option must meet
cost-effectiveness requirements, which include TRC, UCT, and PCT tests from a project
perspective. The program requires that all costs related to the energy efficiency
implementation and energy-savings calculations are gathered and submitted with the program
application. Payback is calculated with and without incentives, along with the estimated dollar
savings for installing energy efficiency measures. As a project progresses, any changes to the
project are used to recalculate energy savings and incentives before the incentives are paid to
the participant. To aid in gathering or verifying the data required to conduct cost-effectiveness
and energy-savings calculations, third-party engineering firms are sometimes used to provide
an assessment, or engineering M&V services are available under the Custom Projects option.
The UCT and TRC ratios for the program are 2.88 and 1.12, respectively. Non-energy impacts
were applied in 2022 based on an estimated per-kWh value by C&I end-uses. These values were
provided by a third-party as part of the 2019 impact evaluation of the New Construction and
Retrofits options. Details for the program cost-effectiveness are in Supplement 1: Cost-
Effectiveness.
C&I Sector—Commercial and Industrial Energy Efficiency Program
Demand-Side Management 2022 Annual Report Page 123
New Construction
To calculate energy savings for the New Construction option, Idaho Power verifies the
incremental efficiency of each measure over a code or standard practice installation baseline.
Savings are calculated through two main methods. When available, savings are calculated using
actual measurement parameters, including the efficiency of the installed measure compared to
code-related efficiency. When precise measurements are unavailable, savings are calculated
based on industry-standard assumptions. Because the New Construction option is prescriptive
and the measures are installed in new buildings, there are no baselines of previous measurable
kWh usage in the building. Therefore, Idaho Power uses industry standard assumptions and the
International Energy Conservation Code (IECC) to calculate the savings based on an assumed
baseline (i.e., how the building would have used energy absent of efficiency measures).
New Construction incentives are based on a variety of methods depending on the measure
type. Incentives are calculated mainly through a dollar-per-unit equation using square footage,
tonnage, operating hours, or kW reduction.
The UCT and TRC ratios for the program are 4.25 and 3.64, respectively. Non-energy impacts
were applied in 2022 based on an estimated per-kWh value by C&I end-uses. These values were
provided by a third party as part of the 2019 impact evaluation of the New Construction and
Retrofits options. The increase in the program’s overall cost-effectiveness is largely due to the
increase in savings between 2021 and 2022. Finally, if the amount incurred for the 2022
evaluation was removed from the program’s cost-effectiveness, the UCT would be 4.34, while
the TRC would be 3.70.
Complete, updated measure-level details for cost-effectiveness can be found in Supplement 1:
Cost-Effectiveness.
Retrofits
For 2022, Idaho Power used most of the same savings and assumptions as were used after the
program changes in 2021 for the Retrofits option. For all lighting measures, Idaho Power uses a
Lighting Tool developed by a third party. An initial analysis is conducted to see if the lighting
measures shown in the tool are cost-effective based on the average input of watts and hours of
operation, while the actual savings for each project are calculated based on specific information
regarding the existing and replacement fixture. For most non-lighting measures, deemed
savings from the Technical Reference Manual (TRM) or the RTF are used to calculate the
cost-effectiveness.
The UCT and TRC ratios for the program are 2.01 and 1.11, respectively. Non-energy impacts
were applied in 2022 based on an estimated per-kWh value by C&I end-uses. These values were
provided by a third-party as part of the 2019 impact evaluation of the New Construction and
Retrofits options. Finally, if the amount incurred for the 2022 evaluation was removed from the
program’s cost-effectiveness, the UCT would be 2.03, while the TRC would be 1.11.
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Page 124 Demand-Side Management 2022 Annual Report
Complete updated measure-level details for cost-effectiveness can be found in Supplement 1:
Cost-Effectiveness.
Customer Satisfaction
In 2022, a survey was sent to Retrofits customers who had a lighting project installed by a
contractor to evaluate the customers’ satisfaction level for the contractors listed on the
website. Survey questions gathered information about how customers learned of the program
and their satisfaction with the program, contractor, and equipment.
A survey invitation was sent to 243 program participants in 2022. Idaho Power received survey
results from 76 respondents. Some highlights include the following:
• More than 63% of respondents learned of the program from a contractor, and more
than 14% learned of the program from an Idaho Power employee.
• Nearly 83% of respondents said they were “very satisfied” with the program,
and more than 14% of respondents indicated they were “somewhat satisfied.”
• More than 89% of respondents said they were “very satisfied” with the contractor
they hired to install their equipment, and more than 9% of respondents indicated
they were “somewhat satisfied.”
• More than 89% of respondents said they were “very satisfied” with the equipment
installed, and nearly 8% of respondents said they were “somewhat satisfied.”
A copy of the survey results is included in Supplement 2: Evaluation.
Evaluations
The Custom Projects option process and impact evaluation was done in 2021, but due to the
timing of receiving the report all recommendations were not addressed in the Demand-Side
Management 2021 Annual Report. The evaluation found a successfully run program that has
mitigated many of the risks associated with custom energy efficiency programs. The evaluation
team identified only minor adjustments to claimed savings and calculated a realization rate of
99.8%. The process evaluation recommended three items that were addressed in 2022:
Update the commercial and industrial program logic model to include recent program updates.
This was done to include provision for new energy management and other program details
in 2022.
Add a new construction or equipment replacement check box for the program application.
This was considered but not chosen for implementation given the complexity of some Custom
projects and potential confusion of which box to check. A Custom Projects check box and
Custom Projects information tab were added to the prescriptive New Construction preliminary
application and Custom Projects engineers were made aware of the project for additional
follow-up.
C&I Sector—Commercial and Industrial Energy Efficiency Program
Demand-Side Management 2022 Annual Report Page 125
Continue to focus on efficient and effective communication between all parties. As COVID-19
restrictions eased, more in-person trainings and customer visits were conducted.
Hybrid meetings (in-person with virtual option) were scheduled, allowing increased access and
attendance for customers, staff, and stakeholders.
A complete copy of the evaluation is included in Supplement 2: Evaluation.
New Construction
The New Construction option process and impact evaluation was conducted in 2021 and the
report was finalized in 2022. The evaluation found a successfully run program that actively
engages with the marketplace on new construction projects to impact the design and
construction of new C&I facilities. The program stays current with code requirements and
works with individual buildings to ensure they exceed code for the appropriate design and
construction period. The evaluation team found only slight adjustments to ex-ante savings
claimed in the 2021 program and limited opportunities for process improvements. The
evaluation team calculated a realization rate of 102.5%. Following are the recommendations
from the evaluation and Idaho Power’s plan for each one.
Document project worksheets at stages throughout the process. Idaho Power will incorporate
this recommendation going forward.
Increase program review and feedback of the submitted code-checking software, COMcheck.
Idaho Power will review and revise the lighting review checklist to incorporate this
recommendation in 2023.
Document the HVAC control systems that meet code and exceed code. Idaho Power will review
and revise the HVAC control review checklist to incorporate this recommendation in 2023.
Continue to expand in-person outreach and program overview training where possible.
Idaho Power will continue to provide in-person outreach and program overview training in
2023. New Construction will attend Retrofit workshops in 2023 to increase the cross-training
between program options.
Consider developing a consolidated contractor list across CIEE program with substantial overlap.
Idaho Power CIEE program staff will develop a consolidated contractor list in 2023.
Consider a leave-behind brochure for contractors with all CIEE program offerings. Idaho Power
has a CIEE leave-behind brochure for contractors, architects, and engineers. The company will
review potential benefits to updating the brochure to provide enhanced clarity to the various
program options available for customers; in addition, the company will review opportunities to
increase brochure distribution in 2023.
The complete copy of the evaluation is included in Supplement 2: Evaluation.
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Page 126 Demand-Side Management 2022 Annual Report
Retrofits
The Retrofits option process and impact evaluation was conducted in 2021 and the report was
finalized in 2022. The evaluation for the Retrofits option found a successfully run program that
balances the use of prescriptive assumptions and values with the data collection from the
project site. The program stays current with baseline requirements and the program savings
calculations are accurate and well-documented. The overall realization rate for the Retrofits
option is 96.4%. Following are the recommendations from the evaluation and Idaho Power’s
responses.
Develop the exterior lighting controls savings factors. Idaho Power will incorporate this
recommendation in its lighting tool update in 2023.
Document lighting control savings for transparency to the applicant. Idaho Power will
incorporate this recommendation in its lighting tool update in 2023.
Consider incorporating interactive effects into the Retrofits lighting tool. Idaho Power reviewed
this recommendation and determined it will not incorporate interactive effects into the lighting
tool. The Retrofits team is presently looking for ways to streamline the lighting tool to
encourage increased participation in the program. Adding additional information for project
submitters to address would be a barrier to participation. In addition, the company would
prefer not to incur costs for programming the lighting tool to capture interactive effects.
Consider adjusting the anti-sweat heater measure to differentiate between medium- and low-
temperature refrigeration. Idaho Power will incorporate this recommendation as part of the
Retrofits program update in 2023.
Continue to increase in-person program overview training where possible. Idaho Power will
continue to increase in-person trainings, to include holding in-person Retrofit program
workshops for trade allies in 2023.
Consider developing a consolidated contractor list across CIEE programs with substantial
overlap. Idaho Power CIEE program staff will develop a consolidated contractor list in 2023.
Consider a leave-behind brochure for contractors with all CIEE programs. Idaho Power has a C&I
Energy Efficiency Program leave-behind brochure for trade allies. The company will review
potential opportunities to update the existing brochure to provide enhanced clarity to the
various program options available for customers; in addition, the company will review
opportunities to increase brochure distribution in 2023.
The complete copy of the evaluation is included in Supplement 2: Evaluation.
2023 Plans
In 2023, the three options will continue to be marketed as part of Idaho Power’s C&I Energy
Efficiency Program. Below are specific program option strategies.
C&I Sector—Commercial and Industrial Energy Efficiency Program
Demand-Side Management 2022 Annual Report Page 127
Custom Projects
In 2023, the company plans to expand deployment of the commercial energy-savings tool,
Find n’ Fix, which, in conjunction with engineering services, helps identify and quantify energy
savings opportunities for commercial customers. Also, the compressed air leak detection and
repair offering that is available to larger customers, like the water-leak measure launched in
2020, will be marketed and expanded in 2023.
Activities and coaching will continue for the school, water, and wastewater cohort participants.
The Industrial Wastewater Energy Cohort officially began in September of 2022. This cohort
focuses on a more technical approach to energy savings than the other water and wastewater
cohorts. Recruitment and energy scans to identify electrical energy saving opportunities have
been completed and active savings have begun. This cohort offers technical trainings that are
extended to non-cohort participants to continue the engagement of customers in the
Idaho Power programs.
Idaho Power is currently in the process of contracting for a new cohort called the Campus
Cohort for Energy Efficiency. This cohort will be structured similarly to the existing cohorts but
will focus on customers who have facilities with multiple buildings on a site, such as but not
limited to universities, government installations, hospitals, and prisons.
Idaho Power will continue to provide the following:
• In-person or virtual site visits and energy scoping assessments by Custom Projects
engineers to identify projects and energy savings opportunities.
• Funding for detailed energy assessments for larger, complex projects. Virtual
assessments can also be offered in many cases.
• M&V of larger, complex projects. Virtual M&V can also be used as conditions allow.
• Technical training for customers, presented virtually or in person as conditions allow.
New Construction
In 2023, Idaho Power will identify and incorporate best practices and recommendations
identified in the impact and process evaluation completed in 2022.
As in past years, Idaho Power will continue to build relationships in 2023 by sponsoring
technical training through the IDL to address the energy efficiency education needs of design
professionals throughout Idaho Power’s service area.
Retrofits
Idaho Power will address the third-party impact and process evaluation recommendations as
outlined above.

C&I Sector—Commercial Energy-Saving Kits
Page 128 Demand-Side Management 2022 Annual Report
Commercial Energy-Saving Kits
2022 2021
Participation and Savings
Participants (kits) 334 906
Energy Savings (kWh) 48,758 296,751
Demand Reduction (MW) n/a n/a
Program Costs by Funding Source
Idaho Energy Efficiency Rider $21,604 $71,501
Oregon Energy Efficiency Rider $1,140 $3,117
Idaho Power Funds $25 $0
Total Program Costs—All Sources $22,770 $74,617
Program Levelized Costs
Utility Levelized Cost ($/kWh) $0.059 $0.029
Total Resource Levelized Cost ($/kWh) $0.059 $0.029
Benefit/Cost Ratios
Utility Benefit/Cost Ratio 0.78 1.64
Total Resource Benefit/Cost Ratio 0.87 2.00

Description
The Commercial Energy-Saving Kit (Commercial ESK) program is offered to commercial business
customers in Idaho and Oregon. One kit was offered to business customers who had not
previously received a commercial kit. The kit included: two 9-watt LED A lamps, two 8-watt LED
BR30 lamps, a bathroom aerator, an exit sign retrofit, and a kitchen aerator. Idaho Power used
a third-party vendor for kit assembly and mailing. The vendor sent the kit directly to the
customer on the company’s behalf.

Figure 22. Commercial Energy-Saving Kit
C&I Sector—Commercial Energy-Saving Kits
Demand-Side Management 2022 Annual Report Page 129
Program Activities
Idaho Power contracted with a new commercial kit vendor mid-year in 2022. The company
streamlined the kit offer to one kit type, which included seven measures.
Table 18. Number of kits distributed per state and associated energy savings
State Total Distributed kWh Savings
Idaho* 317 46,237
Oregon 17 2,520
* Includes 10 restaurant, 1 retail, and 12 office kits distributed from remaining inventory.
Marketing Activities
In 2022, Idaho Power promoted the commercial kits using LinkedIn posts in November.
Additionally, the kits were promoted in September and December in the quarterly newsletter
to business customers, Energy@Work.
The company displayed a pop-up ad to small business customers who logged into My Account
in October, November, and December, resulting in 298 users clicking on the ad. Customers
signing into My Account clicked on the pop-up ad and requested a kit through the vendor’s
online order form.
In November, the company sent an email to 8,651 business customers. This tactic resulted in a
46.55% open rate and 118 kits were ordered that day. Idaho Power’s customer solutions
advisors (CSA) also promoted the commercial kit during their calls with business customers and
offered to sign up customers who requested the kit during the call.
Cost-Effectiveness
Because no deemed savings values exist for the Commercial ESK program, Idaho Power made
several assumptions. When the offering launched in mid-2018, the installation rates of the
items in the kit were unknown. Idaho Power estimated the installation rates based on
professional judgement. Idaho Power updated this assumption in 2021 based on the follow-up
survey sent to customers in 2020. In 2022, evaluators surveyed 2021 participants and updated
the installation rates for each item.
For the LEDs and aerators, savings vary by kit type based on the average annual hours of use
(HOU) and annual gallons of water used by business type. In 2022, energy advisors distributed
10 restaurant kits, 1 retail kit, and 12 office kits that were remaining in inventory. Based on the
updated savings assumptions from the evaluation, restaurant, retail, and office kits provide
approximately 192, 208, and 56 kWh of annual savings, respectively.
At the November 2021 EEAG meeting, Idaho Power shared the cost-effectiveness challenges for
the kit program and proposed four possible options. With direction from EEAG, it was decided
to simplify the offering to one kit, continue sending the kit per customer request, and track the
C&I Sector—Commercial Energy-Saving Kits
Page 130 Demand-Side Management 2022 Annual Report
business type ordering the kit. Of the 311 simplified kits distributed in 2022, 14 were
distributed to restaurants, 38 were distributed to retail businesses, and 259 were distributed to
offices. Based on the savings developed by the evaluators using the installation rates from the
evaluation, the savings ranged from 83 kWh (non-electric office) to 500 kWh (electric
restaurant).
As further discussed with EEAG in 2022, the offering continues to face cost-effectiveness
challenges. When the Energy Independence and Security Act is fully implemented in July 2023,
the evaluators recommended removal of LED bulbs from the kit offering going forward. Due to
the declining savings opportunities and rising costs, the kits will not be cost-effective
going forward.
For more information about the cost-effectiveness savings and assumptions, see Supplement 1:
Cost-Effectiveness.
Customer Satisfaction
In 2022, the third-party evaluator surveyed customers as part of the impact and process
evaluation of the Commercial ESKs. The purpose of the surveys was to understand the
installation rates of the items included in the kits as well as participants’ overall satisfaction
with the offering.
The majority of respondents were “satisfied” or “very satisfied” with the program (88.4%) and
about half of respondents were interested in learning more about other energy efficiency
opportunities through Idaho Power (51.6%). While the majority of respondents who
remembered receiving a kit indicated they installed at least one measure from the kit (95.6%),
Idaho Power plans to continue to survey participants, as certain items such as the LED retrofit
kits for exit signs and faucet aerators had low installation rates, which impacted the savings
reported for the items. Idaho Power plans to continue to survey customers to update the
assumptions around installation rates.
Survey results are included in the impact and process evaluation report available in
Supplement 2: Evaluation.
Evaluations
In 2022, Idaho Power contracted a third party to conduct process and impact evaluations for
the Commercial ESK program. Following are the recommendations of the evaluations and Idaho
Power’s response to each.
To more accurately estimate verified savings, the evaluators recommend Idaho Power continue
to update their in-service rate (ISR) assumptions when calculating claimed savings for future
program years. Idaho Power will continue to update the ISR assumptions.
C&I Sector—Commercial Energy-Saving Kits
Demand-Side Management 2022 Annual Report Page 131
The evaluators recommend Idaho Power continue to update their electric water heat saturation
assumptions when calculating claimed savings for future program years. Idaho Power will
monitor participating customer feedback about electrical water heat use and update program
assumptions, as needed.
The evaluators recommend Idaho Power include space heating and space cooling interactive
effects when calculating claimed savings for lighting measures in the future. Idaho Power has
reviewed this recommendation and will not implement the recommendation because the
company would have to put in place a way of getting information from the customer on heating
and cooling system types; as the company is not certain how long it will continue the program,
it prefers not to adjust any processes at this time.
The evaluators recommend Idaho Power alter assumed hours of use for retail applications to
4,533 hours per year. Idaho Power will update the retail hours of use per the recommendation.
The evaluators recommend that Idaho Power plan to remove LED measures from the
Commercial Energy-Saving Kits Program. The resulting verified savings for the measure will be
claimable until July 1, 2023. After this date, third party evaluators must assume that all
unqualified lighting measures have been replaced by LED measures due to burnout. Idaho
Power will discontinue offering LED measures in a commercial kit by July 1, 2023.
The evaluators recommend that Idaho Power provide more opportunities for participating
customers to learn about other offerings Idaho Power provides. Idaho Power evaluates its
marketing efforts to business customers to learn about the various available energy efficiency
programs on a regular basis. The company will take this recommendation under advisement as
it pursues marketing efforts in 2023.
The evaluators recommend Idaho Power staff reconsider the inclusion of retrofit exit signs and
low-flow aerators altogether for kits moving forward. Although these measures can garner
energy savings, they are not popular among kit recipients and thus may not be cost-effective
measures to provide consumers. Rather than provide unwanted measures, such as retrofit exit
signs, pre-rinse spray valves, and low-flow aerators, Idaho Power staff should consider providing
other measures such as occupancy sensors, as customers indicate a desire for such applications.
Idaho Power included low-flow aerators and retrofit exit signs in its most recent single kit
offering; however, the company scaled back to one of each. Idaho Power plans to consult its
commercial kit vendor to identify any additional measures that could be cost-effectively viable
to install in a future commercial kit.
The complete impact and process evaluation report can be found in Supplement 2: Evaluation.
C&I Sector—Commercial Energy-Saving Kits
Page 132 Demand-Side Management 2022 Annual Report
2023 Plans
In 2023, Idaho Power will continue to market the program until the contract is complete.
In addition, Idaho Power will send customer satisfaction surveys to program participants.
C&I Sector—Flex Peak Program
Demand-Side Management 2022 Annual Report Page 133
Flex Peak Program
2022 2021
Participation and Savings
Participants (buildings) 159 139
Energy Savings (kWh) n/a n/a
Demand Reduction (MW)* 24.5/30.0 30.6/36.0
Program Costs by Funding Source
Idaho Energy Efficiency Rider $84,582 $101,236
Oregon Energy Efficiency Rider $151,148 $175,121
Idaho Power Funds $283,888 $225,617
Total Program Costs—All Sources $519,618 $501,973
Program Levelized Costs
Utility Levelized Cost ($/kWh) n/a n/a
Total Resource Levelized Cost ($/kWh) n/a n/a
Benefit/Cost Ratios
Utility Benefit/Cost Ratio n/a n/a
Total Resource Benefit/Cost Ratio n/a n/a
* Maximum actual demand reduction/maximum potential demand reduction. Demand response program reductions are reported with
9.7% peak loss assumptions.
Description
The Flex Peak Program is a voluntary program where participants are eligible to earn a financial
incentive for reducing load. The program is available to Idaho and Oregon C&I customers with
the objective to reduce the demand on Idaho Power’s system during periods of extreme peak
electricity use.
Program event parameters include the following:
• June 15 to September 15 (excluding weekends and holidays)
• Up to four hours per day between 3 and 10 p.m.
• Up to 16 hours per week
• No more than 60 hours per season
• At least three events per season
Customers with the ability to offer load reduction of at least 20 kW are eligible to enroll in the
program. The 20-kW threshold allows a broad range of customers to participate in the program.
Participants receive notification of a load reduction event four hours before the start of
the event.
The program originated in 2009 as the FlexPeak Management program managed by a
third-party contractor. In 2015, Idaho Power took over full administration and changed the
name to Flex Peak Program. The IPUC issued Order No. 33292 on May 7, 2015, while the OPUC
C&I Sector—Flex Peak Program
Page 134 Demand-Side Management 2022 Annual Report
approved Advice No. 15 03 on May 1, 2015, authorizing Idaho Power to implement an internally
managed Flex Peak Program (Schedule No. 82 in Idaho and Schedule No. 76 in Oregon) and to
continue recovering its demand response program costs in the previous manner.
Program Activities
In 2022, 69 participants enrolled 159 sites in the program. Existing customers were
automatically re-enrolled. Participants had a committed load reduction of 29.5 MW in the first
week of the program and ended the season with a committed load reduction of 27.2 MW.
The estimated maximum capacity of the program came from the nominated amount in the
third week of the season at 30 MW.
This weekly commitment, or nomination, was comprised of all 159 sites. The maximum
realization rate during the season was 86%, and the average for the seven events was 62%.
The realization rate is the percentage of load reduction achieved versus the amount of load
reduction committed for an event. The highest hourly load reduction achieved was 24.5 MW
(at generation level) during the July 28 event (Table 19).
Table 19. Flex Peak Program demand response event details
Event Details
,

Ju
ly
26
,

28

8
,

17

,
31

Event time 5–9 p.m. 5–9 p.m. 5–9 p.m. 5–9 p.m. 6–10 p.m. 5–9 p.m. 5–9 p.m.
Average temperature 97.0° F 101.6° F 101.0° F 97.0° F 96.3° F 98.3° F 102.0° F
Maximum load reduction (MW) 18.7 24.5 21.1 21.1 19.2 14.4 15.6

Event performance and realization rates for the 2022 season were lower than prior years in the
program. Impacts from COVID-19 with respect to supply chain and production issues appears to
still be playing a role in participants’ ability to reduce load.
Marketing Activities
New program parameters per IPUC Case IPC-E-21-32 and OPUC Docket No. ADV 1355/Advice
No. 21-12 (replacing the IPC-E-13-14/UM 1653 Settlement agreement) went into effect in 2022.
In 2022, the program brochures and website were updated to reflect the new program
parameters. The company ran a My Account pop-up ad promoting enrollment to large
commercial customers. In May, the company launched a new email and direct-mail marketing
tactic to 18 national accounts in its service area. Additionally, a LinkedIn post in May promoted
program enrollment, and a thank-you note to participants was posted on LinkedIn in
November. The company also continued to include the Flex Peak Program in its C&I Energy
Efficiency Program collateral. Additional details can be found in the C&I Sector Overview.
C&I Sector—Flex Peak Program
Demand-Side Management 2022 Annual Report Page 135
Cost-Effectiveness
Idaho Power determines cost-effectiveness for its demand response program using the
approved method for valuing demand response under IPUC Order No. 35336 and the OPUC’s
approval on February 8, 2022 in Docket No. ADV 1355. Using the financial and alternate
resource cost assumptions from the 2021 Integrated Resource Plan, the defined
cost-effectiveness threshold for operating Idaho Power’s three demand response
programs for the maximum allowable 60 hours is $82.91 per kW under the current
program parameters.
The Flex Peak Program was dispatched for 28 event hours and achieved a maximum load
reduction of 24.5 MW and a maximum nomination capacity of 30 MW throughout the season.
The total cost of the program in 2022 was $519,618. Had the Flex Peak Program been used for
the full 60 hours, the potential cost would have been approximately $700,200. Using the
potential cost and the average maximum capacity results in a cost of $23.34 per kW,
which shows the program was cost-effective.
A complete description of Idaho Power cost-effectiveness of its demand response programs is
included in Supplement 1: Cost-Effectiveness.
Customer Satisfaction
In November, Idaho Power sent surveys to program participants and non-participants.
The purpose of the surveys was to evaluate the motivators and barriers to participation as well
as gauge customers’ likelihood to participate in the program under varying program designs.
Participants were asked additional questions around their overall satisfaction with the program
and the ease of participation.
Idaho Power received 33 responses from the participant survey and 25 responses from the
non-participant survey. Some highlights include the following:
• For participants, nearly 55% of respondents participated in the program because they
wanted to earn an incentive for providing demand reduction while 27% participated
because they wanted to help reduce overall electrical usage on hot summer days.
For non-participants, almost 52% of the respondents did not participate in the program
because they did not know about it while nearly 30% of respondents indicated it would
negatively impact their business.
• Overall, 76% of participant survey respondents indicated they were “very satisfied” or
“somewhat satisfied” with the Flex Peak program with 84 to 94% of respondents
indicating they were “very satisfied” or “somewhat satisfied” with various components
of the program including the program support from Idaho Power, post-performance
data, and timeliness of receiving the incentive payment/bill credit.
C&I Sector—Flex Peak Program
Page 136 Demand-Side Management 2022 Annual Report
• Nearly 85% of participant survey respondents indicated they are “very likely” or
“somewhat likely” to participate in the program in 2023.
• Respondents were asked their likelihood to participate in the program if Idaho Power
limited the number of times the program could be called each week at a reduced
incentive level.
• Under all scenarios, 42 to 48% of current participants indicated they are
“very unlikely” or “somewhat unlikely” to participate in the program under the
proposed hypothetical scenario options.
• Under all scenarios, 40 to 52% of current non-participants indicated they are
“very unlikely” or “somewhat unlikely” to participate in the program under the
proposed hypothetical scenario options.
A copy of the survey results is included in Supplement 2: Evaluation.
Evaluations
Idaho Power conducted an internal evaluation of the program’s potential load-reduction
impacts. A copy of this report is in Supplement 2: Evaluation.
In 2021 Idaho Power engaged a third-party contractor to conduct an impact evaluation of the
Flex Peak Program. The evaluation found the Flex Peak Program to have been operated
effectively in 2021, and the method for calculating demand reductions to have been
appropriately applied with only minor discrepancies, mostly related to rounding practices.
Recommendations from this evaluation are listed below, followed by Idaho Power’s response:
Use consistent rounding practices and streamline analytical approach through computer
scripting and develop documentation regarding rules for handling errors, missing data,
and other data validation steps. Idaho Power has developed a Statistical Analysis System (SAS)
program to input all metering data and run all calculations. This was developed to make all
calculations consistent, remove human error and to streamline the calculation process.
Establish data validation and quality control protocols. The developed SAS code is written to
remove erroneous data and to flag errors that would affect baseline calculations for
human review.
Continue to work with customers to refine their nominated load reductions. The program
specialist and energy advisors continue to work with participants to identify nominations that
need to be refined to reflect realistic load reductions more accurately.
2023 Plans
For the 2023 program season, Idaho Power has requested program changes from the IPUC and
the OPUC. These changes will add an automatic dispatch option feature to the program that
Idaho Power believes may make it easier for some customers to participate.
C&I Sector—Flex Peak Program
Demand-Side Management 2022 Annual Report Page 137
The company will continue to communicate the program value with enrolled customers and the
importance of active participation when events are called. Idaho Power will meet with existing
participants during the off-season to discuss past season performance and upcoming season
details.
For the upcoming season, Idaho Power will continue its focus on retaining currently enrolled
participants and will be using email marketing, paid search, digital display, and other tactics to
boost program enrollment, with a focus on enrolling national chain stores within Idaho Power’s
service area. Energy assessments conducted by Idaho Power engineers or contract engineers
will be offered to large customers that haven’t participated in the past to help determine
potential for load shed and identify specific load shed tactics and sequences that could be
initiated for events. The program will also continue to be marketed along with the C&I Energy
Efficiency Program.
C&I Sector—Oregon Commercial Audits
Page 138 Demand-Side Management 2022 Annual Report
Oregon Commercial Audits
2022 2021
Participation and Savings
Participants (audits) 12 3
Energy Savings (kWh) n/a n/a
Demand Reduction (MW) n/a n/a
Program Costs by Funding Source
Idaho Energy Efficiency Rider $0 $0
Oregon Energy Efficiency Rider $7,493 $4,401
Idaho Power Funds $0 $0
Total Program Costs—All Sources $7,493 $4,401
Program Levelized Costs
Utility Levelized Cost ($/kWh) n/a n/a
Total Resource Levelized Cost ($/kWh) n/a n/a
Benefit/Cost Ratios
Utility Benefit/Cost Ratio n/a n/a
Total Resource Benefit/Cost Ratio n/a n/a

Description
Oregon Commercial Audits identifies opportunities for all Oregon C&I building owners,
governmental agencies, schools, and small businesses to achieve energy savings. Initiated in
1983, this statutory required program (ORS 469.865) is offered under Oregon Tariff Schedule
No. 82.
Through this program, Idaho Power provides no-cost energy audits, evaluations,
and educational products to customers through a third-party contractor. During the audits,
the contractor inspects the building shell, HVAC equipment, lighting systems, and operating
schedules, if available, and reviews past billing data. These visits provide an opportunity for the
contractor to discuss available incentives and specific business operating practices for energy
savings. The contractor may also distribute energy efficiency program information and remind
customers that Idaho Power personnel can offer additional energy-savings tips and
information. Business owners can decide to change operating practices or make capital
improvements designed to use energy wisely.
Program Activities
During 2022, there were 12 audits completed at separate facilities for five customers.
The program contractor conducted the audits, and an Idaho Power energy advisor was available
to assist customers.
C&I Sector—Oregon Commercial Audits
Demand-Side Management 2022 Annual Report Page 139
Marketing Activities
Idaho Power sent its annual direct-mailing to 1,557 Oregon commercial customers in December
to explain the program’s no-cost or low-cost energy audits and the available incentives
and resources.
Cost-Effectiveness
As previously stated, the Oregon Commercial Audits program is a statutory program offered
under Oregon Schedule 82, the Commercial Energy Conservation Services Program.
Because the required parameters of the Oregon Commercial Audits program are specified in
Oregon Schedule 82 and the company abides by these specifications, this program is deemed
to be cost-effective. Idaho Power claims no energy savings from this program.
2023 Plans
Idaho Power does not expect to make any operational changes in 2023. The company will
continue to market the program through the annual customer notification and will consider
additional opportunities to promote the program to eligible customers via its energy advisors.

C&I Sector—Small Business Direct Install
Page 140 Demand-Side Management 2022 Annual Report
Small Business Direct Install
2022 2021
Participation and Savings
Participants (audits) 680 452
Energy Savings (kWh) 3,228,365 2,421,842
Demand Reduction (MW) n/a n/a
Program Costs by Funding Source
Idaho Energy Efficiency Rider $1,317,820 $1,052,943
Oregon Energy Efficiency Rider $27,558 -$20,887
Idaho Power Funds $51 $0
Total Program Costs—All Sources $1,345,429 $1,032,056
Program Levelized Costs
Utility Levelized Cost ($/kWh) $0.049 $0.062
Total Resource Levelized Cost ($/kWh) $0.049 $0.062
Benefit/Cost Ratios
Utility Benefit/Cost Ratio 0.95 0.99
Total Resource Benefit/Cost Ratio 1.50 1.54

Description
Idaho Power launched the SBDI program in November 2019 targeting typically hard-to-reach,
small business customers in Idaho who use less than 25,000 kWh annually. Idaho Power pays
100% of the cost to assess eligibility and install lighting measures for these customers, using a
third-party contractor to operate the program. SBDI is offered to eligible customers in a
strategic geo-targeted approach.
Program Activities
In 2022, the company continued offering the SBDI program to customers in southern Idaho,
expanding to the company’s Treasure Valley area early in the year. Idaho Power sent
direct-mail letters to customers informing them of their eligibility to participate, and the
contractor followed up with calls offering another opportunity to hear about the program and
declare their interest in participating. As customers responded to the letters and follow-up
calls, lighting assessments were scheduled. Customers who agreed to have LEDs installed at
their facility were scheduled for project installation. The SBDI contractor scheduled 823 lighting
assessments, completed 680 project installations, and completed 70 post-installation
inspections.
C&I Sector—Small Business Direct Install
Demand-Side Management 2022 Annual Report Page 141
Marketing Activities
Idaho Power sent 4,054 direct-mail letters to business customers in the Capital Region,
3,179 letters to business customers in the Canyon-West Region, and 253 letters to business
customers in the Southern Region in 2022. The program contractor followed up with
2,100 phone calls after customers received the letters.
Cost-Effectiveness
In 2022, the projects in the SBDI program were all lighting upgrades. Idaho Power’s third-party
contractor calculates the savings based on the existing fixture wattage, the replacement fixture
wattage, and the HOU. The UCT and TRC ratios for the program are 0.95 and 1.50 respectively.
Non-energy impacts were applied in 2022 based on an estimated per kWh value by C&I
end-uses. These values were provided by a third-party as part of the 2019 impact evaluation of
the New Construction and Retrofits options. In 2022, Idaho Power discussed the cost-
effectiveness challenges facing the program in the future with EEAG. These challenges include
the reduced savings potential from screw-in bulbs and increased costs associated with
materials and labor. As the cost of this free service rises, it will be increasingly difficult for the
program to be cost-effective from the UCT perspective. As a result, the offering will close in
March 2023 once the program has been fully offered across the service area.
Details for the program cost-effectiveness are in Supplement 1: Cost-Effectiveness.
Customer Satisfaction
Idaho Power’s third-party implementer sent 680 customer satisfaction surveys to
program participants in 2022, of which 196 surveys were completed. Key highlights include
the following:
• More than 95% of respondents said they were “very satisfied” with the program,
and just over 4% of respondents indicated they were “somewhat satisfied.”
• Nearly 96% of respondents found it “very easy” to participate in the program and
almost 4% reporting it was “somewhat easy” to participate in the program.
• All respondents reported they would be likely to recommend the program to other
small businesses, with over 92% of respondents saying they were “very likely” and
nearly 8% reporting they were “somewhat likely.”
• All respondents were satisfied with the equipment installed at their business, with
nearly 95% of respondents reporting they were “very satisfied” and just over 5% of
respondents saying they were “somewhat satisfied.”
• When asked how their opinion of Idaho Power has changed since participating in the
program, over 58% of respondents reporting having a more favorable opinion of
Idaho Power, and nearly 42% of respondents reported no change in opinion.
C&I Sector—Small Business Direct Install
Page 142 Demand-Side Management 2022 Annual Report
As part of the process evaluation conducted on the program in 2021, the evaluators
recommended additional customer satisfaction follow-up with nonresponding customers.
In 2022, Idaho Power worked with the third-party implementer to identify non-respondents to
the implementer’s customer satisfaction survey. Idaho Power sent 296 customer satisfaction
surveys to program participants in 2022, of which 47 surveys were completed. Key highlights
include the following:
• More than 89% of respondents said they were “very satisfied” with the program,
and more than 8% of respondents indicated they were “somewhat satisfied.”
• More than 94% of respondents reported they were “very satisfied” with the equipment
installed, and more than 6% of respondents indicated they were “somewhat satisfied.”
• More than 89% of respondents said they were “very satisfied” with the customer service
provided by the company installing the equipment, and more than 6% of respondents
indicated they were “somewhat satisfied.”
A copy of the survey results is included in Supplement 2: Evaluation.
2023 Plans
Idaho Power will continue to operate this program as described above until the program has
been fully offered across its service area, which is March 2023; at that time Idaho Power will
close the program.

Irrigation Sector Overview
Demand-Side Management 2022 Annual Report Page 143
Irrigation Sector Overview
The irrigation sector is comprised of agricultural customers operating water pumping or water
delivery systems to irrigate agricultural crops or pasturage. End-use electrical equipment
primarily consists of agricultural irrigation pumps and center pivots. The irrigation sector does
not include water pumping for non-agricultural purposes, such as the irrigation of lawns, parks,
cemeteries, golf courses, or domestic water supply.
In July 2022, the active irrigation service locations totaled 21,324 system-wide, which is an
increase of 1.2% compared to July 2021. The increase is primarily caused by adding service
locations for pumps and center pivot irrigation systems as land is converted from furrow and
surface irrigation to sprinkler irrigation.
Irrigation customers accounted for 1,949,766 MWh of energy usage in 2022,
versus 2,125,733 MWh in 2021. The approximately 8% decrease is primarily because of
substantial rain that occurred in June. This sector represented nearly 12.3% of Idaho Power’s
total electricity sales, and approximately 29% of July sales. Though annual electricity use may
vary substantially for weather-related reasons, and there are now more irrigation customers,
the energy-use trend for this sector has not changed significantly in many years because of
the following:
• The added energy usage from new customers is relatively small compared to the energy
use of the average existing customer
• Ongoing improvements through energy efficiency efforts and system replacement offset
much of the added energy use
The Irrigation Efficiency Rewards program, including the GMI, experienced decreased annual
savings: from 9,699,849 kWh in 2021 to 6,954,805 kWh in 2022. This was due primarily to a
decrease in the savings and measures from small maintenance upgrades in the Menu Incentive
Option of the program.
Idaho Power re-enrolled the majority of the 2021 Irrigation Peak Rewards participants in 2022,
with 2,142 service points and a maximum load reduction potential of 255.6 MW. Table 20
summarizes the overall expenses and program performance for both programs and shows the
actual load reduction was 155.1 MW.

Irrigation Sector Overview
Page 144 Demand-Side Management 2022 Annual Report
Table 20. Irrigation sector program summary, 2022
Total Cost Savings
Program Participants Utility Resource
Annual Energy (kWh)
Peak Demand (MW)*
Demand Response
Irrigation Peak Rewards .................................. 2,142 $ 8,503,140 $ 8,503,140 155.1/255.6
Total .......................................................................................................... $ 8,503,140 $ 8,503,140 155.1/255.6
Energy Efficiency
Irrigation Efficiency Rewards .......................... 519 2,080,027 14,083,686 6,937,855
Green Motors Initiative—Irrigation ................ 6 0 5,634 16,950
Total .......................................................................................................... $ 2,080,027 $ 14,089,320 6,954,805
Notes:
See Appendix 3 for notes on methodology and column definitions.
Totals may not add up due to rounding.

Irrigation DSM Programs
Irrigation Efficiency Rewards. An energy efficiency program designed to encourage customers
to replace or improve inefficient irrigation systems and components. Customers receive
incentives through the Custom Incentive Option for extensive retrofits and new systems and
through the Menu Incentive Option for small maintenance upgrades.
Irrigation Peak Rewards. A demand response program designed to reduce load from irrigation
pumps during periods of high energy demand or for other system needs. Participating service
points are automatically controlled by Idaho Power switches or manually interrupted by the
customer for very large pumping installations or when switch communication is not available.
Green Motor Initiative. Under the GMI, service center personnel are trained and certified to
repair and rewind motors to improve reliability and efficiency. If a rewind returns a motor to its
original efficiency, the process is called a “Green Rewind.” Idaho Power pays service centers to
rewind qualified irrigation motors. Half of this incentive is then given to the customer as a
credit on the rewind invoice.
Marketing
In 2022, the company mailed a summer edition of Irrigation News to all irrigation customers in
its service area. In part, the newsletter educated customers about how to sign up for new or
upgraded service, momentary outage improvements, planning for safety, My Account
information, changes to the Irrigation Efficiency Rewards program, and updates to the Irrigation
Peak Rewards program.
Irrigation Sector Overview
Demand-Side Management 2022 Annual Report Page 145
The application for new or upgraded service was put into a tear-pad version so during one-on-
one visits agricultural representatives (ag reps) could easily tear off an application and provide
to irrigator.
The company also placed numerous print ads in agricultural publications to reach the target
market in smaller farming communities. Publications included the Capital Press, Power County
Press/Aberdeen Times, Potato Grower magazine, Owyhee Avalanche, and The Ag Expo East and
West programs. Idaho Power used radio advertising to show support for the Future Farmers of
America and Ag Week conferences.
January through March, the company ran 1,796 radio ads promoting the Irrigation Efficiency
Rewards program. The 30-second spots ran in eastern and southern Idaho on a variety of
stations, including news/talk, sports, classic rock, adult hits, and country.
Customer Satisfaction
Idaho Power conducts the Burke Customer Relationship Survey each year. In 2022, on a scale of
zero to 10, irrigation survey respondents rated Idaho Power 8.08 regarding offering programs
to help customers save energy, and 7.95 related to providing customers with information on
how to save energy and money. Twenty-three percent of irrigation respondents indicated they
have participated in at least one Idaho Power energy efficiency program. Of the irrigation
survey respondents who have participated in at least one Idaho Power energy efficiency
program, 89% are “very” or “somewhat” satisfied with the program.
Training and Education
Idaho Power continued to market its irrigation programs by offering virtual and in-person
workshops and offering new presentations to irrigation customers. In 2022, Idaho Power
provided three virtual irrigation workshops for the Irrigation Efficiency Rewards and Irrigation
Peak Rewards programs; this number was greatly reduced compared to a typical year due to
COVID-19. Approximately 18 customers attended virtual workshops. In December 2022,
Idaho Power provided one in-person workshop in Oregon with 20 customers in attendance.
In October program staff attended the first annual Idaho Farm and Ranch Conference in Boise
and hosted a booth.
Field Staff Activities
Idaho Power agricultural representatives (ag reps) were available to be on-site with customers
in 2022, offering Idaho Power energy efficiency and demand response program information,
education, training, and irrigation system assessments and audits across the service area.
Also, in 2022, ag reps continued their engagement with agricultural irrigation equipment
dealers with the goal of sharing expertise about energy-efficient system designs and increasing
awareness about the program. Ag reps and the irrigation segment coordinator, a licensed
Irrigation Sector Overview
Page 146 Demand-Side Management 2022 Annual Report
agricultural engineer, participated in training sponsored by the nationally based
Irrigation Association to maintain or obtain their Certified Irrigation Designer and Certified
Agricultural Irrigation Specialist accreditations.

Irrigation Sector—Irrigation Efficiency Rewards
Demand-Side Management 2022 Annual Report Page 147
Irrigation Efficiency Rewards
2022 2021
Participation and Savings*
Participants (projects) 525 1,031
Energy Savings (kWh) 6,954,805 9,699,849
Demand Reduction (MW) n/a n/a
Program Costs by Funding Source
Idaho Energy Efficiency Rider $1,950,122 $2,350,620
Oregon Energy Efficiency Rider $74,622 $221,523
Idaho Power Funds $55,284 $35,057
Total Program Costs—All Sources $2,080,027 $2,607,200
Program Levelized Costs
Utility Levelized Cost ($/kWh) $0.027 $0.023
Total Resource Levelized Cost ($/kWh) $0.179 $0.166
Benefit/Cost Ratios**
Utility Benefit/Cost Ratio 2.69 3.32
Total Resource Benefit/Cost Ratio 2.54 4.49
* 2021 total includes 19,352 kWh of energy savings from 12 Green Motors projects. 2022 total includes 16,950 kWh of energy savings from
6 Green Motors projects.
** 2021 cost-effectiveness ratios include evaluation expenses. If evaluation expenses were removed from the program’s cost-effectiveness, the 2021 UCT and TRC would be 3.34 and 4.49, respectively.
Description
Initiated in 2003, the Irrigation Efficiency Rewards program encourages energy-efficient
equipment use and design in irrigation systems. Qualified irrigators in Idaho Power’s service
area can receive financial incentives and reduce their electricity usage through participation in
the program. Two options help meet the needs for major or minor changes to new or existing
systems: Custom Incentive Option and Menu Incentive Option. Irrigation customers can also
qualify for an incentive when they “rewind” their irrigation motors.
Custom Incentive Option
The Custom Incentive Option is offered for extensive retrofits to existing systems or the
installation of an efficient, new irrigation system.
For a new system, Idaho Power determines whether the equipment is more energy efficient
than the standard before approving the incentive. If an existing irrigation system is changed to
a new water source, it is considered a new irrigation system under this program. The incentive
for a new system is $0.25 per estimated kWh saved in one year, not to exceed 10% of the
project cost.
Irrigation Sector—Irrigation Efficiency Rewards
Page 148 Demand-Side Management 2022 Annual Report
For existing system upgrades, the incentive is $0.25 per estimated kWh saved in one year or
$450 per estimated kW demand reduction, whichever is greater. The incentive is limited to 75%
of the total project cost.
The qualifying energy efficiency measures include hardware changes that result in a
reduction of the potential kWh use of an irrigation system or that result in a potential demand
reduction. Idaho Power reviews and analyzes each project, considering prior usage history,
irrigation system maps, system design details, invoices, and, in many situations,
post-installation demand data to verify savings and incentives.
Menu Incentive Option
The Menu Incentive Option covers a portion of the costs of repairing and replacing specific
components that help the irrigation system use less energy. This option is designed for systems
where small maintenance upgrades provide energy savings from these 7 measures:
• New flow-control type nozzles
• New nozzles for impact, rotating, or fixed head sprinklers
• New or rebuilt impact or rotating type sprinklers
• New or rebuilt wheel-line levelers
• New complete low-pressure pivot package (sprinkler, regulator, and nozzle)
• New drains for pivots or wheel lines
• New riser caps and gaskets for hand lines, wheel lines, and portable main lines
Incentives are based on a predetermined kWh savings per component from the RTF. Based on
the evaluation that the RTF completed in 2021, the kWh annual savings changed for many
components with some components being removed because the savings were no longer
supported. On January 1, 2022, Idaho Power changed the list of eligible components to exclude
new wheel-line hubs, goosenecks, pipe repair, and center pivot base boot gaskets. Any invoice
dated prior to January 1, 2022, was eligible for the previous measures and incentive amounts
for up to one year from the date of the invoice.
Green Motors Initiative
Idaho Power also participates in the GMPG GMI. Under the initiative, Idaho Power pays service
centers $2.00 per hp for motors 15 to 5,000 hp that received a verified Green Rewind. Half of
that incentive is passed on to irrigation customers as a credit on their rewind invoice.
Program Activities
In 2022, a total of 519 projects were completed: 439 Menu Incentive Option projects that
provided an estimated 2,633 MWh of energy savings, and 80 Custom Incentive Option projects
that provided 4,305 MWh of energy savings (45 new systems and 35 existing systems).
Irrigation Sector—Irrigation Efficiency Rewards
Demand-Side Management 2022 Annual Report Page 149
Also, a total of six irrigation customers’ motors were rewound under the GMI and accounted for
16,950 kWh in savings.
Marketing Activities
In addition to activities mentioned in the Irrigation Sector Overview, the Idaho Power ag rep
and program specialist worked one-on-one with irrigation dealers and vendors who are key to
the successful promotion of the program. In March 2022, the ag reps held three virtual
workshops. The content was the same but offered a morning, noon, and afternoon option on
three different days so customers could easily join. The virtual seminar focused on the Irrigation
Efficiency Rewards program, Idaho Power’s website, and self-help tools. The ag rep also visited
each irrigation vendor in their area to distribute new menu efficiency applications and explain
the program changes.
Cost-Effectiveness
Idaho Power calculates cost-effectiveness using different savings and benefits assumptions and
measurements for the Custom Incentive Option and the Menu Incentive Option.
Each application under the Custom Incentive Option received by Idaho Power undergoes an
assessment to estimate the energy savings that will be achieved through a customer’s
participation in the program. On existing system upgrades, Idaho Power calculates the savings
of a project by determining what changes are made and comparing it to the service point’s
previous five years of electricity usage on a case-by-case basis. On new system installations,
the company uses standard practices as the baseline and determines the efficiency of the
applicant’s proposed project. Based on the specific equipment to be installed, the company
calculates the estimated post-installation energy consumption of the system. The company
verifies the completion of the system design through aerial photographs, maps, and field visits
to ensure the irrigation system is installed and used in the manner the applicant’s
documentation describes.
Each application under the Menu Incentive Option received by Idaho Power also undergoes an
assessment to ensure deemed savings are appropriate and reasonable. Payments are
calculated on a prescribed basis by measure. In some cases, the energy-savings estimates are
adjusted downward from deemed RTF savings to better reflect known information on how the
components are actually being used. For example, a half-circle rotation center pivot will save
half as much energy per sprinkler head as a full-circle rotation center pivot. All deemed savings
are based on seasonal operating hour assumptions by region. If a system’s usage history
indicates it has lower operating hours than the assumptions, like the example above,
the deemed savings are adjusted.
The RTF irrigation hardware maintenance workbook version 5.3 is the source of all savings
assumptions for the Menu Incentive Option. In spring 2021, the RTF updated the savings
Irrigation Sector—Irrigation Efficiency Rewards
Page 150 Demand-Side Management 2022 Annual Report
assumptions for the irrigation hardware measures based on survey results from Idaho Power,
BPA, and PacifiCorp. While measure savings did not change significantly, the survey results did
support an increase in the measure life from 4–5 years to 6–7 years. However, four measures
(wheel-line hubs, goosenecks with drop tube, cut and pipe press or weld repair, and new center
pivot base boot gaskets) showed little to no savings, thus those measures were removed from
the updated irrigation workbook. With no supported savings, Idaho Power removed the
measures from the Menu Incentive Option in 2022.
The changes to the measure offerings were effective on December 31, 2021. Any invoice dated
December 31, 2021, or before and submitted within one year was processed under the prior
program measure incentive list. For invoices with dates of January 1, 2022, and later,
the applications were processed under the updated measure list and incentive levels.
The UCT and TRC for the program are 2.69 and 2.54, respectively.
Complete measure-level details for cost-effectiveness can be found in Supplement 1:
Cost-Effectiveness. Assumptions for measures processed before the program update can be
found in the Demand-Side Management 2021 Annual Report, Supplement 1: Cost-Effectiveness.
2023 Plans
Irrigation Efficiency Rewards program marketing plans typically include conducting at least six
customer-based irrigation workshops to promote energy efficiency, technical education,
and program understanding. Idaho Power has committed to a booth at the Idaho Irrigation
Equipment Show & Conference, Western Ag Expo, Idaho Potato Show, and the Southern Ag
Expo in 2023. The focus of the booth material and conversations will be to promote the
Irrigation Efficiency Rewards program and what customers can do to obtain incentives from
Idaho Power. Marketing the program to irrigation supply companies will continue to be a
priority, as they are an important part of getting the program in front of customers.
The company will promote the program in agriculturally focused editions of newspapers,
magazines, and radio ads. The radio ads will run during the winter/spring throughout the
company’s South-East region.

Irrigation Sector—Irrigation Peak Rewards
Demand-Side Management 2022 Annual Report Page 151
Irrigation Peak Rewards
2022 2021
Participation and Savings
Participants (service points) 2,142 2,235
Energy Savings (kWh) n/a n/a
Demand Reduction (MW)* 155.1/255.6 255.5/319.5
Program Costs by Funding Source
Idaho Energy Efficiency Rider $569,467 $239,101
Oregon Energy Efficiency Rider $272,171 $167,041
Idaho Power Funds $7,661,502 $6,607,173
Total Program Costs—All Sources $8,503,140 $7,013,315
Program Levelized Costs
Utility Levelized Cost ($/kWh) n/a n/a
Total Resource Levelized Cost ($/kWh) n/a n/a
Benefit/Cost Ratios
Utility Benefit/Cost Ratio n/a n/a
Total Resource Benefit/Cost Ratio n/a n/a
* Maximum actual demand reduction/maximum potential demand reduction. Demand response program reductions are reported with
9.7% peak loss assumptions.
Description
Idaho Power’s Irrigation Peak Rewards program is a voluntary, demand response program
available to all agricultural irrigation customers. Initiated in 2004, the purpose of the program is
to minimize or delay the need for new supply-side resources.
The program pays irrigation customers a financial incentive to interrupt the operation of
specific irrigation pumps using one or more control devices and offers two interruption options:
Automatic Dispatch Option and Manual Dispatch Option. Automatic Dispatch Option pumps are
controlled by an AMI or cellular device that remotely turns off the pump(s). Manual Dispatch
Option pumps can participate if they have 1,000 cumulative hp or if Idaho Power has
determined the AMI or cellular technology will not function properly at that location. Manual
Dispatch Option customers nominate a kW reduction and are compensated based on the actual
load reduction during the event.
Program event parameters for both interruption options are listed below:
• June 15 to September 15 (excluding Sundays and holidays)
• Up to four hours per day between 3 and 10 p.m. (Standard Interruption) or 3 and
11 p.m. (Extended Interruption)
• Up to 16 hours per week
• No more than 60 hours per season
Irrigation Sector—Irrigation Peak Rewards
Page 152 Demand-Side Management 2022 Annual Report
• At least three events per season
The incentive structure consists of fixed and variable payments. The fixed payments are credits
that are applied to the monthly billing during the months of June through October. The fixed
credits are based on the customer’s actual demand and use, and reduce the monthly billed
amount. The variable payments are additional incentives that are paid beginning with the fifth
event. The variable payments are calculated at the end of the season and are mailed to the
customers in the form of a check.
The fixed incentive amount is $5.25 per kW with an energy incentive of $0.008 per kWh.
The fixed incentive demand (kW) credit is calculated by multiplying the monthly billing kW
usage by the fixed incentive amount. The energy (kWh) incentive credit is calculated by
multiplying the monthly billing kWh usage by the energy incentive amount. The fixed incentive
is applied to monthly bills, and credits are prorated for periods when reading/billing cycles do
not align with the program season dates. An additional variable incentive of $0.18 (Standard
Interruption) per kWh applies to the fifth and subsequent events that occur between 3 p.m.
and 10 p.m. The variable incentive is increased to $0.25 per kWh when customers allow
Idaho Power to interrupt their pumps for 4 hours between 3 p.m. and 11 p.m. For the
Automatic Dispatch Option service points, the variable incentive is calculated using the billed
demand (kW) during the billing cycle/period of the event, multiplied by the length of the event
in hours multiplied by the applicable variable incentive rate. For the participating Manual
Dispatch Option participants, the variable incentive payment is calculated based on the actual
demand (kW) reduction during the event hours multiplied by the length of the event in hours
multiplied by the applicable variable incentive rate. The variable incentive is paid in the form of
a check no later than 70 days after the program season.
Program rules allow customers to opt out of dispatch events while incurring an opt-out fee of
$6.25. The opt-out fee is calculated by multiplying $6.25 times the kW cost based on the
current month’s billing or kW not achieved for Manual Dispatch Option participants. The kW
not achieved for the Manual Dispatch Option refers to the amount that was nominated versus
the actual kW reduction that was achieved. At the start of the season the manual customers
nominate the amount of kW reduction they plan to achieve during a demand response event.
The opt-out penalties will not exceed the total credit that would have been paid with
full participation.
Program Activities
Changes to the program as authorized by the OPUC and the IPUC in 2022 included lengthening
the season from August 15 to September 15; changing the event window to later in the
evening; increasing the fixed and variable incentives; changing the threshold from three to
Irrigation Sector—Irrigation Peak Rewards
Demand-Side Management 2022 Annual Report Page 153
four events for when the variable incentive is paid; and opening enrollment to all agricultural
irrigation customers.
In 2022, Idaho Power enrolled 2,142 (10%) of the eligible service points in its service area in the
program. The total billing demand of participating service locations was 346.3 MW versus
402.8 MW in 2021. The total maximum potential reduction (capacity) for the program was
255.6 MW in 2022 versus 319.5 MW in 2021. The key factor impacting the lower maximum
capacity was participation concern over the later evening hours and labor issues in getting
systems going again after events. Another factor was that during enrollment for the program
the water supply forecast looked to be very low, so customers felt they would have less ability
to make up for load reduction events.
A primary ongoing activity each year is maintaining communication and device failure
identification and correction both pre-season and during the season. Device failure is affected
by many things outside the company’s control, from customer electrical panel or wiring issues
to actual component failure in the device. The company used three electrical contractors in
2022 to maintain, troubleshoot, repair, and exchange the AMI devices and cellular devices that
are attached to customers electrical panels to be able to turn pumps off during events.
Table 21 shows the event performance by date and group. The total load reduction shown in
2022 is less than 2021 because Idaho Power had a smaller number of total MW enrolled in the
program in 2022. The program was used on eleven days. Nine days had two groups
participating and two days had all four groups participating, for 43 total event hours.
The program achieved an actual maximum demand reduction of 155.1 MW (at generation
level) on September 2, with all groups participating.
Table 21. Irrigation Peak Rewards demand response event details

,

7
,

Ju
ly
12

,

26

,
27

,

28
,

,
8 , 9

Event Time

6–10 4–9 4–9 5–10 4–9 4–10 3–9 4–9 4–10 3–10 6–10
A, B C, D A, C B, D A, C B, D C, D A, B B, C A, B, C, D
*
95° F 101° F 100° F 102° F 103° F 104° F 104° F 99° F 103° F 101° F 101° F
Load
eduction (MW)
121.2 109.1 113.5 76.2 102.6 76.8 83.9 75.1 86.8 155.1 152.1
*National Weather Service, recorded in the Boise area
Irrigation Sector—Irrigation Peak Rewards
Page 154 Demand-Side Management 2022 Annual Report
Marketing Activities
New program parameters per IPUC Case IPC-E-21-32 and OPUC Docket No. ADV 1355/Advice
No. 21-12 (replacing the IPC-E-13-14/UM 1653 Settlement agreement) went into effect in 2022
and allowed Idaho Power to market the program to all potential customers.
In 2022, the program brochures and website were updated to reflect the new program
parameters. Idaho Power used virtual workshops, direct-mail, and outreach calls to encourage
past participants to re-enroll in the program and potential new participants to enroll for the
first time. The brochure, enrollment worksheet, and contact worksheet were mailed to all
eligible participants in March 2022. See the Irrigation Sector Overview section for additional
marketing activities.
Cost-Effectiveness
Idaho Power determines cost-effectiveness for the demand response programs using the
approved method for valuing demand response under IPUC Order No. 35336 and the OPUC’s
approval on February 8, 2022, in Docket No. ADV 1355. Using the financial and alternate
resource cost assumptions from the 2021 Integrated Resource Plan, the defined
cost-effectiveness threshold for operating Idaho Power’s three demand response programs
for the maximum allowable 60 hours is $82.91 per kW under the current program parameters.
The Irrigation Peak Rewards participants were dispatched for either six or seven events,
resulting in either 24 or 28 event hours and achieved a maximum demand reduction of
155.1 MW with a maximum potential capacity of 255.6 MW. The total expense for 2022 was
$8.5 million and would have been approximately $10.5 million if the program had been
operated for the full 60 hours. Using the potential cost and the maximum potential capacity
results in a cost of $40.97 per kW, which shows the program was cost-effective.
A complete description of cost-effectiveness results for Idaho Power’s demand response
programs is included in Supplement 1: Cost-Effectiveness.
Customer Satisfaction
In November, Idaho Power sent surveys to program participants and non-participants.
The purpose of the surveys was to evaluate the motivators and barriers to participation as well
as gauge customers’ likelihood to participate in the program under varying program designs.
Participants were asked additional questions around their customer’s overall satisfaction with
the program and the ease of participation.
Idaho Power received 93 responses from the participant survey and 171 responses from the
non-participant survey. Some highlights include the following:
• For participants, nearly 42% of respondents indicated their irrigation system type and
20% indicated the time of event hours prevented them from enrolling additional
Irrigation Sector—Irrigation Peak Rewards
Demand-Side Management 2022 Annual Report Page 155
irrigation service locations in the program. For non-participants, almost 14% of the
respondents did not participate in the program because it’s too much risk to their crops
while 13% of respondents indicated it was too much trouble to coordinate their
system/labor.
• More than 47% of participant survey respondents are enrolled in the Extended
Interruption Option. Of those enrolled, 68% chose to participate because of the
increased variable incentive.
• Overall, 75% of participant survey respondents indicated they are “very satisfied”
or “somewhat satisfied” with the Peak Rewards program.
• Nearly 85% of participant survey respondent indicated they are “very likely” or
“somewhat likely” to participate in the program in 2023.
• Respondents were asked their likelihood to participate in the program if Idaho Power
limited the number of times the program could be called each week at a reduced
incentive level.
• Under all scenarios, 58 to 63% of current participants indicated they are
“very unlikely” or “somewhat unlikely” to participate in the program under the
proposed hypothetical scenario options.
• Under all scenarios, 53 to 58% of current non-participants indicated they are
“very unlikely” or “somewhat unlikely” to participate in the program under the
proposed hypothetical scenario options.
A copy of the complete report is included in Supplement 2: Evaluation.
Evaluations
Each year, Idaho Power produces an internal report of the Irrigation Peak Rewards program.
This report includes more detail on the load-reduction analysis, overall costs, and program
participation. A breakdown of the load reduction for each event day and each event hour,
including line losses, is shown in Table 22.

Irrigation Sector—Irrigation Peak Rewards
Page 156 Demand-Side Management 2022 Annual Report
Table 22. Irrigation Peak Rewards program MW load reduction for events
Event Date Groups* 3–4 p.m. 4–5 p.m. 5–6 p.m. 6–7 p.m. 7–8 p.m. 8–9 p.m. –10 p.m.
7/7/2022 A, B 115.3 121.2 119.5 119.1
7/12/2022 C, D 5.5 67.1 109.1 108.9 101.1 40.5
7/26/2022 A, C 3.1 68.5 113.5 113.5 108.7 43.0
7/27/2022 B, D 42.2 75.8 76.2 75.8 32.5
7/28/2022 A, C 5.1 59.7 102.6 102.1 96.1 40.6
7/29/2022 B, D 40.4 40.5 76.2 76.8 35.5 35.0
8/8/2022 C, D 16.3 54.4 83.9 80.6 67.8 30.2
8/9/2022 A, B 40.1 74.0 75.1 74.6 33.7
8/17/2022 B, C 4.1 55.8 86.7 86.8 81.4 29.5
9/2/2022 A, B, C, D 4.5 43.7 117.7 155.1 147.3 110.2 37.5
9/6/2022 A, B, C, D 102.8 122.7 151.0 152.1
*Group C had some customers on an early off time.
2023 Plans
For the 2023 program season, Idaho Power will continue the program as revised in 2022 as
authorized by the IPUC and the OPUC.
Irrigation Peak Rewards enrollment packets will be sent to all irrigation customers.
Each customer will be sent a comprehensive packet containing an informational brochure,
enrollment worksheet and a contact worksheet. For all new pump signups, a demand response
unit will need to be installed by a contracted electrician prior to June 15, 2023.
Idaho Power will have an informational booth at the local 2023 Ag Expos including Western,
Eastern, and Southern. The Irrigation Peak Rewards program will be the focus of in person
workshops presented by Idaho Power ag reps in spring 2023. For the upcoming season,
Idaho Power will continue its focus on retaining currently enrolled participants and will consider
using email marketing, radio, paid search, digital display, and other new tactics to boost
program enrollment. The ag reps will continue to remind and inform customers and encourage
program participation in person and by phone.

Other Programs and Activities
Demand-Side Management 2022 Annual Report Page 157
Other Programs and Activities
Idaho Power’s Internal Energy Efficiency Commitment
Renovation projects continued at the Idaho Power Corporate Headquarters (CHQ) in downtown
Boise, with a project to exchange the old T-12 parabolic lighting fixtures with LED fixtures on
floors five, six and seven. Remodels continued to incorporate energy efficiency measures,
such as lower partitions for better transfer of daylight, transom lighting, and automated
lighting controls.
The CHQ building also participated in the Flex Peak Program again in 2022 and committed to
reduce up to 200 kW of electrical demand during events. Unlike other program participants,
Idaho Power does not receive any financial incentives for its participation.
Local Energy Efficiency Funds
The purpose of Local Energy Efficiency Funds (LEEF) is to provide modest funding for short-term
projects that do not fit within Idaho Power’s energy efficiency programs but provide a direct
benefit to the promotion or adoption of beneficial energy efficiency behaviors or activities.
Because Idaho Power has been modifying its existing programs and expanding programs over
the years to include as many cost-effective energy efficiency measures as possible for all
customers, there has been minimal participation in the LEEF offering.
In 2022, Idaho Power received seven LEEF applications. They were generally related to home
equipment replacement requests for items such as windows, heating systems, door seals,
and load centers. The applications were reviewed, and the products referenced in the
submittals were found to be standard, widely available products, and therefore not appropriate
for LEEF. A residential program specialist followed up with the applicants to provide
information on incentives currently available through Idaho Power’s H&CE Program.
Energy Efficiency Advisory Group (EEAG)
Formed in 2002, EEAG provides input on enhancing existing DSM programs and on
implementing energy efficiency programs. Currently, EEAG consists of 12 members
representing a cross-section of Idaho Power customers from the residential, industrial,
commercial, and irrigation sectors, as well as individuals representing low-income households,
environmental organizations, state agencies, city governments, public utility commissions,
and Idaho Power.
EEAG meets quarterly, and when necessary, Idaho Power facilitates additional meetings and/or
calls to address special topics. In 2022, four regular virtual EEAG meetings were held on
February 9, May 4, August 11, and November 17. EEAG meetings are generally open to the
public and attract a diverse audience. Idaho Power appreciates the input from the group and
Other Programs and Activities
Page 158 Demand-Side Management 2022 Annual Report
acknowledges the commitment of time and resources the individual members give to
participate in EEAG meetings and activities.
During these meetings, Idaho Power discussed new energy efficiency program ideas and new
measure proposals, marketing methods, and specific measure details. The company provided
the status of energy efficiency programs and expenses, gave updates of ongoing programs and
projects, and supplied general information on DSM issues and other important issues occurring
in the region.
Idaho Power relies on input from EEAG to provide a customer and public-interest view of
energy efficiency and demand response. Additionally, Idaho Power regularly provides updates
on current and future cost-effectiveness of energy efficiency programs and how changes in the
IRP will impact DSM alternate costs, which Idaho Power uses in calculating cost-effectiveness.
In the meetings, Idaho Power frequently requests input and feedback from EEAG members on
programmatic changes, marketing tactics, and incentive levels.
Throughout 2022, Idaho Power relied on input from EEAG on the important topics discussed in
the sections below. For complete meeting notes, see Supplement 2: Evaluation.
Market Transformation
Idaho Power’s energy efficiency programs and activities are gradually transforming markets by
changing customers’ knowledge, use, and application of energy-efficient technologies and
principles. The traditional market transformation definition is an effort to permanently change
the existing market for energy efficiency goods and services by engaging and influencing large
national companies to manufacture or supply more energy-efficient equipment.
Through market transformation activities, there is promotion of the adoption of
energy-efficient materials and practices before they are integrated into building codes or
become standard equipment.
Idaho Power and Avista Utilities continued working with a third-party marketing firm on a
project that began in 2020 to explore potential opportunities to accelerate market
transformation; the goal is to benefit customers in both utilities’ service areas beyond what
NEEA is currently providing. This work resulted in a market transformation pilot that began in
2021 for DHPs in both Idaho Power’s and Avista’s service areas. The pilot was active throughout
2022 and will continue through 2023.
NEEA
Idaho Power has funded NEEA since its inception in 1997. NEEA’s role is to look to the future to
find emerging opportunities for energy efficiency and to create a path forward to make those
opportunities a reality in the region.
Other Programs and Activities
Demand-Side Management 2022 Annual Report Page 159
Idaho Power participates in NEEA with funding from the Idaho and Oregon Riders. The current
NEEA contract is for the five years from 2020 to 2024. NEEA categorizes the savings it achieves
in five categories: total regional savings, baseline savings, local program savings, net market
effects, and co-created saving created by NEEA and its utility funders working collaboratively.
Of the 360 to 500 average megawatts (aMW) of savings forecast for 2020 to 2024, NEEA
expects 70 to 100 aMW to be net market effects, and 115 to 152 aMW to be co-created
savings. The current contract commits Idaho Power to paying NEEA a total of $14.7 million, or
approximately $2.9 million annually.
In 2022, Idaho Power participated in all NEEA committees and workgroups, including
representation on the Regional Portfolio Advisory Committee (RPAC) and the Board of
Directors. Idaho Power representatives participate in the RPAC, Cost-Effectiveness Advisory
Committee, Commercial Advisory Committee, Regional Emerging Technology Advisory
Committee (RETAC) and the Idaho Energy Code Collaborative. The company also participated in
NEEA’s initiatives, including the Commercial Building Stock Assessment (CBSA), Residential
Building Stock Assessment (RBSA), SEM, Top-Tier Trade Ally (NXT Level), and Luminaire Level
Lighting Controls (LLLC).
NEEA performed several market progress evaluation reports (MPER) on various energy
efficiency efforts this year. In addition to the MPER, NEEA provides market research reports
through third-party contractors for energy efficiency initiatives throughout the Northwest.
Links to these and other reports mentioned below are provided in Supplement 2: Evaluation
and on NEEA’s website under Resources & Reports. For information about all committee and
workgroup activities, see the NEEA Activities information below.
NEEA Marketing
To support NEEA efforts, Idaho Power educated residential customers on Heat Pump Water
Heater (HPWH) and DHPs and educated commercial customers and participating contractors on
NXT Level Lighting Training and LLLC.
Idaho Power promoted DHPs and HPWHs as part of its H&CE Program. Full details can be found
in the H&CE Program’s Marketing section.
The company participated in NEEA’s HPWH Boring but Efficient campaign that ran on digital
channels from September 1–October 31 to continue increasing consumer awareness.
The advertising directs customers to visit their local utility’s website, find a local installer,
locate a retailer, and get product information from manufacturers.
Idaho Power continued to encourage trade allies to take the NXT Level Lighting Training.
Idaho Power posted NXT Level Lighting Training information on its website and on LinkedIn
in May.
Other Programs and Activities
Page 160 Demand-Side Management 2022 Annual Report
To promote LLLC, Idaho Power continued using a link to an informational LLLC flyer on its main
Retrofits and Lighting web pages. The company also posted about LLLCs on LinkedIn in May.
NEEA Activities: All Sectors
For the 2020 to 2024 funding cycle, NEEA and its funders have reorganized the advisory
committees into two coordinating committees: Products Coordinating Committee and
Integrated Systems Coordinating Committee. Additionally, NEEA and its funders form working
groups as needed in consultation with the RPAC. The RPAC will continue, as well as the
Cost-Effectiveness Advisory and the RETAC committees. The Idaho Energy Code Collaborative
will also remain intact.
The company currently has representation on both of the NEEA coordinating committees.
Quarterly meetings were held in 2022 for both committees. These committees provide utilities
with the opportunity to give meaningful input into the design and implementation of NEEA
initiatives, as well as to productively engage with each other. Working groups were formed by
the coordinating committees to focus on topics relevant to all sectors, as described below.
Cost-Effectiveness and Evaluation Advisory Committee
The advisory committee meets four times a year to review evaluation reports,
cost-effectiveness, and savings assumptions. One of the primary functions of the work group
is to review all savings assumptions updated since the previous reporting cycle. The committee
also reviews NEEA evaluation studies and data collection strategies and previews forthcoming
research and evaluations.
Idaho Energy Code Collaborative
Since 2005, the State of Idaho has been adopting a state-specific version of the International
Energy Conservation Code (IECC). The Idaho Energy Code Collaborative was formed to assist the
Idaho Building Code Board (IBCB) in the vetting and evaluation of future versions of the IECC for
the residential and commercial building sectors. NEEA facilitates the group, comprised of
individuals having diverse backgrounds in the building industry and energy code development.
Building energy code evaluations are presented by the group at the IBCB public meetings. The
group also educates the building community and stakeholders to increase energy code
knowledge and compliance. Idaho Power is an active member.
The Idaho Energy Code Collaborative provided statewide resources throughout 2022 to builders
and related stakeholders in support of the current codes. The resources included monthly
training sessions, a monthly technical newsletter by email, and a robust website—
IdahoEnergyCode.com. Idaho Power will continue to participate in the Idaho Energy
Code Collaborative.
Other Programs and Activities
Demand-Side Management 2022 Annual Report Page 161
Regional Emerging Technology Advisory Committee (RETAC)
Idaho Power participated in the RETAC, which met quarterly to review RETAC’s emerging
technology pipeline that was developed with assistance from the BPA, NEEA, and the NWPCC.
Throughout 2022, RETAC focused primarily on space-heating and water-heating products for
residential and commercial markets. The technologies for these products centered on heat
pumps. RETAC discussed the current state of the technologies and their associated gaps and
issues. In each RETAC session, the group discussed ways NEEA and the regional utilities could
help address those gaps and issues. This work will continue in 2023.
Regional Portfolio Advisory Committee
RPAC is responsible for overseeing NEEA’s market transformation programs and their
advancement through key milestones in the “Initiative Lifecycle.” RPAC members must reach a
full consent vote at selected milestones for a program to advance to the next stage. In 2018,
NEEA and RPAC formed an additional group called the RPAC Plus (RPAC+), which included
marketing subject matter experts to help coordinate NEEA’s marketing activities with those of
the funders. RPAC convenes quarterly meetings and adds other webinars as needed.
In 2022, RPAC conducted three of the quarterly meetings, all of which were virtual; the
November meeting was cancelled as topics were not time-sensitive and could wait until 2023.
Throughout 2022, RPAC received updates of savings forecasts, portfolio priorities, and
committee reports.
In the first regular quarterly meeting on February 23, NEEA staff went over upcoming
milestones for the NEEA initiatives and presented charter and various work group updates.
Upcoming milestone votes NEEA reviewed were: Efficient Fans, Extended Motor Products for
Pumps, High Performance HVAC, High Performance Windows, and Variable-speed Heat Pumps.
NEEA staff made the committee aware of the details involved in program advancement and
went over the timeline for each initiative.
On May 25, NEEA staff updated RPAC on recent developments and reviewed the NEEA electric
portfolio, reminding RPAC members of the key portfolio goals, programs included, current
status in NEEA’s initiative lifecycle, savings and risk profiles, and which programs help with
portfolio diversification. NEEA provided an overview on the Extended Motor Products—Pumps
and Circulators program in preparation for a committee vote to move the initiative to the next
phase of market development; the committee voted to approve that action. NEEA provided an
update on both the High-Performance HVAC program and Efficient Fans program based on an
anticipated milestone vote to advance each next quarter. NEEA staff also went over a proposal
to run the 2021 HPWH ad campaign again in September through October 2022.
At the August 24 meeting, NEEA gave RPAC members a portfolio update showing status and
outlook of each initiative. NEEA provided an overview on the Efficient Fans program in
preparation for a committee vote to move the initiative from concept development to program
Other Programs and Activities
Page 162 Demand-Side Management 2022 Annual Report
development; the committee voted to approve that action. NEEA also presented the
High-Performance HVAC program in preparation for a committee vote to move the initiative to
the next phase of market development; the committee voted to approve that action. NEEA also
presented their 2023 Operations Plan and timeline.
NEEA Activities: Residential
NEEA provides BetterBuiltNW online builder and contractor training and manages the regional
homes database, AXIS.
Residential Building Stock Assessment (RBSA)
The RBSA is a study conducted approximately every five years. Its purpose is to determine
common attributes of residential homes and to develop a profile of the existing residential
buildings in the Northwest. The information is used by the regional utilities and the NWPCC to
determine load forecast and energy-savings potential in the region. NEEA began work on the
RBSA in mid-2020.
Idaho Power participated in monthly work group meetings to discuss the study’s objectives,
framework, sampling design, and communication plan. Site visits in the region began at the end
of 2021 and continued through 2022. For residential customers who chose to participate,
the third-party contractor scheduled a site visit with a field technician who collected
information on the home’s characteristics. While site visits for single-family homes are now
complete, NEEA continues to recruit for multifamily buildings to participate in the study. Field
work will continue through early quarter 2 of 2023.
Due to delays in receiving the demographic and housing characteristics file from the 2020 U.S.
Census, completion of the study has been delayed. A final report will be available by the end
of 2023.
NEEA Activities: Commercial/Industrial
NEEA continued to provide support for C&I energy efficiency activities in Idaho in 2022, which
included partial funding of the IDL for trainings and additional tasks.
Commercial Building Stock Assessment (CBSA)
NEEA began work on the CBSA in 2022. The CBSA is a study conducted approximately every
five years, and the information is used by utilities in the Pacific Northwest and the NWPCC to
determine load forecast and electrical energy-savings potential in the region.
For commercial customers who chose to participate in the study, the third-party contractor
scheduled a site visit with a field technician who collects information on equipment and
building characteristic that affect energy consumption. This includes HVAC equipment, lighting,
building envelope, water heating, refrigeration and cooking, computers and miscellaneous
equipment, and cooling towers.
Other Programs and Activities
Demand-Side Management 2022 Annual Report Page 163
Beginning in August 2022, Idaho Power staff participated in the monthly working group.
The CBSA is still in the early design phase of the study, thus the objectives and priorities are still
being determined. A request for proposal to select a contractor will be issued in early 2023 with
site visits planned for 2024 through 2025. The report is slated to be released in early 2026.
Very High-Efficiency Dedicated Outside Air Systems (DOAS)
NEEA’s High-Performance HVAC program focused on design of market intervention strategies
based on market and field research associated with very high efficiency DOAS. Very high-
efficiency DOAS pairs a very high-efficiency heat/energy recovery ventilator (HRV/ERV) type of
DOAS with a high-efficiency heating and cooling system, while following set design principles
that maximize efficiency. NEEA updated the Very High Efficiency DOAS system requirements in
2022 based on market feedback and project experience. NEEA performed market research and
published a report titled VHE DOAS Commercial Building Decision Makers Market Research on
March 29, 2022, on building owners’ perceptions of the challenges and benefits of very high
efficiency DOAS. NEEA also created additional resources for utilities provided on the
BETTERBRICKS website.
Luminaire Level Lighting Controls (LLLC)
Throughout 2022, NEEA engaged with key manufacturers and their sales channels to encourage
promotion of LLLC to their customers and projects. NEEA continued to partner with utilities to
offer trade ally training opportunities for awareness and increased understanding of Networked
Lighting Controls (NLC)/LLLC systems. Two of the training classes were held in Idaho Power’s
service area, with 38 trade allies receiving NLC/LLLC training.
NEEA continued to offer a variety of LLLC educational resources for use by utilities and their
customers and trade allies. These materials are found at betterbricks.com. In addition, NEEA is
actively working with utilities in the Pacific Northwest to develop case studies of commercial
buildings that incorporated LLLC.
NEEA Funding
In 2020, Idaho Power and NEEA commenced a five-year agreement for the 2020 to 2024
funding cycle. Per this agreement, NEEA implements market transformation programs in the
company’s service area and Idaho Power is committed to fund NEEA based on a quarterly
estimate of expenses up to the five-year total direct funding amount of $14.7 million,
or approximately $2.9 million annually. On February 20, 2020, Idaho Power received IPUC
Order No. 34556, supporting Idaho Power’s participation in NEEA from 2020 to 2024 with such
participation to be funded through the Idaho Rider and subject to a prudency review.
In 2022, Idaho Power paid $2,789,937 to NEEA: $2,650,440 from the Idaho Rider for the Idaho
jurisdiction and $139,497 from the Oregon Rider for the Oregon jurisdiction. Other expenses
Other Programs and Activities
Page 164 Demand-Side Management 2022 Annual Report
associated with Idaho Power’s participation in NEEA activities, such as administration and
travel, were also paid from the Idaho and Oregon Riders.
Final NEEA savings for 2022 will be released later in 2023. Preliminary estimates reported by
NEEA indicate Idaho Power’s share of regional market transformation savings as 24,448 MWh.
These savings are reported in two categories: 1) codes-related and standards-related savings
of 20,344 MWh (83%) and 2) non-codes-related and non-standards-related savings of
4,104 MWh (17%).
The preliminary savings reported by NEEA for 2022 had one change in methodology.
Because code adoption varies between states, NEEA transitioned to report energy savings for
state building codes using a state allocation approach, as the funder share allocation
methodology no longer provided a reasonable representation of code savings occurring in a
funder’s service area. For non-codes related savings, NEEA continued to use the funder share
allocation methodology. Idaho Power has requested that non-codes savings use the service
area allocation approach. NEEA has committed to work with Idaho Power in 2023 to update the
assumptions used to allocate savings before shifting to this methodology for 2023 reporting.
In the Demand-Side Management 2021 Annual Report, preliminary funding-share estimated
savings reported were 17,870 MWh. The final funding-share NEEA savings for 2021 reported
herein are 16,819 MWh, and include savings from code-related initiatives as well as non-code
related initiatives. Idaho Power relies on NEEA to report the energy savings and other benefits
of NEEA’s regional portfolio of initiatives. For further information about NEEA, visit their
website at neea.org.
Regional Technical Forum
The RTF is a technical advisory committee to the NWPCC, established in 1999 to develop
standards to verify and evaluate energy efficiency savings. Since 2004, Idaho Power has
supported the RTF by providing annual financial support, regularly attending monthly meetings,
participating in subcommittees, and sharing research and data beneficial to the forum’s efforts.
The forum is made up of both voting members and corresponding members from
investor -owned and public utilities, consultant firms, advocacy groups, ETO, and BPA, all with
varied expertise in engineering, evaluation, statistics, and program administration. The RTF
advises the NWPCC during the development and implementation of the regional power plan
regarding the following RTF charter items:
• Developing and maintaining a readily accessible list of eligible conservation resources,
including the estimated lifetime costs and savings associated with those resources and
the estimated regional power system value associated with those savings.
• Establishing a process for updating the list of eligible conservation resources as
technology and standard practices change, and an appeal process through which
Other Programs and Activities
Demand-Side Management 2022 Annual Report Page 165
utilities, trade allies, and customers can demonstrate that different savings and value
estimates should apply.
• Developing a set of protocols by which the savings and system value of conservation
resources should be estimated, with a process for applying the protocols to existing or
new measures.
• Assisting the NWPCC in assessing 1) the current performance, cost, and availability of
new conservation technologies and measures; 2) technology development trends;
and 3) the effect of these trends on the future performance, cost, and availability of
new conservation resources.
• Tracking regional progress toward the achievement of the region’s conservation targets
by collecting and reporting regional research findings and energy savings annually.
The current agreement to sponsor the RTF extends through 2024. Under this agreement,
Idaho Power is the fourth largest RTF funder, at a rate of $713,300 for the five-year period.
For this funding cycle, gas utilities and the gas portion dual-fuel utilities are also funding
the RTF.
When appropriate and when the work products are applicable to the climate zones and load
characteristics in Idaho Power’s service area, Idaho Power uses the savings estimates,
measure protocols, and supporting work documents provided by the RTF. In 2022, Idaho Power
staff participated in all RTF meetings as a voting member and is represented on the RTF Policy
Advisory Committee.
Throughout the year, Idaho Power reviews any changes enacted by the RTF to savings, costs,
or parameters for existing and proposed measures. The company then determines how the
changes might be applicable to, or whether they impact, its programs and measures.
The company accounted for all implemented changes in planning and budgeting for 2022.
Residential Energy Efficiency Education Initiative
Idaho Power recognizes the value of general energy efficiency awareness and education in
creating behavioral change and customer demand for, and satisfaction with, its programs.
The REEEI promotes energy efficiency to the Residential sector. The company achieves this
by creating and delivering educational materials and programs that result in wise and
informed choices regarding energy use and increased participation in Idaho Power’s energy
efficiency programs.
Kill A Watt Meter Program
The Kill A Watt™ Meter Program remained active in 2022. Idaho Power’s Customer Care Center
and field staff continued to encourage customers to learn about the energy used by specific
appliances and activities within their homes by visiting a local library to check out a Kill A Watt
meter. It was promoted in the 2022 Energy Efficiency Guide, and on the fall energy efficiency
Other Programs and Activities
Page 166 Demand-Side Management 2022 Annual Report
bill insert, which went to all residential customers in September. The meter was also
demonstrated and promoted during the October KTVB segment.

Figure 23. Energy Efficiency Kit featuring the Kill A Watt meter
Customer Education and Marketing
REEEI produced one Energy Efficiency Guide in 2022, which was distributed primarily as an
insert in local newspapers. The year-round-themed guide was published and distributed by the
Boise Weekly and 24 newspapers in Idaho Power’s service area the week of June 26. The guide
focused on information that would be useful to customers throughout the year, including
energy-savings 101, what a kilowatt is and how customers can use a Kill A Watt meter to
measure watts, tips for working with a contractor, how to find information about energy
savings, ways to save energy during each season, an energy efficiency success story, the A/C
Cool Credit program, and information for customers considering rooftop solar.
Idaho Power promoted the guide on its homepage, on social media, and through a link emailed
to residential customers. The Idaho Statesman published two ads encouraging readers to look
for the guide. Digital ads on idahostatesman.com included a homepage takeover on June 26
and June 30, as well as banner ads that ran between June 26 and July 9, earning 150,000
impressions. Digital ads drove traffic to the Energy Efficiency Guide on idahopower.com.
Idaho Power’s website also provides links to the current guide, as well as past seasonal guides.
In 2022, over 184,000 guides were distributed throughout the service area.
Other Programs and Activities
Demand-Side Management 2022 Annual Report Page 167
REEEI distributed energy efficiency messages through a variety of other communication
methods in 2022. Idaho Power increased customer awareness of energy-saving ideas via
continued distribution of the fifth printing of the 96-page booklet 30 Simple Things You Can Do
to Save Energy, a joint publishing project between Idaho Power and The EarthWorks Group.
In 2022, the program distributed 1,550 copies directly to customers. This was accomplished
primarily by fulfilling direct web requests from customers, through energy advisors during
in-home visits, and in response to inquiries received by Idaho Power’s Customer Care Center.
Idaho Power continues to recognize that educated employees are effective advocates for
energy efficiency and Idaho Power’s energy efficiency programs. Idaho Power energy efficiency
program specialists connected with energy advisors and other employees from each of
Idaho Power’s geographical regions and the Customer Care Center to discuss educational
initiatives and answer questions about the company’s energy efficiency programs.
As COVID-19 concerns waned, opportunities to re-engage with customers at in-person
community events and venues began to return to normal. Idaho Power participated in
42 events highlighting energy efficiency messages. Program specialists and EOEAs shared
information about programs and other energy-saving ideas in an additional 667 presentations
and trainings for audiences of all ages throughout the year. To increase opportunities with adult
audiences and more secondary-school-aged young people, the EOEAs carried out a concerted
marketing effort—establishing relationships with 338 new influencers and decision-makers.
Additionally, Idaho Power’s energy efficiency program specialists responded with detailed
answers to 375 customer questions about energy efficiency and related topics that were either
forwarded from the Idaho Power’s Customer Care Center or received via Idaho Power’s
website.
Idaho Power’s social media channels and News Briefs focused on content designed to help
customers save energy, including quarterly bill inserts and emails that provided all residential
customers with easy steps to get their home ready for each season, and behavioral tips for
reducing energy use.
Other Programs and Activities
Page 168 Demand-Side Management 2022 Annual Report

Figure 24. Summer energy-saving tips
Idaho Power promoted National Energy Awareness Month on social media in October.
News Briefs and the regular KTVB television spots also highlighted Energy Awareness
Month activities.
Other Programs and Activities
Demand-Side Management 2022 Annual Report Page 169

Figure 25. Energy Awareness Month social media posts
The REEEI continued to provide energy efficiency tips in response to media inquiries and in
support of Idaho Power’s social media posts. In addition to supplying information for
publications, such as Connections and Idaho Power’s social media pages, energy efficiency
tips and content were provided for News Briefs and KTVB news segments focusing on
energy efficiency.

Figure 26. Tip Tuesday post
Other Programs and Activities
Page 170 Demand-Side Management 2022 Annual Report
2023 Program and Marketing Strategies
The initiative’s 2023 goals are to improve customer awareness of the wise use of energy,
increase program participation, and promote educational and energy-saving ideas that result in
energy-efficient, conservation-oriented behaviors.
In addition to producing and distributing educational materials, the initiative will continue to
manage the company’s Educational Distributions program. Examples of activities conducted
under Educational Distributions include developing LED lighting education material,
distributing LED nightlights, administering the SEEK program, and distributing welcome kits.
The initiative will continue to educate customers using a multi-channel approach to explore
new technologies and/or program opportunities that incorporate a behavioral component.
Distributed Energy Resources
Pursuant to Order Nos. 32846 and 32925 in Case No. IPC-E-12-27 and Order No. 34955 in Case
No. IPC-E-20-30, Idaho Power files its annual Distributed Energy Resources (DER) Status Report
with the IPUC in April each year. The report provides updates on participation levels of
customer generation, system reliability considerations, and accumulated excess net energy
credits. The report can be accessed on Idaho Power’s website (idahopower.com/solar); links to
the three most recent reports are located to the right on the web page, in the section labeled
DER/Customer Generation Status Reports.
University of Idaho Integrated Design Lab
Idaho Power is a founding supporter of the IDL (idlboise.com), which is dedicated to the
development of high-performance, energy-efficient buildings in the Intermountain West.
Idaho Power has worked with the IDL since its inception in 2004 to educate the public about
how energy efficient business practices benefit the business and the customer. In 2022,
Idaho Power entered into an agreement with the IDL to perform the tasks and services
described below.
Foundational Services
The goal of this task is to provide energy efficiency technical assistance and project-based
training to building industry professionals and customers. Requests for IDL involvement in
building projects are categorized into one of three types:
• Phase I projects are simple requests that can be addressed with minimal IDL time
• Phase II projects are more complex requests that require more involvement and
resources from the lab
• Phase III projects are significantly more complex and must be co-funded
Other Programs and Activities
Demand-Side Management 2022 Annual Report Page 171
The IDL provided technical assistance on 16 new projects in Idaho Power’s service area in 2022:
12 Phase I projects, three Phase II projects, and one Phase III project. Ten of the projects were
on new buildings, five were on existing buildings, and one was general design assistance. The
number of projects were the same compared to 2021. The related report is in the IDL section of
Supplement 2: Evaluation.
Lunch & Learn
The goal of the Lunch & Learn task is to educate architects, engineers, and other design and
construction professionals about energy efficiency topics through a series of educational
lunch sessions.
In 2022, the IDL provided 14 in-person technical training lunches. A total of 100 architects,
engineers, designers, project managers, and others attended.
The topics of the lunches (and the number performed of each) were: Ultraviolet Germicidal Air
Irradiation (1); Daylighting Multipliers (1); Thermal Energy Storage Systems (1); LLLC (3);
High-Performance Classrooms (1); The Future of Lighting Controls (3); Dedicated Outdoor Air
Systems (DOAS) Integration (1); LED Technology Impact on Savings and Efficiency (1); LEED V4.1
Daylighting Credits (1); and ASHRAE 36 High Performance Sequence of Operations for HVAC
Systems (1). The related report is in the IDL section of Supplement 2: Evaluation.
Building Simulation Users Group (BSUG)
The goal of this task is to facilitate the Idaho BSUG, which is designed to improve the energy
efficiency related simulation skills of local design and engineering professionals.
In 2022, six BSUG sessions were hosted by the IDL. Three of the six sessions were hosted in
person and three were hosted virtually due to COVID-19 restrictions at the time. The sessions
were attended by 195 professionals. Evaluation forms were completed by attendees for each
session. Analyzing results from the first six questions that rated the sessions on a scale of 1 to 5,
with 5 being “excellent” and 1 being “poor,” the average session rating was 4.37 for 2022.
For the final question, “The content of the presentation was …”on a scale of 1 to 5, with 1 being
“too basic,” 3 being “just right,” and 5 being “too advanced,” the average session rating was
3.23 for 2022.
Each presentation was archived for remote access anytime, along with general BSUG content
through the IDL website. The related report is in the IDL section of Supplement 2: Evaluation.
New Construction Verification
The goal of this task is to provide random on-site project verification on approximately 10% of
the total completed C&I Energy Efficiency Program New Construction projects. This task also
includes the desk review of all daylight photo-control incentives to improve the quality of
design and installation.
Other Programs and Activities
Page 172 Demand-Side Management 2022 Annual Report
In 2022, Idaho Power collaborated with IDL to create a new process for on-site verification to
ensure that the final project documentation aligns with field installation prior to project
payment. IDL conducted eight random on-site, project verifications. The purpose of these
verifications was to confirm accurate information was provided regarding measure installations.
The complete verification report is in the IDL section of Supplement 2: Evaluation.
Energy Resource Library (ERL)
The ERL gives customers access to resources for measuring and monitoring energy use on
various systems. The goal of this task is to operate and maintain the library, which includes a
web-based loan tracking system, and to teach customers how to use the resources in
the library.
The inventory of the ERL consists of over 900 individual pieces of equipment. In 2022, 69 new
tools were added to replace old data logging models, current transformers, air quality sensors
to complete tool kits, and added accessories for kits. The tools and manuals are available at no
cost to customers, engineers, architects, and contractors in Idaho Power’s service area to aid in
the evaluation of energy efficiency projects and equipment they are considering. Due to
COVID-19 restrictions, a contactless pick-up and drop-off system is available if desired.
In 2022, nine of the 16 tool loan requests were completed by six unique users from
seven locations, including two new users. Two additional loan requests are ongoing. The ERL
web page recorded 2,768 visits compared to 1,483 visits in 2021. The related report is in the IDL
section of Supplement 2: Evaluation.
Power over Ethernet (PoE)
In 2022, the IDL completed a literature review of the PoE technology and how it compares to
conventional lighting technology. PoE can be configured to work with many low-wattage LEDs
and can be addressed by Internet Protocol (IP) for individual control resulting in energy savings.
The IDL met with several facility managers and reached out to architects, engineers, and
consultants to find a suitable case study site. Due to project costs and installation time and
effort, a site was not discovered to use for this task. The related report for this task is in the IDL
section of Supplement 2: Evaluation.
Luminaire Level Lighting Controls (LLLC) Workshop Development
In 2022, the IDL planned and organized one LLLC workshop which consisted of a one-hour
classroom presentation and a one-hour hands-on demonstration. Ten industry professionals
attended the presentation and demonstration. The IDL installed LLLCs in their open office area
and configured them into daylighting and occupancy zones. The related report for this task is in
the IDL section of Supplement 2: Evaluation.
Other Programs and Activities
Demand-Side Management 2022 Annual Report Page 173
Design Tools Update
Over the years, the IDL has developed several digital design tools to assist local firms.
These tools require updating over time. In 2022, 12 tools were hosted on the IDL website and
made available for use and download serving as a one-stop resource for engineers and
architects for early design considerations. IDL provided priority for each tool and will update in
future tasks. The related report for this task is in the IDL section of Supplement 2: Evaluation.
2023 IDL Strategies
In 2023, the IDL will continue work on Foundational Services, Lunch & Learn sessions, BSUG,
New Construction Verifications, ERL, Design Tools Update and one new task, Fan Savings
UV Lamps.

Other Programs and Activities
Page 174 Demand-Side Management 2022 Annual Report

Conclusions
Demand-Side Management 2022 Annual Report Page 175
CONCLUSIONS
This DSM report provides a summary of activities performed by Idaho Power to offer DSM
programs to all its customers throughout 2022. All Programs are generally designed to educate,
inform, and/or reward customers.
The savings from energy efficiency programs, including the estimated savings from NEEA,
were 169,889 MWh, and the energy efficiency portfolio was cost-effective from all three
benefit/cost methodologies (UCT, TRC, and PCT).
Idaho Power successfully operated its three demand response programs in 2022, with total
demand response capacity approximately 312 MW and an actual max load reduction of
200 MW.
The DSM programs are carefully managed and monitored for ways to improve savings,
cost-effectiveness, and value to the customer. Two energy efficiency programs were closed in
2022 and three energy efficiency programs are being phased out in 2023, either because rising
costs have impacted cost-effectiveness or because market trends have lessened the impact of
the offerings and measures.
Idaho Power’s collaboration with multiple stakeholders lays the groundwork for building a
more energy efficient future with the long-term goal of permanently changing the existing
market for energy-efficient equipment and practices.
This DSM 2022 Annual Report satisfies the reporting obligation set forth by IPUC Order
No. 29419 in Case No. IPC-E-03-19.
Conclusions
Page 176 Demand-Side Management 2022 Annual Report

List of Acronyms
Demand-Side Management 2022 Annual Report Page 177
LIST OF ACRONYMS
A/C—Air Conditioning or Air Conditioner
Ad—Advertisement
AMI—Advanced Metering Infrastructure
aMW—Average Megawatt
AHRI—Air-Conditioning, Heating, and Refrigeration Institute
ASHRAE—American Society of Heating, Refrigeration, and Air Conditioning Engineers
ASHP—Air-Source Heat Pumps
B/C—Benefit/Cost
BCASEI—Building Contractors Association of Southeast Idaho
BCASWI—Building Contractors Association of Southwestern Idaho
BOMA—Building Owners and Managers Association
BPA—Bonneville Power Administration
BSU—Boise State University
BSUG—Building Simulation Users Group
BTU—British Thermal Units
C&I—Commercial and Industrial
CAP—Community Action Partnership
CAPAI—Community Action Partnership Association of Idaho, Inc.
CBSA— Commercial Building Stock Assessment
CCNO—Community Connection of Northeast Oregon, Inc.
CCS—Commissioning, Sizing, and Controls
CEI—Continuous Energy Improvement
CEL—Cost-Effective Limit
CFM—Cubic Feet per Minute
CHQ—Corporate Headquarters (Idaho Power)
CIEE—Commercial and Industrial Energy Efficiency
CINA—Community in Action
COP—Coefficient of Performance
CR&EE—Customer Relations and Energy Efficiency
CSA–Customer Solutions Advisors
CSI—College of Southern Idaho
List of Acronyms
Page 178 Demand-Side Management 2022 Annual Report
DHP—Ductless Heat Pump
DOAS—Dedicated Outside Air Systems
DOE—US Department of Energy
DR—Demand Response
DSM—Demand-Side Management
EA5—EA5 Energy Audit Program
ECM—Electronically Commutated Motor
EEAG—Energy Efficiency Advisory Group
EEI—Edison Electric Institute
EICAP—Eastern Idaho Community Action Partnership
EISA—Energy Independence and Security Act of 2007
EIWC—Eastern Idaho Water Cohort
EL ADA—El Ada Community Action Partnership
EM&V—Evaluation, Measurement, and Verification
EPA—Environmental Protection Agency
EOEA—Education and Outreach Energy Advisors
ERL—Energy Resource Library
ERV— Recovery Ventilator
ESK—Energy-Saving Kit
ETO—Energy Trust of Oregon
ft—Feet
GMI—Green Motors Initiative
GMPG—Green Motors Practice Group
GWh–Gigawatt-hour
H&CE—Heating & Cooling Efficiency
HER—Home Energy Report
HOU—Hours of Use
hp—Horsepower
HPWH—Heat Pump Water Heater
HRV—Heat Recovery Ventilator
HSPF—Heating Seasonal Performance Factor
HUD—Housing and Urban Development
List of Acronyms
Demand-Side Management 2022 Annual Report Page 179
HVAC—Heating, Ventilation, and Air Conditioning
IAQ—Indoor Air Quality
IBCA—Idaho Building Contractors Association
IBCB—Idaho Building Code Board
ID—Idaho
IDHW—Idaho Department of Health and Welfare
IDL—Integrated Design Lab
IECC—International Energy Conservation Code
IP—Internet Protocol
IPMVP—International Performance Measurement and Verification Protocol
IPUC—Idaho Public Utilities Commission
IRP—Integrated Resource Plan
ISM—In-Stadium Marketing
ISR—In-Service Rate
ISU—Idaho State University
kW—Kilowatt
kWh—Kilowatt-hour
LEEF—Local Energy Efficiency Funds
LIHEAP—Low Income Home Energy Assistance Program
LLLC—Luminaire Level Lighting Controls
M&V—Monitoring and Verification
MPER—Market Progress Evaluation Report
MVBA—Magic Valley Builders Association
MW—Megawatt
MWh—Megawatt-hour
n/a—Not Applicable
NEB—Non-Energy Benefit
NEEA—Northwest Energy Efficiency Alliance
NEEC—Northwest Energy Efficiency Council
NEEM—Northwest Energy-Efficient Manufactured Housing Program
NEMA—National Electrical Manufacturers Association
NLC—Networked Lighting Controls
List of Acronyms
Page 180 Demand-Side Management 2022 Annual Report
NPR—National Public Radio
NREL—National Renewable Energy Laboratory’s
NTG—Net to Gross
NWPCC—Northwest Power and Conservation Council
O&M—Operation and Maintenance
OPUC—Public Utility Commission of Oregon
OR—Oregon
ORS—Oregon Revised Statute
OTT—Over-the-Top
PAI—Professional Assistance Incentive
PCA—Power Cost Adjustment
PCT—Participant Cost Test
PLC—Powerline Carrier
PR—Public Relations
PTCS—Performance Tested Comfort System
QA—Quality Assurance
QC—Quality Control
RBSA—Residential Building Stock Assessment
RCT—Randomized Control Trial
REEEI—Residential Energy Efficiency Education Initiative
REM—Required Energy Modeling
RESNET—Residential Energy Services Network
RETAC—Regional Emerging Technology Advisory Committee
Rider—Energy Efficiency Rider
RIM—Ratepayer Impact Measure
RPAC—Regional Portfolio Advisory Committee
RPAC+—Regional Portfolio Advisory Committee Plus
RTF—Regional Technical Forum
SAS—Statistical Analysis System
SBDI—Small Business Direct Install
SCCAP—South Central Community Action Partnership
SCE—Streamlined Custom Efficiency
List of Acronyms
Demand-Side Management 2022 Annual Report Page 181
SEEK—Student Energy Efficiency Kits
SEICAA—Southeastern Idaho Community Action Agency
SEM—Strategic Energy Management
SIR—Savings-to-Investment Ratio
SRVBCA—Snake River Valley Building Contractors Association
TRC—Total Resource Cost
TRM—Technical Reference Manual
TSV—Thermostatic Shower Valve
UCT—Utility Cost Test
VFD—Variable Frequency Drive
WAP—Weatherization Assistance Program
WAQC—Weatherization Assistance for Qualified Customers
WSOC—Water Supply Optimization Cohort
WWEEC—Wastewater Energy Efficiency Cohort

List of Acronyms
Page 182 Demand-Side Management 2022 Annual Report

Appendices
Demand-Side Management 2022 Annual Report Page 183
APPENDICES

Appendices
Page 184 Demand-Side Management 2022 Annual Report

Appendix 1. Idaho Rider, Oregon Rider, and NEEA Payment Amounts
Demand-Side Management 2022 Annual Report Page 185
Appendix 1. Idaho Rider, Oregon Rider, and NEEA payment amounts
(January–December 2022)
Idaho Energy Efficiency Rider
2022 Beginning Balance ............................................................................................................................................ $ (6,937,705)
2022 Funding plus Accrued Interest as of December 31, 2022 ................................................................................. 34,843,936
Total 2022 Funds ........................................................................................................................................................... 27,906,231
2022 Expenses as December 31, 2022 ...................................................................................................................... (31,673,550)
Ending Balance as of December 31, 2022..................................................................................................................... $ (3,767,319)
Oregon Energy Efficiency Rider
2022 Beginning Balance ............................................................................................................................................ $ (683,982)
2022 Funding plus Accrued Interest as of December 31, 2022 ................................................................................. 2,123,512
Total 2022 Funds ........................................................................................................................................................... 1,439,530
2022 Expenses as of December 31, 2022 .................................................................................................................. (1,285,478)
Ending Balance as of December 31, 2022..................................................................................................................... $ 154,052
NEEA Payments
2022 NEEA Payments as of December 31, 2022 ........................................................................................................ $ 2,789,937
Total .............................................................................................................................................................................. $ 2,789,937

Appendix 2. 2022 DSM expenses by Funding Source
Page 186 Demand-Side Management 2022 Annual Report
Appendix 2. 2022 DSM expenses by funding source (dollars)
Sector/Program Idaho Rider Oregon Rider Non-Rider Funds Total
Energy Efficiency/Demand Response
A/C Cool Credit....................................................................... $429,722 $ 24,491 $375,558 $829,771
Easy Savings: Low-Income Energy Efficiency Education ......... — — 152,718 152,718
Educational Distributions ....................................................... 1,061,898 24,866 49 1,086,813
Energy Efficient Lighting ......................................................... 505,430 29,475 76 534,982
Heating & Cooling Efficiency Program.................................... 636,597 28,960 459 666,016
Home Energy Audit ................................................................ 184,650 0 208 184,858
Home Energy Reports ............................................................ 964,709 — 82 964,791
Oregon Residential Weatherization ....................................... — 8,825 — 8,825
Rebate Advantage .................................................................. 157,746 9,762 115 167,622
Residential New Construction Program ................................. $236,962 (1,356) 126 235,732
Shade Tree Project ................................................................. 128,673 — 183 128,856
Weatherization Assistance for Qualified Customers .............. — — 1,281,495 1,281,495
Weatherization Solutions for Eligible Customers ................... 198,198 — 7,590 205,788
Commercial/Industrial
Commercial and Industrial Energy Efficiency Program
Custom Projects ............................................................... 8,753,084 164,248 2,595 8,919,927
New Construction ............................................................ 2,762,412 17,582 513 2,780,507
Retrofits ........................................................................... 4,785,645 84,933 337 4,870,916
Commercial Energy-Saving Kits .............................................. 21,604 1,140 25 22,770
Small Business Direct Install ................................................... 1,317,820 27,558 51 1,345,429
Irrigation
Irrigation Efficiency Rewards .................................................. 1,950,122 74,622 55,284 2,080,027
Irrigation Peak Rewards ......................................................... 569,467 272,171 7,661,502 8,503,140
Energy Efficiency/Demand Response Total ............................... $24,818,689 $ 921,277 $9,822,976 $35,562,943
Market Transformation
NEEA ...................................................................................... 2,650,440 139,497 — 2,789,937
Market Transformation Total .................................................... $2,650,440 $ 139,497 $— $2,789,937
Other Programs and Activities
Commercial/Industrial Energy Efficiency Overhead ............... 826,911 44,184 2,383 873,477
Energy Efficiency Direct Program Overhead .......................... 296,204 15,653 895 312,752
Oregon Commercial Audit ...................................................... — 7,493 — 7,493
Residential Energy Efficiency Overhead ................................. 1,528,355 80,573 728 1,609,656
Other Programs and Activities Total $ 2,939,309 $ 158,556 $ 5,689 $ 3,103,553
Indirect Program Expenses
Energy Efficiency Advisory Group .......................................... 15,575 826 20 16,421
Local Energy Efficiency Funds................................................. — — — —
Special Accounting Entries ..................................................... 13,068 694 — 13,762
Indirect Program Expenses Total ............................................... $ 1,265,112 $ 66,148 $175,886 $1,507,146
Grand Total ................................................................................ $ 31,673,550 $ 1,285,478 $10,004,551 $42,963,579

Appendix 3. 2022 DSM Program Activity
Demand-Side Management 2022 Annual Report Page 187
Appendix 3. 2022 DSM program activity
Total Costs Savings Nominal Levelized Costs a
Program Participants
Program Administrator b Resource c
Annual Energy (kWh)
Peak
Demand d (MW)
Measure
Life (Years) Utility ($/kWh)
Total
Resource ($/kWh)
Demand Response1
A/C Cool Credit ........................................................................ homes $ 829,771 $ 829,771 n/a 20.1/26.8 n/a n/a n/a
Flex Peak Program ................................................................... sites 519,618 519,618 n/a 24.5/30.0 n/a n/a n/a
Irrigation Peak Rewards........................................................... service points 8,503,140 8,503,140 n/a n/a n/a n/a
Total ...................................................................................................................................................................... $ 9,852,529 $ 9,852,529 199.7/312.4
Energy Efficiency
Residential
Easy Savings: Low-Income Energy Efficiency Education 267 HVAC tune-ups 152,718 152,718 22,755 5 1.448 1.448
Educational Distributions ........................................................ 49,136 kits/giveaways 1,086,813 1,086,813 3,741,954 10 0.037 0.037
Energy Efficient Lighting .......................................................... 370,739 lightbulbs 534,982 714,445 1,728,352 15 0.030 0.040
Heating & Cooling Efficiency Program ..................................... 1,080 projects 666,016 2,414,026 1,310,260 15 0.050 0.180
Home Energy Audit ................................................................. 425 audits 184,858 239,783 28,350 11 0.771 1.000
Home Energy Report Program2 ............................................... 104,826 treatment size 964,791 964,791 20,643,379 1 0.044 0.044
Multifamily Energy Savings Program ....................................... 97 [3]units [buildings] 34,181 34,181 41,959 11 0.096 0.096
Oregon Residential Weatherization ........................................ 7 audits/projects 8,825 8,825 0 45 n/a n/a
Rebate Advantage ................................................................... 97 homes 167,622 402,649 255,541 44 0.043 0.104
Residential New Construction Program ................................... 109 homes 235,732 578,922 337,562 58 0.045 0.110
Shade Tree Project .................................................................. 1,874 trees 128,856 128,856 39,595 40 0.218 0.218
Weatherization Assistance for Qualified Customers ............... 147 homes/non-profits 1,281,495 2,028,513 272,647 30 0.338 0.535
Weatherization Solutions for Eligible Customers .................... 27 homes 205,788 205,788 48,233 30 0.307 0.307
Sector Total ....................................................................................................................................................... $ 5,690,839 $ 8,998,473 28,252,103 5 $ 0.043 $0.068
Commercial/Industrial
Commercial Energy-Saving Kits ............................................... kits 22,770 22,770 48,758 10 0.059 0.059
Custom Projects ...................................................................... projects 8,919,927 25,715,468 56,157,060 13 0.017 0.049
New Construction .................................................................... projects 2,780,507 3,641,930 27,615,777 12 0.011 0.015
Retrofits .................................................................................. projects 4,870,916 13,402,016 22,890,678 12 0.024 0.065
Small Business Direct Install .................................................... projects 1,345,429 1,345,429 3,228,365 11 0.049 0.049
Sector Total ....................................................................................................................................................... $ 17,939,548 $ 44,131,037 109,960,489 12 $ 0.018 $ 0.045
Appendix 3. 2022 DSM Program Activity
Page 188 Demand-Side Management 2022 Annual Report
Total Costs Savings Nominal Levelized Costs a
Program Participants Program Administrator b Resource c Annual Energy (kWh)
Peak Demand d (MW)
Measure Life (Years) Utility ($/kWh)
Total Resource ($/kWh)
Irrigation
Green Motors—Irrigation ........................................................ motor rewinds $ 5,634 16,950 23 n/a n/a

Sector Total ..................................................................................................................................................... $ 2,080,027 $ 14,089,320 6,954,805 18 $ 0.026 $ 0.179
Energy Efficiency Portfolio Total ..................................................................................................................... $ 25,710,414 $ 67,218,829 145,440,398 11 $ 0.021 $ 0.55
Market Transformation
Northwest Energy Efficiency Alliance (codes and standards) ........................................................................... 20,344,154
Northwest Energy Efficiency Alliance (other initiatives) .................................................................................. 4,103,978
Northwest Energy Efficiency Alliance Totals3 ................................................................................................. $ 2,789,937 $ 2,789,937 24,448,132
Other Programs and Activities
Residential
Commercial
Oregon Commercial Audits ............................................................ 12 7,493 7,493
Other
Total Program Direct Expense $ 41,456,433 $ 82,964,848 169,888,530
Indirect Program Expenses .............................................................................................................................. 1,507,146 1,507,146
Total DSM Expense .......................................................................................................................................... $ 42,963,579 $ 84,471,994
a Levelized Costs are based on financial inputs from Idaho Power’s 2019 IRP Second Amended IRP, and calculations include line-loss adjusted energy savings.
b The Program Administrator Cost is the cost incurred by Idaho Power to implement and manage a DSM program.
c The Total Resource Cost is the total expenditures for a DSM program from the point of view of Idaho Power and its customers as a whole.
d Demand response program reductions are reported with 9.7% peak loss assumptions. Maximum actual demand reduction and maximum demand capacity.
1 Peak Demand is the peak performance of each respective program and not combined performance on the actual system peak hour.
2 Savings have been reduced by 0.44% to avoid double counting of savings in other energy efficiency programs.
3

Appendix 4. 2022 DSM Program Activity by State Jurisdiction
Demand-Side Management 2022 Annual Report Page 189
Appendix 4. 2022 DSM program activity by state jurisdiction
Idaho Oregon
Program Participants
Program
Administrator
Costs
Demand Reduction (MW)/
Annual Energy
Savings (kWh) Participants
Program
Administrator
Costs
Demand Reduction (MW)/
Annual Energy
Savings (kWh)
Demand Response1
A/C Cool Credit ..................................................................... 18,910 homes $ 805,268 19.9/26.5 217 homes $ 24,503 0.2/0.3
Flex Peak Program ................................................................ 150 sites 368,458 20.4/23.7 9 sites 151,159 4.1/6.3
Irrigation Peak Rewards ........................................................ 2,708 service points 8,230,512 150.0/247.2 64 service points 272,628 5.1/8.4
Total ..................................................................................................................................................... $ 9,404,239 190.3/297.4 $ 448,291 9.4/15.0
Energy Efficiency
Residential
Easy Savings: Low-Income Energy Efficiency Education 267 HVAC tune-ups 152,718 22,755 n/a HVAC tune-ups
Educational Distributions ...................................................... 47,901 kits/giveaways 1,061,944 3,644,643 1,235 kits/giveaways 24,868 97,311
Energy Efficient Lighting ....................................................... 349,444 lightbulbs 505,503 1,628,616 21,295 lightbulbs 29,479 99,736
Energy House Calls................................................................ 50 homes 36,782 53,110 2 homes 1,380 1,406
Heating & Cooling Efficiency Program .................................. 1,053 projects 637,033 1,266,010 27 projects 28,983 44,250
Home Energy Audit ............................................................... 425 audits 184,858 28,350 n/a audits 0 0
Multifamily Energy Savings Program ................................... 97 [3] units [buildings] 32,703 41,959 0 units [buildings] 1,477 0
Oregon Residential Weatherization ...................................... n/a 0 audits/projects 8,825 0
Rebate Advantage ................................................................ 91 homes 157,855 239,031 6 homes 9,767 16,510
2
Shade Tree Project................................................................ 1,874 trees 128,856 39,595 n/a
Weatherization Assistance for Qualified Customers ............. 147 homes/non-profits 1,277,717 272,647 0 homes/non-profits 3,778 0
Weatherization Solutions for Eligible Customers .................. 27 homes 205,788 48,233 n/a homes 0 0
Sector Total ............................................................................................................................................. $ 5,583,636 28,265,890 $ 107,203 259,213
Commercial
Commercial Energy-Saving Kits ............................................. 317 kits 21,628 46,237 17 kits 1,142 2,520
Custom Projects .................................................................... 101 projects 8,755,549 55,138,409 5 projects 164,378 1,018,651
New Construction ................................................................. 87 projects 2,762,899 27,615,610 1 project 17,608 167
Retrofits ................................................................................ 519 projects 4,785,965 22,330,625 6 projects 84,950 560,053
Small Business Direct Install ................................................. 672 projects 1,317,868 3,182,196 8 projects 27,561 46,170
Sector Total .............................................................................................................................................. $ 17,643,909 108,332,928 $ 295,638 1,627,561
Appendix 4. 2022 DSM Program Activity by State Jurisdiction
Page 190 Demand-Side Management 2022 Annual Report
Idaho Oregon
Program Participants
Program
Administrator Costs
Demand
Reduction (MW)/
Annual Energy Savings (kWh) Participants
Program
Administrator Costs
Demand
Reduction (MW)/
Annual Energy Savings (kWh)
Irrigation
Green Motors—Irrigation ..................................................... 6 motor rewinds 16,950 0 motor rewinds 0
Irrigation Efficiency Rewards ................................................ 494 projects 2,002,642 6,686,707 25 projects 77,386 251,148
Sector Total $ 2,002,642 6,703,657 $ 77,386 251,148
Market Transformation
Northwest Energy Efficiency Alliance (codes and standards).......................................................... 19,326,946 1,017,208
Northwest Energy Efficiency Alliance (other initiatives) ................................................................. 3,898,779 205,199
Northwest Energy Efficiency Alliance Totals3 ................................................................................
Other Programs and Activities
Residential
Residential Energy Efficiency Education Initiative ............................................................................. 289,437 10,738
Commercial
Oregon Commercial Audits .............................................................................................................. 12 audits 7,493
Other
Energy Efficiency Direct Program Overhead .................................................................................. 2,655,275 140,609
Total Program Direct Expense $ 40,229,578 $ 1,226,855
Indirect Program Expenses .............................................................................................................. 1,432,203 74,942
Total Annual Savings 166,528,201 3,360,329
Total DSM Expense ............................................................................................................................... $ 41,661,782 $ 1,301,797
1. Peak Demand is the peak performance of each respective program and not combined performance on the actual system peak hour.
2. Oregon administrator costs are negative due to account adjustments. Amount charged to the Oregon rider was reversed and charged to the Idaho rider.
3. Savings are preliminary estimates provided by NEEA. Final savings for 2022 will be provided by NEEA April 2023.
A P P E N D I X C : A P P E N D I X C : T E C H N I C A L R E P O R TT E C H N I C A L R E P O R T
IRP
INTEGRATED RESOURCE PLAN
September 2023
Printed on recycled paper
SAFE HARBOR STATEMENT
This document may contain forward-looking statements,
and it is important to note that the future results could
differ materially from those discussed. A full discussion
of the factors that could cause future results to differ
materially can be found in Idaho Power’s filings with the
Securities and Exchange Commission.
Table of Contents
2023 Integrated Resource Plan—Appendix C Page i
TABLE OF CONTENTS
Introduction .................................................................................................................................... 1
IRP Advisory Council ....................................................................................................................... 3
Customer Representatives ........................................................................................................ 3
Public-Interest Representatives ................................................................................................ 3
Regulatory Commission Representatives ................................................................................. 4
IRPAC Meeting Schedule and Agenda ...................................................................................... 4
Sales and Load Forecast Data ......................................................................................................... 5
Compound Annual Forecast Growth Rates .............................................................................. 5
Expected-Case Load Forecast ................................................................................................... 6
Annual Summary ..................................................................................................................... 16
Demand-Side Resource Data ........................................................................................................ 18
DSM Financial Assumptions .................................................................................................... 18
Avoided Cost Averages ($/MWh except where noted) .......................................................... 18
Bundle Amounts ..................................................................................................................... 19
Bundle Costs............................................................................................................................ 19
Supply-Side Resource Data ........................................................................................................... 20
Key Financial and Forecast Assumptions ................................................................................ 20
Cost Inputs and Operating Assumptions (Costs in 2024$) ..................................................... 21
Supply-Side Resource Escalation Factors1 (2024–2032) ......................................................... 22
Supply-Side Resource Escalation Factors1 (2033–2043) ......................................................... 23
Levelized Cost of Energy (costs in 2024$, $/MWh) at stated capacity factors ...................... 24
Levelized Capacity (fixed) Cost per kW/Month (costs in 2024$) ............................................ 25
Renewable Energy Certificate Forecast .................................................................................. 26
Existing Resource Data .................................................................................................................. 27
Qualifying Facility Data (PURPA) ............................................................................................. 27
Cogeneration & Small Power Production Projects ........................................................... 27
Status as of July 31, 2023 .................................................................................................. 27
Power Purchase Agreement Data ........................................................................................... 29
Hydro Flow Modeling .............................................................................................................. 30
Hydro Models .................................................................................................................... 30
Table of Contents
Page ii 2023 Integrated Resource Plan—Appendix C
Hydro Model Inputs .......................................................................................................... 30
Hydro Model Results ......................................................................................................... 31
Hydro Modeling Potential Energy Limits (aMW) .................................................................... 32
Long-Term Capacity Expansion Results (MW) .............................................................................. 42
Main Cases .............................................................................................................................. 42
Preferred Portfolio–Valmy 1 & 2 (MW) ............................................................................ 42
Valmy 2 (MW) ................................................................................................................... 43
Without Valmy (MW) ........................................................................................................ 44
November 2026 B2H Valmy 1 & 2 (MW) .......................................................................... 45
November 2026 B2H Valmy 2 (MW) ................................................................................ 46
November 2026 B2H Without Valmy (MW) ..................................................................... 47
Without GWW Segments (MW) ....................................................................................... 48
GWW Segment 1 Only (MW) ............................................................................................ 49
GWW Segments 1 & 2 Only (MW) .................................................................................... 50
Scenarios and Sensitivities ...................................................................................................... 51
High Gas High Carbon (MW) ............................................................................................. 51
Low Gas Zero Carbon (MW) .............................................................................................. 52
Constrained Storage (MW) ............................................................................................... 53
100% Clean by 2045 (MW) ............................................................................................... 54
Additional Large Load 100 MW (MW) .............................................................................. 55
Additional Large Load 200 MW (MW) .............................................................................. 56
100% Clean by 2035 (MW) ............................................................................................... 57
New Forecasted PURPA (MW) .......................................................................................... 58
Extreme Weather (MW) ................................................................................................... 59
Rapid Electrification Air-Source Heat Pump (MW) ........................................................... 60
Rapid Electrification Ground-Source Heat Pump (MW) ................................................... 61
Load Flattening (MW) ....................................................................................................... 62
Validation and Verification ..................................................................................................... 63
Valmy 1 & 2 Early Exit (MW) ............................................................................................. 63
Valmy 2 Early Exit (MW) ................................................................................................... 64
November 2026 B2H Valmy 1 & 2 Early Exit (MW) .......................................................... 65
Table of Contents
2023 Integrated Resource Plan—Appendix C Page iii
November 2026 B2H Valmy 2 Early Exit (MW) ................................................................. 66
Without Bridger 3 & 4 (MW) ............................................................................................ 67
Nuclear (MW) .................................................................................................................... 68
Wind +30% Cost (MW) ...................................................................................................... 69
Energy Efficiency (MW) ..................................................................................................... 70
Demand Response (MW) .................................................................................................. 71
Portfolio Emissions Forecast ......................................................................................................... 72
Main Cases CO2 Emissions (Metric Tons) ................................................................................ 72
Scenarios and Sensitivities CO2 Emissions (Metric Tons): ...................................................... 73
Main Cases SO2 Emissions (Metric Tons) ................................................................................ 74
Scenarios and Sensitivities SO2 Emissions (Metric Tons) ........................................................ 75
Main Cases NOx Emissions (Metric Tons) ............................................................................... 76
Scenarios and Sensitivities NOx Emissions (Metric Tons) ...................................................... 77
Portfolio Emissions.................................................................................................................. 78
Main Cases CO2 Emissions (Metric Tons) .......................................................................... 78
Scenarios and Sensitivities CO2 Emissions (Metric Tons) ................................................. 79
Main Cases SO2 Emissions (Metric Tons) .......................................................................... 80
Scenarios and Sensitivities SO2 Emissions (Metric Tons) .................................................. 81
Main Cases NOx Emissions (Metric Tons) ......................................................................... 82
Scenarios and Sensitivities NOx Emissions (Metric Tons) ................................................ 83
Stochastic Risk Analysis ................................................................................................................. 84
Natural Gas Sampling (Nominal $/MMBtu) ............................................................................ 84
Customer Load Sampling (Annual MWh) ............................................................................... 85
Hydro Generation Sampling (Annual MWh) ........................................................................... 85
Carbon Price Sampling (Annual MWh) ................................................................................... 86
Portfolio Stochastic Analysis, Total Portfolio Cost .................................................................. 88
NPV Years 2024–2043 ($ x 1,000) ..................................................................................... 88
Loss of Load Expectation ............................................................................................................... 89
Methodology Components ..................................................................................................... 89
Modeling Idaho Power’s System ............................................................................................ 90
Western Resource Adequacy Program Modeling............................................................. 91
Table of Contents
Page iv 2023 Integrated Resource Plan—Appendix C
Effective Load-Carrying Capability Results ............................................................................. 92
Timing of Highest Risk ............................................................................................................. 92
Summer Risk Hours (June 1–September 15) .................................................................... 93
Winter Risk Hours (November 1–February 28/29) ........................................................... 94
Off-Season Risk Hours (March 1–May 31, September 16–October 31) ........................... 95
Compliance with State of Oregon IRP Guidelines ......................................................................... 97
Guideline 1: Substantive Requirements ................................................................................. 97
Guideline 2: Procedural Requirements ................................................................................... 99
Guideline 3: Plan Filing, Review, and Updates ....................................................................... 99
Guideline 4: Plan Components ............................................................................................. 101
Guideline 5: Transmission ..................................................................................................... 104
Guideline 6: Conservation ..................................................................................................... 104
Guideline 7: Demand Response ............................................................................................ 105
Guideline 8: Environmental Costs ......................................................................................... 105
Guideline 9: Direct Access Loads .......................................................................................... 106
Guideline 10: Multi-state Utilities ......................................................................................... 107
Guideline 11: Reliability ........................................................................................................ 107
Guideline 12: Distributed Generation................................................................................... 107
Guideline 13: Resource Acquisition ...................................................................................... 107
Compliance with EV Guidelines .................................................................................................. 109
Guideline 1: Forecast the Demand for Flexible Capacity...................................................... 109
Guideline 2: Forecast the Supply for Flexible Capacity ........................................................ 109
Guideline 3: Evaluate Flexible Resources on a Consistent and Comparable Basis ............... 109
State of Oregon Action Items Regarding Idaho Power’s 2021 IRP ............................................. 110
Action Item 1: B2H ................................................................................................................ 110
Action Item 2: SWIP–North ................................................................................................... 110
Action Item 3: Jackpot Solar ................................................................................................. 110
Action Item 4: Jim Bridger Units 1 and 2 .............................................................................. 110
Action Item 5: 2024 and 2025 RFP ........................................................................................ 111
Action Item 6: Jim Bridger Units 3 and 4 .............................................................................. 111
Action Item 7: Demand Response ........................................................................................ 111
Table of Contents
2023 Integrated Resource Plan—Appendix C Page v
Action Item 8: B2H ................................................................................................................ 111
Action Item 9: Energy Efficiency ........................................................................................... 111
Action Item 10: Large-Load Customers ................................................................................ 112
Action Item 11: Storage Projects .......................................................................................... 112
Action Item 12: Valmy Unit 2 ................................................................................................ 112
Action Item 13: Jim Bridger Unit 3 ........................................................................................ 112
Additional Recommendation 1: B2H .................................................................................... 112
Additional Recommendation 2: Wholesale Prices ............................................................... 113
Additional Recommendation 3: Grant Opportunities .......................................................... 113
Additional Recommendation 4: Demand Response ............................................................. 113
Additional Recommendation 5: Large-Load Customers ....................................................... 113
Additional Recommendation 6: WRAP ................................................................................. 114
Additional Recommendation 7: Reliability ........................................................................... 114
Additional Recommendation 8: QF Renewal Rate ............................................................... 114
Additional Recommendation 9: QF Forecast ........................................................................ 114
Additional Recommendation 10: GHG Emissions ................................................................. 114
Additional Recommendation 11: Green Hydrogen Proxy .................................................... 115

Table of Contents
Page vi 2023 Integrated Resource Plan—Appendix C

Introduction
2023 Integrated Resource Plan—Appendix C Page 1
INTRODUCTION
Appendix C–Technical Appendix contains supporting data and explanatory materials used to
develop Idaho Power’s 2023 Integrated Resource Plan (IRP).
The main document, the 2023 IRP Report, contains a full narrative of Idaho Power’s resource
planning process. Additional information regarding the 2023 IRP sales and load forecast is
contained in Appendix A–Sales and Load Forecast and details on Idaho Power’s demand-side
management efforts are explained in Appendix B–Demand-Side Management 2022
Annual Report.
For information or questions concerning the resource plan or the resource planning process,
contact Idaho Power:
Jared Hansen, Resource Planning
Idaho Power
1221 West Idaho Street
Boise, Idaho 83702
208-388-2706
[e-mail]

Introduction
Page 2 2023 Integrated Resource Plan—Appendix C

IRP Advisory Council
2023 Integrated Resource Plan—Appendix C Page 3
IRP ADVISORY COUNCIL
Idaho Power has involved representatives of the public in the IRP planning process since the
early 1990s. This public forum is known as the IRP Advisory Council (IRPAC). The IRPAC
generally meets monthly during the development of the IRP, and the meetings are open to the
public. Members of the council include regulatory, political, environmental, and customer
representatives, as well as representatives of other public-interest groups.
Idaho Power hosted 11 IRPAC meetings for the 2023 IRP. Idaho Power values these
opportunities to convene, and the IRPAC members and the public have made significant
contributions to this plan.
Involvement from the public improves the IRP, and Idaho Power is grateful to the individuals
and groups that participated in the process.
Customer Representatives
Agricultural Representative Sid Erwin
Boise State University Barry Burbank
Idaho Milk Products Chris Parker
Idaho National Laboratory Kurt Myers
KitzWorks, LLC Kevin Kitz
Meta Etta Lockey
Micron Jim Swier
Obendorf Farms Brock Obendorf
St. Luke’s Medical Stephanie Wicks
Syngenta Seeds Patrick Silveria
Public-Interest Representatives
Boise State University Energy Policy Institute Kathleen Araujo
City of Boise Steve Burgos
City of Nampa Mark Steuer
Clean Energy Opportunities for Idaho Mike Heckler
Idaho Conservation League Brad Heusinkveld
Idaho Legislature Rep. Laurie Lickley
Idaho Office of Energy and Mineral Resources Richard Stover
Idaho Water Resource Board Brian Olmstead
National Renewable Energy Laboratory Wesley Cole
Oil and Gas Industry Advisor David Hawk
IRP Advisory Council
Page 4 2023 Integrated Resource Plan—Appendix C
Oregon State University, Malheur Experiment Station Professor Emeritus Clint Shock
Renewable Northwest Sashwat Roy
Sierra Club Lisa Young
Sun Valley Institute for Resilience Herbert Romero
Regulatory Commission Representatives
Idaho Public Utilities Commission Matt Suess
Public Utility Commission of Oregon Kim Herb
IRPAC Meeting Schedule and Agenda
Meeting Dates Agenda Items
2022 Wednesday, May 4 Energy Efficiency Subcommittee Meeting
2022 Tuesday, August 30 Introductory Comments
Idaho Power Team Introductions
Advisory Council Introductions
2022 Thursday, September 8 Review of 2021 IRP
2023 IRP Overview
Carbon Outlook
Transmission Update
2022 Thursday, October 13 CSPP, Natural Gas, Energy, and Demand Forecasts
2022 Thursday, November 10 Hydro System
Future Resources
Energy Efficiency
Demand Response
Modeling Scenarios
2022 Thursday, December 8 Reliability and Capacity
Natural Gas Conversion
Future Supply-Side Resources
Modeling Scenarios
2023 Thursday, January 12 Transmission and Distribution (T&D) Planning
Solar on Underutilized Lands
Stochastics
Resource Adequacy
2023 Thursday, February 9 Modeling Update with Scenarios and Sensitivities Follow-up
2023 Thursday, March 9 Industry Topics
Electrification Scenarios
Loss of Load Analysis
2023 Thursday, April 27 Transmission Updates
2023 Tuesday, August 15 Analysis Update
Preliminary Modeling Results
2023 Thursday, August 31 Scenarios and Sensitivities
Risk Analysis
Preferred Portfolio and Action Plan

Sales and Load Forecast Data
2023 Integrated Resource Plan—Appendix C Page 5
SALES AND LOAD FORECAST DATA
Compound Annual Forecast Growth Rates
2024–2029 2024–2034 2024–2043
Sales
Residential Sales 1.14% 1.19% 1.06%
Commercial Sales 0.71% 0.79% 0.83%
Irrigation Sales 0.36% 0.46% 0.56%
Industrial Sales 1.14% 1.18% 1.32%
Additional Firm Sales 35.81% 17.94% 9.13%
System Sales 4.22% 2.85% 1.87%
Total Sales 4.22% 2.85% 1.87%
Average Loads
Residential Load 1.20% 1.22% 1.07%
Commercial Load 0.78% 0.82% 0.84%
Irrigation Load 0.42% 0.49% 0.58%
Industrial Load 1.19% 1.21% 1.33%
Additional Firm Sales 35.81% 17.94% 9.13%
System Load Losses 3.37% 2.30% 1.59%
System Load 5.40% 3.37% 2.12%
Total Load 5.40% 3.37% 2.12%
Peaks
System Peak 3.67% 2.49% 1.76%
Total Peak 3.67% 2.49% 1.76%
Winter Peak 4.35% 2.59% 1.61%
Summer Peak 3.67% 2.49% 1.76%
Customers
Residential Customers 2.01% 1.93% 1.60%
Commercial Customers 1.53% 1.60% 1.50%
Irrigation Customers 1.13% 1.10% 1.05%
Industrial Customers 0.80% 0.63% 0.65%

Sales and Load Forecast Data
Page 6 2023 Integrated Resource Plan—Appendix C
Expected-Case Load Forecast
2024 Monthly Summary1 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Load (aMW) 70th Percentile
Residential 854 760 639 535 508 596 817 719 557 559 697 891
Commercial 535 493 467 449 459 499 557 537 495 478 493 534
Irrigation 4 4 14 156 372 626 696 578 344 70 9 4
Industrial 311 296 307 299 304 318 319 322 314 315 314 315
Additional Firm 137 138 137 132 127 129 128 127 119 131 152 163
Loss 158 147 137 138 153 182 208 190 157 136 144 161
System Load 1,998 1,837 1,701 1,710 1,923 2,350 2,725 2,473 1,986 1,690 1,809 2,069
Light Load 1,865 1,716 1,587 1,566 1,755 2,108 2,451 2,194 1,808 1,541 1,689 1,925
Heavy Load 2,103 1,927 1,791 1,815 2,055 2,544 2,941 2,674 2,141 1,797 1,905 2,192
Total Load 1,998 1,837 1,701 1,710 1,923 2,350 2,725 2,473 1,986 1,690 1,809 2,069
Peak Load (MW) 70th Percentile
System Peak Load (1 hour) 2,487 2,306 2,178 2,553 2,655 3,668 3,830 3,547 3,108 2,323 2,311 2,492
Total Peak Load 2,487 2,306 2,178 2,553 2,655 3,668 3,830 3,547 3,108 2,323 2,311 2,492

2025 Monthly Summary Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Load (aMW) 70th Percentile
Residential 862 794 646 542 514 605 829 729 563 564 701 897
Commercial 539 514 470 452 462 502 561 541 498 480 495 538
Irrigation 4 4 14 157 374 631 703 583 347 71 9 4
Industrial 317 312 313 304 310 324 325 328 319 321 320 319
Additional Firm 176 188 187 185 195 211 226 238 243 266 281 303
Loss 160 153 140 141 156 186 213 196 162 142 149 167
System Load 2,057 1,965 1,769 1,781 2,011 2,460 2,857 2,615 2,132 1,843 1,955 2,227
Light Load 1,920 1,835 1,650 1,631 1,835 2,206 2,570 2,320 1,941 1,680 1,825 2,072
Heavy Load 2,165 2,062 1,862 1,891 2,150 2,662 3,084 2,847 2,284 1,960 2,068 2,349
Total Load 2,057 1,965 1,769 1,781 2,011 2,460 2,857 2,615 2,132 1,843 1,955 2,227
Peak Load (MW) 70th Percentile
System Peak Load (1 hour) 2,567 2,391 2,242 2,635 2,749 3,788 4,001 3,729 3,268 2,494 2,483 2,656
Total Peak Load 2,567 2,391 2,242 2,635 2,749 3,788 4,001 3,729 3,268 2,494 2,483 2,656
1.The sales and load forecast reflects the impact of existing energy efficiency programs on average load and peak demand. The new energy efficiency programs, proposed as part of the 2023 IRP.
The peak load forecast does not include the impact of existing or new demand response programs.

Sales and Load Forecast Data
2023 Integrated Resource Plan—Appendix C Page 7
2026 Monthly Summary Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Load (aMW) 70th Percentile
Residential 867 799 649 545 518 611 839 738 569 568 706 903
Commercial 546 519 474 457 466 507 567 547 502 484 499 541
Irrigation 4 4 14 157 374 632 704 584 347 71 9 4
Industrial 320 315 316 308 313 327 328 331 323 324 323 322
Additional Firm 329 355 370 384 395 422 443 456 456 473 484 498
Loss 166 160 146 148 163 194 221 204 170 149 156 174
System Load 2,232 2,152 1,970 1,998 2,230 2,693 3,103 2,860 2,366 2,069 2,176 2,442
Light Load 2,083 2,010 1,838 1,829 2,034 2,416 2,791 2,537 2,154 1,886 2,032 2,272
Heavy Load 2,349 2,259 2,074 2,121 2,398 2,896 3,349 3,115 2,536 2,201 2,303 2,576
Total Load 2,232 2,152 1,970 1,998 2,230 2,693 3,103 2,860 2,366 2,069 2,176 2,442
Peak Load (MW) 70th Percentile
System Peak Load (1 hour) 2,741 2,568 2,460 2,847 2,942 4,041 4,256 3,981 3,515 2,707 2,700 2,880
Total Peak Load 2,741 2,568 2,460 2,847 2,942 4,041 4,256 3,981 3,515 2,707 2,700 2,880

2027 Monthly Summary Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Load (aMW) 70th Percentile
Residential 874 805 655 550 524 619 852 749 577 574 713 913
Commercial 550 522 476 459 468 510 571 551 504 485 500 544
Irrigation 4 4 14 157 375 635 708 587 348 71 9 4
Industrial 323 318 319 310 316 330 332 334 326 327 326 325
Additional Firm 511 523 520 519 518 537 547 551 544 553 562 576
Loss 173 166 152 153 168 199 227 209 174 153 160 178
System Load 2,434 2,339 2,137 2,150 2,369 2,830 3,236 2,981 2,473 2,163 2,270 2,539
Light Load 2,272 2,184 1,993 1,968 2,161 2,538 2,910 2,645 2,251 1,972 2,119 2,362
Heavy Load 2,574 2,455 2,240 2,282 2,548 3,043 3,493 3,247 2,650 2,314 2,391 2,679
Total Load 2,434 2,339 2,137 2,150 2,369 2,830 3,236 2,981 2,473 2,163 2,270 2,539
Peak Load (MW) 70th Percentile
System Peak Load (1 hour) 2,949 2,765 2,633 3,000 3,061 4,185 4,406 4,116 3,625 2,795 2,792 2,972
Total Peak Load 2,949 2,765 2,633 3,000 3,061 4,185 4,406 4,116 3,625 2,795 2,792 2,972

Sales and Load Forecast Data
Page 8 2023 Integrated Resource Plan—Appendix C

2028 Monthly Summary Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Load (aMW) 70th Percentile
Residential 884 786 662 557 531 629 867 762 585 582 721 923
Commercial 555 509 480 463 472 514 577 556 508 488 503 547
Irrigation 4 4 14 157 375 636 710 589 349 71 9 4
Industrial 326 310 322 313 319 334 335 337 329 331 329 328
Additional Firm 578 584 587 583 577 592 598 598 585 589 594 604
Loss 177 165 156 157 171 202 230 212 177 155 162 180
System Load 2,523 2,358 2,220 2,230 2,445 2,908 3,317 3,054 2,533 2,215 2,317 2,586
Light Load 2,355 2,202 2,071 2,042 2,231 2,607 2,983 2,709 2,306 2,019 2,163 2,405
Heavy Load 2,668 2,474 2,328 2,381 2,615 3,127 3,604 3,304 2,715 2,370 2,441 2,741
Total Load 2,523 2,358 2,220 2,230 2,445 2,908 3,317 3,054 2,533 2,215 2,317 2,586
Peak Load (MW) 70th Percentile
System Peak Load (1 hour) 3,038 2,853 2,714 3,074 3,121 4,269 4,501 4,204 3,695 2,845 2,840 3,011
Total Peak Load 3,038 2,853 2,714 3,074 3,121 4,269 4,501 4,204 3,695 2,845 2,840 3,011

2029 Monthly Summary Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Load (aMW) 70th Percentile
Residential 894 824 670 564 539 640 883 776 595 589 729 934
Commercial 560 531 483 467 474 517 582 560 511 491 505 552
Irrigation 4 4 14 157 375 638 712 591 350 71 9 4
Industrial 329 324 325 317 322 337 338 341 332 334 332 331
Additional Firm 605 615 615 613 609 628 637 638 627 631 637 648
Loss 179 172 158 159 174 205 233 215 180 157 164 183
System Load 2,570 2,470 2,265 2,276 2,493 2,965 3,386 3,122 2,595 2,273 2,377 2,652
Light Load 2,399 2,306 2,112 2,083 2,274 2,659 3,045 2,770 2,362 2,072 2,219 2,467
Heavy Load 2,706 2,592 2,374 2,429 2,666 3,189 3,679 3,377 2,798 2,418 2,503 2,811
Total Load 2,570 2,470 2,265 2,276 2,493 2,965 3,386 3,122 2,595 2,273 2,377 2,652
Peak Load (MW) 70th Percentile
System Peak Load (1 hour) 3,085 2,899 2,755 3,114 3,161 4,337 4,585 4,288 3,767 2,900 2,898 3,070
Total Peak Load 3,085 2,899 2,755 3,114 3,161 4,337 4,585 4,288 3,767 2,900 2,898 3,070

Sales and Load Forecast Data
2023 Integrated Resource Plan—Appendix C Page 9

2030 Monthly Summary Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Load (aMW) 70th Percentile
Residential 904 833 678 571 546 651 899 789 604 596 736 943
Commercial 568 537 488 472 479 523 589 568 516 495 510 555
Irrigation 4 4 14 157 377 641 716 594 352 71 9 4
Industrial 333 328 329 320 326 341 342 344 336 338 336 335
Additional Firm 667 677 668 661 654 674 682 683 671 677 684 697
Loss 182 175 160 161 176 208 237 219 182 160 167 186
System Load 2,658 2,554 2,337 2,343 2,559 3,038 3,465 3,197 2,660 2,337 2,442 2,720
Light Load 2,480 2,385 2,180 2,145 2,334 2,724 3,116 2,836 2,422 2,130 2,280 2,530
Heavy Load 2,798 2,681 2,461 2,488 2,736 3,289 3,740 3,458 2,869 2,486 2,572 2,883
Total Load 2,658 2,554 2,337 2,343 2,559 3,038 3,465 3,197 2,660 2,337 2,442 2,720
Peak Load (MW) 70th Percentile
System Peak Load (1 hour) 3,176 2,983 2,830 3,178 3,220 4,420 4,679 4,381 3,848 2,970 2,968 3,133
Total Peak Load 3,176 2,983 2,830 3,178 3,220 4,420 4,679 4,381 3,848 2,970 2,968 3,133

2031 Monthly Summary Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Load (aMW) 70th Percentile
Residential 914 842 686 578 554 662 915 804 614 604 745 954
Commercial 572 541 491 475 482 526 594 572 519 497 512 559
Irrigation 4 4 14 158 378 644 720 598 353 72 9 4
Industrial 337 332 333 324 330 345 346 348 340 342 340 339
Additional Firm 696 705 696 688 680 698 704 702 688 692 697 707
Loss 185 177 162 163 178 210 240 221 184 161 168 187
System Load 2,707 2,601 2,381 2,386 2,602 3,085 3,519 3,246 2,698 2,368 2,471 2,752
Light Load 2,526 2,429 2,221 2,184 2,374 2,766 3,164 2,879 2,456 2,158 2,307 2,560
Heavy Load 2,838 2,730 2,507 2,534 2,767 3,340 3,775 3,535 2,875 2,519 2,603 2,891
Total Load 2,707 2,601 2,381 2,386 2,602 3,085 3,519 3,246 2,698 2,368 2,471 2,752
Peak Load (MW) 70th Percentile
System Peak Load (1 hour) 3,224 3,032 2,870 3,215 3,258 4,478 4,747 4,446 3,902 3,003 2,997 3,156
Total Peak Load 3,224 3,032 2,870 3,215 3,258 4,478 4,747 4,446 3,902 3,003 2,997 3,156

Sales and Load Forecast Data
Page 10 2023 Integrated Resource Plan—Appendix C

2032 Monthly Summary Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Load (aMW) 70th Percentile
Residential 924 823 694 585 562 672 931 817 622 611 752 962
Commercial 579 528 495 480 487 531 601 578 523 502 516 563
Irrigation 4 4 14 158 380 648 724 601 355 72 9 4
Industrial 341 324 336 328 333 349 350 352 344 346 344 344
Additional Firm 705 706 701 692 683 701 706 705 690 694 699 709
Loss 187 174 164 165 180 212 242 223 186 162 169 188
System Load 2,739 2,558 2,404 2,408 2,624 3,113 3,554 3,277 2,721 2,386 2,488 2,771
Light Load 2,556 2,388 2,242 2,204 2,394 2,791 3,196 2,907 2,476 2,174 2,323 2,578
Heavy Load 2,871 2,696 2,521 2,557 2,806 3,348 3,813 3,569 2,899 2,552 2,609 2,911
Total Load 2,739 2,558 2,404 2,408 2,624 3,113 3,554 3,277 2,721 2,386 2,488 2,771
Peak Load (MW) 70th Percentile
System Peak Load (1 hour) 3,255 3,058 2,888 3,230 3,283 4,520 4,797 4,495 3,943 3,025 3,015 3,169
Total Peak Load 3,255 3,058 2,888 3,230 3,283 4,520 4,797 4,495 3,943 3,025 3,015 3,169

2033 Monthly Summary Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Load (aMW) 70th Percentile
Residential 933 860 700 592 569 682 946 831 631 618 759 972
Commercial 584 551 499 484 490 535 606 583 527 504 518 567
Irrigation 4 4 14 159 382 652 729 605 357 72 9 4
Industrial 345 340 341 332 338 353 354 357 348 350 348 348
Additional Firm 707 714 703 694 685 703 709 707 693 696 701 712
Loss 188 180 165 166 181 214 244 225 187 164 170 190
System Load 2,761 2,648 2,422 2,426 2,644 3,139 3,588 3,308 2,743 2,403 2,506 2,793
Light Load 2,576 2,473 2,258 2,221 2,412 2,815 3,227 2,934 2,497 2,191 2,339 2,598
Heavy Load 2,906 2,780 2,539 2,576 2,828 3,376 3,874 3,579 2,923 2,571 2,628 2,934
Total Load 2,761 2,648 2,422 2,426 2,644 3,139 3,588 3,308 2,743 2,403 2,506 2,793
Peak Load (MW) 70th Percentile
System Peak Load (1 hour) 3,276 3,079 2,902 3,243 3,305 4,560 4,847 4,545 3,984 3,047 3,033 3,183
Total Peak Load 3,276 3,079 2,902 3,243 3,305 4,560 4,847 4,545 3,984 3,047 3,033 3,183

Sales and Load Forecast Data
2023 Integrated Resource Plan—Appendix C Page 11

2034 Monthly Summary Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Load (aMW) 70th Percentile
Residential 942 868 707 597 575 692 960 842 638 622 763 977
Commercial 591 556 503 489 494 540 613 590 531 508 522 572
Irrigation 4 4 14 160 384 656 734 609 360 73 9 5
Industrial 350 345 345 336 342 358 359 362 353 355 353 353
Additional Firm 710 717 706 697 687 706 711 710 695 699 704 714
Loss 189 181 166 167 182 215 247 227 188 164 171 191
System Load 2,785 2,671 2,441 2,446 2,666 3,167 3,623 3,340 2,766 2,420 2,522 2,812
Light Load 2,599 2,494 2,277 2,239 2,431 2,839 3,258 2,962 2,517 2,206 2,354 2,615
Heavy Load 2,932 2,803 2,560 2,612 2,835 3,406 3,911 3,612 2,947 2,589 2,644 2,966
Total Load 2,785 2,671 2,441 2,446 2,666 3,167 3,623 3,340 2,766 2,420 2,522 2,812
Peak Load (MW) 70th Percentile
System Peak Load (1 hour) 3,299 3,097 2,917 3,256 3,330 4,601 4,897 4,594 4,025 3,068 3,049 3,195
Total Peak Load 3,299 3,097 2,917 3,256 3,330 4,601 4,897 4,594 4,025 3,068 3,049 3,195

2035 Monthly Summary Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Load (aMW) 70th Percentile
Residential 947 873 711 602 581 700 973 853 645 627 768 983
Commercial 598 562 508 494 499 546 620 597 536 512 526 576
Irrigation 4 4 14 161 387 660 739 614 362 73 9 5
Industrial 355 350 350 341 347 363 364 367 358 360 358 358
Additional Firm 710 717 706 697 688 706 711 710 695 699 704 715
Loss 190 182 167 168 183 217 249 229 190 165 172 192
System Load 2,804 2,688 2,456 2,463 2,684 3,191 3,656 3,369 2,786 2,436 2,537 2,828
Light Load 2,616 2,509 2,291 2,254 2,448 2,862 3,287 2,988 2,536 2,221 2,368 2,630
Heavy Load 2,939 2,821 2,575 2,629 2,855 3,432 3,947 3,645 2,987 2,592 2,660 2,983
Total Load 2,804 2,688 2,456 2,463 2,684 3,191 3,656 3,369 2,786 2,436 2,537 2,828
Peak Load (MW) 70th Percentile
System Peak Load (1 hour) 3,316 3,113 2,928 3,267 3,351 4,640 4,944 4,642 4,065 3,088 3,064 3,204
Total Peak Load 3,316 3,113 2,928 3,267 3,351 4,640 4,944 4,642 4,065 3,088 3,064 3,204

Sales and Load Forecast Data
Page 12 2023 Integrated Resource Plan—Appendix C

2036 Monthly Summary Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Load (aMW) 70th Percentile
Residential 954 849 717 607 587 709 987 866 654 633 774 990
Commercial 604 547 511 498 502 549 626 602 539 515 528 580
Irrigation 4 4 14 162 389 665 744 618 365 74 9 5
Industrial 360 342 355 346 352 368 369 372 363 365 363 363
Additional Firm 711 712 707 698 688 706 712 710 696 700 705 716
Loss 192 179 168 169 184 219 251 231 191 166 173 193
System Load 2,823 2,632 2,472 2,479 2,703 3,217 3,689 3,399 2,807 2,452 2,552 2,846
Light Load 2,634 2,458 2,305 2,269 2,465 2,884 3,317 3,015 2,555 2,235 2,382 2,648
Heavy Load 2,959 2,761 2,603 2,632 2,874 3,483 3,958 3,702 2,992 2,609 2,688 2,990
Total Load 2,823 2,632 2,472 2,479 2,703 3,217 3,689 3,399 2,807 2,452 2,552 2,846
Peak Load (MW) 70th Percentile
System Peak Load (1 hour) 3,333 3,131 2,940 3,278 3,373 4,679 4,992 4,690 4,105 3,109 3,080 3,215
Total Peak Load 3,333 3,131 2,940 3,278 3,373 4,679 4,992 4,690 4,105 3,109 3,080 3,215

2037 Monthly Summary Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Load (aMW) 70th Percentile
Residential 961 886 723 613 594 719 1,003 879 662 639 780 998
Commercial 610 572 515 502 506 554 632 607 543 518 531 584
Irrigation 4 4 15 163 391 670 750 623 367 74 9 5
Industrial 365 359 360 351 357 373 374 377 368 370 368 369
Additional Firm 710 718 706 697 688 706 712 710 696 699 705 715
Loss 193 184 169 170 186 220 253 233 192 167 174 194
System Load 2,843 2,723 2,488 2,496 2,722 3,242 3,723 3,430 2,829 2,468 2,567 2,865
Light Load 2,653 2,543 2,320 2,285 2,482 2,907 3,348 3,042 2,575 2,250 2,396 2,665
Heavy Load 2,980 2,859 2,620 2,650 2,911 3,487 3,995 3,736 3,014 2,626 2,704 3,009
Total Load 2,843 2,723 2,488 2,496 2,722 3,242 3,723 3,430 2,829 2,468 2,567 2,865
Peak Load (MW) 70th Percentile
System Peak Load (1 hour) 3,352 3,149 2,951 3,288 3,396 4,719 5,041 4,739 4,147 3,129 3,096 3,226
Total Peak Load 3,352 3,149 2,951 3,288 3,396 4,719 5,041 4,739 4,147 3,129 3,096 3,226

Sales and Load Forecast Data
2023 Integrated Resource Plan—Appendix C Page 13

2038 Monthly Summary Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Load (aMW) 70th Percentile
Residential 968 893 729 619 601 729 1,017 892 670 645 785 1,004
Commercial 617 577 520 507 510 559 639 614 548 522 535 589
Irrigation 4 4 15 163 394 674 755 627 370 74 9 5
Industrial 370 365 366 356 362 379 380 383 373 375 374 374
Additional Firm 710 718 706 697 688 706 711 710 696 699 704 715
Loss 194 186 170 171 187 222 255 235 194 168 175 195
System Load 2,864 2,742 2,505 2,514 2,742 3,269 3,759 3,461 2,851 2,485 2,582 2,883
Light Load 2,672 2,561 2,336 2,301 2,501 2,931 3,380 3,070 2,595 2,265 2,411 2,682
Heavy Load 3,015 2,879 2,626 2,669 2,932 3,516 4,032 3,770 3,038 2,658 2,708 3,028
Total Load 2,864 2,742 2,505 2,514 2,742 3,269 3,759 3,461 2,851 2,485 2,582 2,883
Peak Load (MW) 70th Percentile
System Peak Load (1 hour) 3,372 3,168 2,964 3,299 3,420 4,760 5,091 4,789 4,190 3,151 3,112 3,237
Total Peak Load 3,372 3,168 2,964 3,299 3,420 4,760 5,091 4,789 4,190 3,151 3,112 3,237

2039 Monthly Summary Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Load (aMW) 70th Percentile
Residential 975 899 734 624 607 738 1,031 904 678 650 789 1,009
Commercial 625 584 525 513 515 565 647 621 553 527 539 594
Irrigation 4 4 15 164 396 679 761 632 372 75 9 5
Industrial 376 370 371 361 368 385 386 389 379 381 379 380
Additional Firm 710 717 706 697 688 706 711 710 696 699 704 715
Loss 195 187 171 172 188 224 258 237 195 169 176 196
System Load 2,885 2,761 2,522 2,532 2,762 3,296 3,794 3,493 2,873 2,501 2,597 2,899
Light Load 2,692 2,578 2,352 2,317 2,519 2,955 3,411 3,098 2,615 2,280 2,425 2,697
Heavy Load 3,037 2,899 2,644 2,688 2,954 3,545 4,095 3,778 3,062 2,676 2,724 3,045
Total Load 2,885 2,761 2,522 2,532 2,762 3,296 3,794 3,493 2,873 2,501 2,597 2,899
Peak Load (MW) 70th Percentile
System Peak Load (1 hour) 3,392 3,186 2,976 3,311 3,444 4,800 5,140 4,839 4,233 3,172 3,127 3,246
Total Peak Load 3,392 3,186 2,976 3,311 3,444 4,800 5,140 4,839 4,233 3,172 3,127 3,246

Sales and Load Forecast Data
Page 14 2023 Integrated Resource Plan—Appendix C

2040 Monthly Summary Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Load (aMW) 70th Percentile
Residential 980 873 739 629 613 747 1,045 916 685 655 794 1,015
Commercial 631 569 529 518 520 570 654 628 557 531 543 598
Irrigation 4 4 15 165 398 684 766 636 375 75 10 5
Industrial 382 363 377 367 373 391 392 395 385 387 385 386
Additional Firm 709 710 706 697 687 705 711 709 695 699 704 714
Loss 197 183 172 173 189 225 260 239 196 170 177 197
System Load 2,903 2,702 2,537 2,548 2,781 3,322 3,827 3,523 2,894 2,517 2,611 2,915
Light Load 2,709 2,523 2,366 2,332 2,536 2,978 3,441 3,124 2,634 2,294 2,438 2,711
Heavy Load 3,056 2,835 2,660 2,721 2,958 3,573 4,132 3,811 3,102 2,678 2,739 3,075
Total Load 2,903 2,702 2,537 2,548 2,781 3,322 3,827 3,523 2,894 2,517 2,611 2,915
Peak Load (MW) 70th Percentile
System Peak Load (1 hour) 3,409 3,203 2,987 3,321 3,467 4,840 5,188 4,888 4,274 3,192 3,142 3,256
Total Peak Load 3,409 3,203 2,987 3,321 3,467 4,840 5,188 4,888 4,274 3,192 3,142 3,256

2041 Monthly Summary Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Load (aMW) 70th Percentile
Residential 985 909 743 633 619 756 1,058 927 692 660 798 1,020
Commercial 638 595 534 523 524 575 661 634 562 535 546 602
Irrigation 4 4 15 166 401 688 772 641 377 76 10 5
Industrial 387 382 382 372 379 396 398 401 391 393 391 391
Additional Firm 719 726 714 704 693 711 716 715 701 706 712 723
Loss 198 189 173 174 191 227 262 241 198 172 178 198
System Load 2,932 2,805 2,561 2,572 2,806 3,354 3,867 3,559 2,921 2,541 2,634 2,940
Light Load 2,736 2,619 2,388 2,355 2,559 3,007 3,477 3,156 2,659 2,316 2,459 2,735
Heavy Load 3,073 2,945 2,696 2,732 2,985 3,631 4,149 3,850 3,131 2,703 2,763 3,102
Total Load 2,932 2,805 2,561 2,572 2,806 3,354 3,867 3,559 2,921 2,541 2,634 2,940
Peak Load (MW) 70th Percentile
System Peak Load (1 hour) 3,427 3,221 3,005 3,340 3,496 4,886 5,242 4,943 4,322 3,223 3,167 3,265
Total Peak Load 3,427 3,221 3,005 3,340 3,496 4,886 5,242 4,943 4,322 3,223 3,167 3,265

Sales and Load Forecast Data
2023 Integrated Resource Plan—Appendix C Page 15

2042 Monthly Summary Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Load (aMW) 70th Percentile
Residential 990 914 748 638 624 765 1,072 939 700 664 802 1,024
Commercial 644 600 537 527 527 579 667 640 566 538 549 606
Irrigation 4 4 15 167 403 693 777 646 380 76 10 5
Industrial 393 387 388 378 385 402 404 407 396 399 397 397
Additional Firm 719 726 714 704 693 711 716 715 701 706 712 723
Loss 199 190 174 175 192 229 264 243 199 172 179 199
System Load 2,950 2,822 2,575 2,588 2,825 3,379 3,900 3,589 2,942 2,556 2,648 2,955
Light Load 2,752 2,634 2,402 2,369 2,576 3,029 3,506 3,183 2,678 2,329 2,472 2,749
Heavy Load 3,092 2,962 2,712 2,749 3,004 3,658 4,184 3,909 3,135 2,719 2,789 3,104
Total Load 2,950 2,822 2,575 2,588 2,825 3,379 3,900 3,589 2,942 2,556 2,648 2,955
Peak Load (MW) 70th Percentile
System Peak Load (1 hour) 3,444 3,237 3,016 3,351 3,518 4,925 5,290 4,991 4,362 3,242 3,181 3,274
Total Peak Load 3,444 3,237 3,016 3,351 3,518 4,925 5,290 4,991 4,362 3,242 3,181 3,274

2043 Monthly Summary Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Average Load (aMW) 70th Percentile
Residential 995 919 752 642 630 773 1,084 950 706 669 805 1,028
Commercial 650 605 541 531 531 583 673 646 569 541 552 610
Irrigation 4 4 15 168 405 697 783 650 382 77 10 5
Industrial 399 393 394 383 390 408 409 413 402 404 403 403
Additional Firm 719 726 714 704 693 711 716 715 701 706 712 723
Loss 200 191 175 176 193 230 266 245 200 173 179 200
System Load 2,968 2,838 2,590 2,605 2,843 3,403 3,932 3,617 2,962 2,570 2,661 2,970
Light Load 2,769 2,650 2,415 2,384 2,593 3,052 3,535 3,208 2,696 2,342 2,484 2,762
Heavy Load 3,111 2,979 2,727 2,766 3,040 3,661 4,218 3,940 3,156 2,734 2,803 3,119
Total Load 2,968 2,838 2,590 2,605 2,843 3,403 3,932 3,617 2,962 2,570 2,661 2,970
Peak Load (MW) 70th Percentile
System Peak Load (1 hour) 3,461 3,252 3,026 3,361 3,539 4,964 5,337 5,038 4,401 3,261 3,194 3,283
Total Peak Load 3,461 3,252 3,026 3,361 3,539 4,964 5,337 5,038 4,401 3,261 3,194 3,283

Sales and Load Forecast Data
Page 16 2023 Integrated Resource Plan—Appendix C
Annual Summary
2024 2025 2026 2027 2028 2029 2030 2031 2032 2033
Billed Sales (MWh) 70th Percentile
Residential 5,952,203 6,015,372 6,064,292 6,131,412 6,212,505 6,299,614 6,383,861 6,471,568 6,555,018 6,633,732
Commercial 4,389,449 4,415,395 4,459,613 4,481,988 4,518,268 4,548,417 4,599,132 4,627,083 4,672,632 4,704,762
Irrigation 2,112,332 2,130,433 2,131,886 2,140,898 2,145,544 2,151,055 2,161,512 2,172,343 2,184,166 2,197,504
Industrial 2,730,923 2,780,341 2,808,143 2,835,162 2,861,510 2,890,833 2,922,399 2,956,967 2,991,128 3,029,583
Additional Firm 1,185,562 1,972,275 3,702,016 4,717,323 5,174,670 5,477,596 5,909,535 6,097,135 6,140,903 6,149,345
System Load 16,370,468 17,313,815 19,165,950 20,306,782 20,912,497 21,367,515 21,976,439 22,325,096 22,543,847 22,714,925
Total Load 16,370,468 17,313,815 19,165,950 20,306,782 20,912,497 21,367,515 21,976,439 22,325,096 22,543,847 22,714,925
Generation Month Sales (MWh) 70th Percentile
Residential 5,956,695 6,018,895 6,068,360 6,136,888 6,218,381 6,305,689 6,389,286 6,477,861 6,559,842 6,639,006
Commercial 4,390,873 4,417,970 4,460,805 4,484,056 4,519,947 4,551,390 4,600,667 4,629,723 4,674,424 4,707,375
Irrigation 2,112,350 2,130,436 2,131,896 2,140,904 2,145,550 2,151,065 2,161,523 2,172,355 2,184,179 2,197,517
Industrial 2,735,093 2,782,687 2,810,423 2,837,385 2,863,985 2,893,497 2,925,317 2,959,850 2,994,373 3,033,114
Additional Firm 1,185,562 1,972,275 3,702,016 4,717,323 5,174,670 5,477,596 5,909,535 6,097,135 6,140,903 6,149,345
System Sales 16,380,573 17,322,263 19,173,500 20,316,557 20,922,533 21,379,236 21,986,327 22,336,924 22,553,721 22,726,358
Total Sales 16,380,573 17,322,263 19,173,500 20,316,557 20,922,533 21,379,236 21,986,327 22,336,924 22,553,721 22,726,358
Loss 1,400,102 1,435,438 1,499,307 1,542,889 1,570,420 1,591,049 1,617,688 1,635,569 1,649,836 1,660,426
Required Supply 17,780,674 18,757,701 20,672,807 21,859,447 22,492,953 22,970,286 23,604,015 23,972,493 24,203,558 24,386,784
Average Load (aMW) 70th Percentile
Residential 678 687 693 701 708 720 729 739 747 758
Commercial 500 504 509 512 515 520 525 529 532 537
Irrigation 240 243 243 244 244 246 247 248 249 251
Industrial 311 318 321 324 326 330 334 338 341 346
Additional Firm 135 225 423 539 589 625 675 696 699 702
Loss 159 164 171 176 179 182 185 187 188 190
System Load 2,024 2,141 2,360 2,495 2,561 2,622 2,695 2,737 2,755 2,784
Light Load 1,852 1,959 2,159 2,283 2,343 2,399 2,465 2,503 2,521 2,547
Heavy Load 2,159 2,285 2,518 2,662 2,733 2,798 2,874 2,912 2,931 2,962
Total Load 2,024 2,141 2,360 2,495 2,561 2,622 2,695 2,737 2,755 2,784
Peak Load (MW) 70th Percentile
System Peak (1 hour) 3,830 4,001 4,256 4,406 4,501 4,585 4,679 4,747 4,797 4,847
Total Peak Load 3,830 4,001 4,256 4,406 4,501 4,585 4,679 4,747 4,797 4,847

Sales and Load Forecast Data
2023 Integrated Resource Plan—Appendix C Page 17

2034 2035 2036 2037 2038 2039 2040 2041 2042 2043
Billed Sales (MWh) 70th Percentile
Residential 6,701,009 6,759,420 6,828,122 6,902,280 6,972,664 7,035,828 7,095,241 7,154,048 7,212,029 7,266,306
Commercial 4,750,003 4,798,757 4,831,415 4,871,061 4,917,076 4,968,676 5,011,749 5,056,679 5,094,573 5,132,734
Irrigation 2,211,654 2,226,398 2,241,679 2,257,279 2,272,690 2,288,397 2,304,043 2,319,739 2,335,293 2,350,298
Industrial 3,071,424 3,114,153 3,157,745 3,201,940 3,250,317 3,300,396 3,350,607 3,400,422 3,450,450 3,501,215
Additional Firm 6,171,167 6,172,006 6,193,102 6,177,196 6,176,327 6,173,887 6,183,582 6,234,425 6,234,425 6,234,425
System Load 22,905,257 23,070,734 23,252,062 23,409,755 23,589,075 23,767,184 23,945,221 24,165,313 24,326,770 24,484,977
Total Load 22,905,257 23,070,734 23,252,062 23,409,755 23,589,075 23,767,184 23,945,221 24,165,313 24,326,770 24,484,977
Generation Month Sales (MWh) 70th Percentile
Residential 6,704,206 6,763,302 6,832,534 6,906,651 6,976,408 7,039,015 7,098,397 7,157,159 7,215,024 7,268,947
Commercial 4,752,832 4,800,574 4,833,665 4,873,707 4,920,067 4,971,129 5,014,314 5,058,800 5,096,708 5,134,882
Irrigation 2,211,669 2,226,412 2,241,694 2,257,294 2,272,705 2,288,412 2,304,058 2,319,755 2,335,307 2,350,312
Industrial 3,075,030 3,117,832 3,161,475 3,206,023 3,254,544 3,304,634 3,354,811 3,404,644 3,454,735 3,505,562
Additional Firm 6,171,167 6,172,006 6,193,102 6,177,196 6,176,327 6,173,887 6,183,582 6,234,425 6,234,425 6,234,425
System Sales 22,914,904 23,080,126 23,262,469 23,420,870 23,600,052 23,777,076 23,955,161 24,174,783 24,336,199 24,494,128
Total Sales 22,914,904 23,080,126 23,262,469 23,420,870 23,600,052 23,777,076 23,955,161 24,174,783 24,336,199 24,494,128
Loss 1,672,397 1,683,411 1,695,732 1,706,055 1,718,046 1,729,897 1,742,228 1,753,939 1,764,571 1,774,927
Required Supply 24,587,300 24,763,537 24,958,202 25,126,925 25,318,098 25,506,973 25,697,389 25,928,722 26,100,770 26,269,054
Average Load (aMW) 70th Percentile
Residential 765 772 778 788 796 804 808 817 824 830
Commercial 543 548 550 556 562 567 571 577 582 586
Irrigation 252 254 255 258 259 261 262 265 267 268
Industrial 351 356 360 366 372 377 382 389 394 400
Additional Firm 704 705 705 705 705 705 704 712 712 712
Loss 191 192 193 195 196 198 198 200 201 203
System Load 2,807 2,827 2,841 2,868 2,890 2,912 2,926 2,960 2,980 2,999
Light Load 2,568 2,586 2,599 2,624 2,644 2,663 2,676 2,707 2,725 2,743
Heavy Load 2,987 3,008 3,023 3,052 3,075 3,098 3,114 3,149 3,171 3,191
Total Load 2,807 2,827 2,841 2,868 2,890 2,912 2,926 2,960 2,980 2,999
Peak Load (MW) 70th Percentile
System Peak (1 hour) 4,897 4,944 4,992 5,041 5,091 5,140 5,188 5,242 5,290 5,337
Total Peak Load 4,897 4,944 4,992 5,041 5,091 5,140 5,188 5,242 5,290 5,337
Demand-Side Resource Data
Page 18 2023 Integrated Resource Plan—Appendix C
DEMAND-SIDE RESOURCE DATA
DSM Financial Assumptions
Avoided Levelized Capacity Costs
Simple Cycle Combustion Turbine (SCCT) $145.94/kW-year
Financial Assumptions
Discount rate (weighted average cost of capital) 7.12%
Financial escalation factor 2.60%
Transmission Losses
Non-summer secondary losses 7.60%
Summer peak loss 7.60%

Avoided Cost Averages ($/MWh except where noted)
Year
Summer
High-Risk
Summer
Medium-Risk
Summer
Low-Risk
Winter
High-Risk
Winter
Medium-Risk
Winter
Low-Risk
Off Season
Low-Risk
2024 $53.48 $49.44 $30.40 $46.68 $41.02 $38.83 $26.67
2025 $50.90 $48.25 $29.61 $45.80 $40.92 $38.37 $26.31
2026 $51.41 $47.73 $28.47 $47.42 $40.49 $39.12 $24.95
2027 $74.68 $70.21 $44.15 $65.45 $53.89 $53.84 $33.75
2028 $71.72 $68.19 $43.44 $64.02 $50.61 $52.15 $29.52
2029 $70.57 $66.78 $42.01 $61.08 $48.30 $51.82 $28.64
2030 $70.09 $65.60 $40.01 $62.08 $48.02 $53.41 $26.57
2031 $69.60 $64.72 $37.52 $58.34 $42.29 $47.89 $24.03
2032 $67.53 $63.29 $37.55 $58.38 $44.24 $49.46 $23.48
2033 $72.11 $67.37 $39.11 $57.08 $41.95 $49.69 $23.18
2034 $78.99 $73.32 $48.68 $63.30 $50.37 $57.11 $21.97
2035 $70.08 $58.41 $32.27 $45.04 $34.97 $37.71 $14.01
2036 $93.67 $64.41 $18.71 $45.04 $32.53 $30.90 $13.43
2037 $100.50 $69.86 $18.99 $47.41 $34.84 $32.96 $14.37
2038 $97.60 $69.33 $18.40 $45.25 $36.10 $31.44 $14.04
2039 $92.93 $63.94 $18.17 $41.56 $32.90 $27.96 $13.58
2040 $91.36 $57.96 $14.39 $34.69 $26.68 $23.99 $10.87
2041 $97.19 $61.51 $14.48 $36.95 $29.42 $25.26 $10.83
2042 $107.97 $65.06 $14.97 $36.62 $28.19 $23.43 $11.15
2043 $98.25 $60.65 $12.47 $34.86 $26.94 $23.43 $10.86

The time periods used to develop the avoided cost averages presented in the table above align with
the company’s highest-risk hours, which are described in the Loss of Load Expectation section.
Demand-Side Resource Data
2023 Integrated Resource Plan—Appendix C Page 19
Bundle Amounts
Incremental Achievable Potential (aMW)
Bundle 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033
Summer Low 2 2 2 2 3 3 3 3 3 3
Summer Medium 0 0 0 0 1 1 1 1 1 1
Summer High 0 1 1 1 1 2 2 2 2 2
Winter Low 1 2 2 3 3 4 3 3 3 3
Winter High 0 1 1 2 2 2 3 3 3 3
Total 4 5 7 8 10 11 11 12 13 13

Bundle 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043
Summer Low 3 2 2 2 2 2 2 2 2 2
Summer Medium 1 2 2 2 2 3 3 3 3 3
Summer High 2 2 2 2 2 2 2 2 2 2
Winter Low 3 3 3 4 4 4 4 4 4 4
Winter High 4 4 4 4 4 4 4 4 4 4
Total 13 13 14 14 14 14 15 15 15 15

Bundle Costs
Savings Weighted Levelized Cost of Energy ($/MWh) Real Dollars
Bundle 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033
Summer Low $91 $94 $96 $98 $100 $99 $99 $97 $97 $99
Summer Medium $336 $334 $333 $330 $326 $321 $316 $310 $307 $302
Summer High $948 $873 $860 $835 $807 $772 $749 $725 $711 $648
Winter Low $85 $84 $84 $83 $82 $80 $77 $74 $71 $68
Winter High $632 $592 $559 $540 $514 $482 $466 $432 $405 $382
Total $2,091 $1,977 $1,933 $1,886 $1,829 $1,754 $1,707 $1,639 $1,591 $1,500

Bundle 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043
Summer Low $100 $99 $98 $97 $95 $93 $92 $90 $89 $88
Summer Medium $300 $298 $295 $293 $291 $289 $287 $286 $285 $284
Summer High $643 $640 $629 $615 $581 $555 $535 $519 $510 $495
Winter Low $365 $350 $335 $315 $289 $277 $255 $237 $236 $224
Winter High $66 $64 $61 $59 $56 $54 $52 $52 $52 $52
Total $1,473 $1,450 $1,419 $1,379 $1,313 $1,267 $1,221 $1,185 $1,173 $1,143

Supply-Side Resource Data
Page 20 2023 Integrated Resource Plan—Appendix C
SUPPLY-SIDE RESOURCE DATA
Key Financial and Forecast Assumptions
Financing Cap Structure and Cost
Composition
Debt 50.10%
Preferred 0.00%
Common 49.90%
Total 100.00%
Cost
Debt 5.73%
Preferred 0.00%
Common 10.00%
Average Weighted Cost 7.86%

Financial Assumptions and Factors
Plant operating (book) life Expected Life of the Asset
Discount rate (weighted average cost of capital1) 7.12%
Composite tax rate 25.74%
Deferred rate 21.30%
General O&M escalation rate 2.60%
Annual property tax rate (% of investment) 0.44%
B2H annual property tax rate (% of investment) 0.70%
Property tax escalation rate 3.00%
B2H property tax escalation rate 1.05%
Annual insurance premiums (% of investment) 0.046%
B2H annual insurance premiums (% of investment) 0.003%
Insurance escalation rate 5.00%
B2H insurance escalation rate 5.00%
AFUDC rate (annual) 7.50%
1 Incorporates tax effects.

Supply-Side Resource Data
2023 Integrated Resource Plan—Appendix C Page 21
Cost Inputs and Operating Assumptions (Costs in 2024$)

1 /I

2

-Side Resources (MW) ($/kW) ($/kW) ($/kW) ($/kW-month) ($/MWh) (Btu/kWh) (years)
Baseload Gas—Combined-Cycle Combustion Turbine (CCCT) 300 $1,450 $140 $1,590 $1.40 $3.10 6,363 30
Biomass 30 $4,770 $167 $4,937 $15.10 $7.00 13,500 30
Clean Peaking Gas—Hydrogen Combustion Turbine 170 $940 $81 $1,021 $2.10 $6.00 9,717 35
Danskin 1 Retrofit—Simple-Cycle Combustion Turbine (SCCT) to CCCT Conversion 90 $2,530 $94 $2,624 $1.40 $3.10 6,909 30
Geothermal 30 $5,150 $167 $5,317 $10.40 $0.00 0 30
Long-Duration Storage—Pumped Hydro (12 hour) 250 $3,710 $207 $3,917 $1.80 $0.60 0 75
Medium-Duration Storage—Li Battery (8 hour) 50 $2,500 $37 $2,537 $5.20 $0.00 0 20
Multi-Day-Duration Storage—Iron-Air Battery (100 hour) 50 $2,400 $37 $2,437 $1.80 $0.00 0 30
Nuclear—Small Modular Reactor 100 $7,960 $174 $8,134 $11.40 $4.30 10,461 60
Peaking Gas—Reciprocating Gas Engine (Recip) 50 $1,880 $81 $1,961 $3.50 $6.80 8,699 40
Peaking Gas—SCCT 170 $910 $81 $991 $2.10 $6.00 9,717 35
Short-Duration Storage—Li Battery (4 hour) 50 $1,600 $37 $1,637 $2.90 $0.00 0 20
Short-Duration Storage—Li Battery (4 hour)—Distribution Connected 5 $1,440 $40 $1,480 $2.90 $0.00 0 20
Solar PV 100 $1,200 $22 $1,222 $1.90 $0.00 0 30
Wind—Idaho 100 $1,760 $22 $1,782 $4.10 $0.00 0 30
Wind—Wyoming 100 $1,760 $22 $1,782 $4.10 $0.00 0 30
2

Supply-Side Resource Data
Page 22 2023 Integrated Resource Plan—Appendix C
Supply-Side Resource Escalation Factors1 (2024–2032)
Baseload Gas—Combined-Cycle Combustion Turbine (CCCT) 1.68% 1.90% 1.78% 2.01% 2.00% 2.24% 2.00% 2.24%
Biomass 1.94% 1.95% 1.95% 1.94% 1.94% 1.94% 1.93% 1.93%
Clean Peaking Gas—Hydrogen Combustion Turbine 0.76% 1.53% 1.24% 1.78% 1.77% 2.04% 1.90% 2.03%
Danskin 1 Retrofit—Simple-Cycle Combustion Turbine (SCCT) to CCCT Conversion 1.68% 1.90% 1.78% 2.01% 2.00% 2.24% 2.00% 2.24%
Geothermal 1.07% 1.05% 1.02% 1.00% 0.97% 0.94% 2.10% 2.10%
Long-Duration Storage—Pumped Hydro (12 hour) 2.60% 2.60% 2.60% 2.60% 2.60% 2.60% 2.60% 2.60%
Medium-Duration Storage—Li Battery (8 hour) 0.00% -2.56% -2.14% -2.68% -2.35% -2.12% 1.39% 1.33%
Multi-Day-Duration Storage—Iron-Air Battery (100 hour) 0.00% -2.56% -2.14% -2.68% -2.35% -2.12% 1.39% 1.33%
Nuclear—Small Modular Reactor 1.96% 1.95% 1.95% 1.95% 1.94% 1.94% 1.93% 1.93%
Peaking Gas—Reciprocating Gas Engine (Recip) 0.76% 1.53% 1.24% 1.78% 1.77% 2.04% 1.90% 2.03%
Peaking Gas—SCCT 0.76% 1.53% 1.24% 1.78% 1.77% 2.04% 1.90% 2.03%
Short-Duration Storage—Li Battery (4 hour) 0.00% -1.67% -1.36% -2.04% -1.18% -1.33% 1.40% 1.33%
Short-Duration Storage—Li Battery (4 hour)—Distribution Connected 0.00% -1.67% -1.36% -2.04% -1.18% -1.33% 1.40% 1.33%
Solar PV -1.88% -2.09% -2.32% -2.57% -2.86% -3.17% 1.71% 1.70%
Wind—Idaho -1.47% -1.65% -1.83% -2.04% -2.27% -2.51% 1.60% 1.59%
Wind—Wyoming -1.47% -1.65% -1.83% -2.04% -2.27% -2.51% 1.60% 1.59%
1 Factors include the 2023 IRP general O&M escalation rate assumption of 2.6%.
Supply-Side Resource Data
2023 Integrated Resource Plan—Appendix C Page 23
Supply-Side Resource Escalation Factors1 (2033–2043)
Baseload Gas—Combined-Cycle Combustion Turbine (CCCT) 2.11% 2.23% 2.11% 2.23% 2.11% 2.23% 2.10% 2.22% 2.22% 2.10% 2.22%
Biomass 1.92% 1.92% 1.91% 1.91% 1.90% 1.90% 1.89% 1.89% 1.88% 1.88% 1.87%
Clean Peaking Gas—Hydrogen Combustion Turbine 2.03% 2.17% 2.03% 2.02% 2.02% 2.16% 2.01% 2.01% 2.01% 2.15% 2.00%
Danskin 1 Retrofit—Simple-Cycle Combustion Turbine (SCCT) to CCCT Conversion 2.11% 2.23% 2.11% 2.23% 2.11% 2.23% 2.10% 2.22% 2.22% 2.10% 2.22%
Geothermal 2.10% 2.10% 2.10% 2.10% 2.10% 2.10% 2.10% 2.10% 2.10% 2.10% 2.10%
Long-Duration Storage—Pumped Hydro (12 hour) 2.60% 2.60% 2.60% 2.60% 2.60% 2.60% 2.60% 2.60% 2.60% 2.60% 2.60%
Medium-Duration Storage—Li Battery (8 hour) 1.32% 1.30% 1.28% 1.27% 1.25% 1.23% 1.21% 1.19% 1.17% 1.15% 1.13%
Multi-Day-Duration Storage—Iron-Air Battery (100 hour) 1.32% 1.30% 1.28% 1.27% 1.25% 1.23% 1.21% 1.19% 1.17% 1.15% 1.13%
Nuclear—Small Modular Reactor 1.92% 1.92% 1.92% 1.91% 1.91% 1.90% 1.90% 1.89% 1.89% 1.88% 1.88%
Peaking Gas—Reciprocating Gas Engine (Recip) 2.03% 2.17% 2.03% 2.02% 2.02% 2.16% 2.01% 2.01% 2.01% 2.15% 2.00%
Peaking Gas—SCCT 2.03% 2.17% 2.03% 2.02% 2.02% 2.16% 2.01% 2.01% 2.01% 2.15% 2.00%
Short-Duration Storage—Li Battery (4 hour) 1.32% 1.30% 1.28% 1.27% 1.25% 1.23% 1.21% 1.19% 1.17% 1.15% 1.13%
Short-Duration Storage—Li Battery (4 hour)—Distribution Connected 1.32% 1.30% 1.28% 1.27% 1.25% 1.23% 1.21% 1.19% 1.17% 1.15% 1.13%
Solar PV 1.69% 1.68% 1.68% 1.67% 1.66% 1.65% 1.64% 1.63% 1.62% 1.61% 1.60%
Wind—Idaho 1.58% 1.57% 1.56% 1.55% 1.54% 1.52% 1.51% 1.50% 1.49% 1.48% 1.46%
Wind—Wyoming 1.58% 1.57% 1.56% 1.55% 1.54% 1.52% 1.51% 1.50% 1.49% 1.48% 1.46%

Supply-Side Resource Data
Page 24 2023 Integrated Resource Plan—Appendix C
Levelized Cost of Energy (costs in 2024$, $/MWh) at stated capacity factors
Supply-Side Resources Cost of Capital1 Non-Fuel O&M2 Fuel3 Total Cost per MWh4,5 Capacity Factor
Baseload Gas—Combined-Cycle Combustion Turbine (CCCT) $36 $12 $42 $89 55%
Biomass $65 $61 $110 $236 64%
Clean Peaking Gas—Hydrogen Combustion Turbine $68 $50 $191 $309 12%
Danskin 1 Retrofit—Simple-Cycle Combustion Turbine (SCCT) to CCCT Conversion $56 $13 $46 $115 55%
Geothermal $50 $27 $0 $78 90%
Long-Duration Storage—Pumped Hydro (12 hour) $82 $17 $0 $99 50%
Medium-Duration Storage—Li Battery (8 hour) $77 $33 $0 $111 33%
Multi-Day-Duration Storage—Iron-Air Battery (100 hour) $148 $36 $0 $184 15%
Nuclear—Small Modular Reactor $83 $42 $13 $139 94%
Peaking Gas—Reciprocating Gas Engine (Recip) $188 $83 $61 $332 12%
Peaking Gas—SCCT $98 $50 $66 $214 12%
Short-Duration Storage—Li Battery (4 hour) $97 $37 $0 $134 17%
Short-Duration Storage—Li Battery (4 hour)—Distribution Connected $88 $36 $0 $124 17%
Solar PV $17 $15 $0 $31 31%
Wind—Idaho $28 $25 $0 $53 36%
Wind—Wyoming $16 $19 $0 $35 47%
1 Cost of Capital includes tax credit benefits (ITC/PTC).
2 Non-Fuel O&M includes fixed and property taxes.
3 Fuel costs are not included for biomass resource.
4 Storage resources will have a cost or benefit associated with the price difference between the energy price to charge the storage and the energy price during the time of discharge (less losses). Arbitrage is not included in the LCOE calculation in the table. As noted in IRP, levelized cost for storage resources is driven by fixed costs.
5 Rounding may make the sum of Capital, Non-Fuel O&M and Fuel not match the total cost per MWh.

Supply-Side Resource Data
2023 Integrated Resource Plan—Appendix C Page 25
Levelized Capacity (fixed) Cost per kW/Month (costs in 2024$)
Supply-Side Resources Cost of Capital1 Non-Fuel O&M2 Total Cost per kW3
Baseload Gas—Combined-Cycle Combustion Turbine (CCCT) $14 $3 $17
Biomass $31 $24 $54
Clean Peaking Gas—Hydrogen Combustion Turbine $8 $4 $12
Danskin 1 Retrofit—Simple-Cycle Combustion Turbine (SCCT) to CCCT Conversion $23 $4 $26
Geothermal $33 $18 $51
Long-Duration Storage—Pumped Hydro (12 hour) $30 $6 $36
Medium-Duration Storage—Li Battery (8 hour) $19 $8 $27
Multi-Day-Duration Storage—Iron-Air Battery (100 hour) $16 $4 $20
Nuclear—Small Modular Reactor $57 $25 $82
Peaking Gas—Reciprocating Gas Engine (Recip) $16 $6 $23
Peaking Gas—SCCT $9 $4 $12
Short-Duration Storage—Li Battery (4 hour) $12 $5 $17
Short-Duration Storage—Li Battery (4 hour)—Distribution Connected $11 $4 $15
Solar PV $4 $3 $7
Wind—Idaho $7 $7 $14
Wind—Wyoming $5 $7 $12
1 Cost of Capital includes tax credit benefits (ITC/PTC).
2 Non-Fuel O&M includes fixed and property taxes.
3 Rounding may make sum of Cost of Capital and Non-Fuel O&M costs not match Total Cost per kW.
Supply-Side Resource Data
Page 26 2023 Integrated Resource Plan—Appendix C
Renewable Energy Certificate Forecast
Year Nominal ($/MWh)
2024 $22.07
2025 $20.10
2026 $20.58
2027 $21.06
2028 $21.54
2029 $22.01
2030 $22.49
2031 $22.97
2032 $23.45
2033 $23.93
2034 $24.40
2035 $24.88
2036 $25.36
2037 $25.84
2038 $26.32
2039 $26.79
2040 $27.27
2041 $27.75
2042 $28.23
2043 $28.71

Existing Resource Data
2023 Integrated Resource Plan—Appendix C Page 27
EXISTING RESOURCE DATA
Qualifying Facility Data (PURPA)
Cogeneration & Small Power Production Projects
Status as of July 31, 2023
Hydro Projects
Contract Contract
Project MW -line Date End Date Project MW -line Date End Date
Arena Drop 0.45 Sep-2010 Sep-2030 Little Wood River Ranch II 1.25 Oct-2015 Oct-2035
Baker City Hydro 0.24 Sep-2015 Sep-2030 Little Wood River Res 2.85 Mar-2020 Mar-2040
Barber Dam 3.70 Apr-1989 Apr-2024 Low Line Canal 8.20 May-2020 May-2040
Birch Creek 0.07 Nov-2019 Nov-2039 Low Line Midway Hydro 2.50 Aug-2007 Aug-2027
Black Canyon #3 0.13 Apr-2019 Apr-2039 Lowline #2 2.79 May-2023 May-2043
Black Canyon Bliss Hydro 0.03 Oct-2015 Oct-2035 Magic Reservoir 9.07 Jun-1989 Jun-2024
Blind Canyon 1.63 Dec-2014 Dec-2034 Malad River 1.17 May-2019 May-2039
Box Canyon 0.30 Feb-2019 Feb-2039 Marco Ranches 1.20 Aug-2020 Aug-2040
Briggs Creek 0.60 Oct-2020 Oct-2040 MC6 Hydro 2.30 Apr-2021 Sep-2040
Bypass 9.96 Jun-2023 Jun-2043 Mile 28 1.50 Jun-1994 Jun-2029
Canyon Springs 0.11 Jan-2019 Jan-2039 Mitchell Butte 2.09 May-1989 Dec-2034
Cedar Draw 1.55 Jun-2019 Jun-2039 Mora Drop Small Hydro 1.85 Sep-2006 Sep-2026
Clear Springs Trout 0.56 Nov-2018 Nov-2038 Mud Creek/S&S 0.52 Feb-2017 Feb-2037
Coleman Hydro 0.80 Sep-2023 Estimated Mud Creek/White 0.29 Jan-2021 Jan-2041
Crystal Springs 2.55 Apr-2021 Apr-2041 North Gooding Main Hydro 1.30 Oct-2016 Oct-2036
Curry Cattle Company 0.25 Jun-2018 Jun-2033 Owyhee Dam CSPP 5.00 Aug-1985 May-2034
Dietrich Drop 4.77 Sep-2023 Sep-2043 Pigeon Cove 1.75 Nov-2019 Nov-2039
Eightmile Hydro Project 0.36 Oct-2014 Oct-2034 Pristine Springs #1 0.13 May-2020 May-2040
Elk Creek Hydro 2.35 Jun-2021 Apr-2041 Pristine Springs #3 0.20 May-2020 May-2040
Fall River 9.10 Aug-1993 Aug-2028 Reynolds Irrigation 0.35 Sep-2021 Sep-2041
Fargo Drop Hydroelectric 1.27 Apr-2013 Apr-2033 Rock Creek #1 2.17 Jan-2018 Jan-2038
Faulkner Ranch Hydro 0.87 Aug-2022 Aug-2042 Rock Creek #2 1.90 Apr-1989 Apr-2024
Fisheries Dev. 0.26 Jul-1990 Jul-2040 Sagebrush 0.58 Jun-2021 Jun-2040
Geo-Bon #2 1.06 Nov-2021 Nov-2041 Sahko Hydro 0.50 Feb-2021 Feb-2041
Hailey CSPP 0.04 Jun-2020 Jun-2025 Shingle Creek 0.22 Aug-2022 Aug-2027
Hazelton A 8.10 Mar-2011 Feb-2026 Shoshone #2 0.58 May-1996 May-2031
Hazelton B 7.60 May-1993 May-2028 Shoshone CSPP 0.36 Feb-2017 Feb-2037
Head of U Canal Project 1.28 Jun-2015 Jun-2035 Snake River Pottery 0.09 Dec-2019 Dec-2027
Horseshoe Bend Hydro 9.50 Sep-1995 Sep-2030 Snedigar 0.50 Jan-2020 Jan-2040
Jim Knight 0.48 May-2021 May-2040 Tiber Dam 7.50 Jun-2004 Jun-2024
Koyle Small Hydro 1.25 Apr-2019 Apr-2039 Trout-Co 0.28 Dec-2021 Dec-2041
Lateral # 10 2.06 May-2020 May-2040 Tunnel #1 7.00 Jun-1993 Jun-2036
Lemhi Hydro 0.45 Aug-2021 Aug-2041 White Water Ranch 0.16 Aug-2020 Aug-2040
LeMoyne Hydro 0.08 Jun-2020 Jun-2030 Wilson Lake Hydro 8.40 May-1993 May-2028
Little Wood River Ranch I 1.01 Aug-2021 Aug-2041
Total Hydro Nameplate Rating 151.32 MW

Existing-Side Resource Data
Page 28 2023 Integrated Resource Plan—Appendix C
Cogeneration/Thermal Projects
Contract
Project MW On-line Date End Date
Pico Energy, LLC 2.13 Aug-2020 Aug-2030
Simplot Pocatello Cogen 15.90 Mar-2022 Mar-2025
TASCO—Nampa Natural Gas 2 Sep-2003 Sept-2040
TASCO—Twin Falls Natural Gas 3 Aug-2001 Jan-2040
Total Thermal Nameplate Rating 23.03 MW

Biomass Projects
Contract Contract
Project MW On-line Date End Date Project MW On-line Date End Date
Bannock County Landfill 3.20 May-2014 May-2034 Pocatello Waste 0.50 Jan-2021 Jan-2041
Fighting Creek Landfill Gas to Energy Station 3.06 Apr-2014 Apr-2029 SISW LFGE 5.00 Sept-2018 Sept-2038
Hidden Hollow Landfill Gas 3.20 Jan-2007 Jan-2027 Tamarack CSPP 6.25 Jun-2018 Jun-2038
Total Biomass Nameplate Rating 21.21 MW

Solar Projects
Contract Contract
Project MW On-line Date End Date Project MW On-line Date End Date
American Falls Solar II, LLC 20.00 Mar-2017 Mar-2037 Mt. Home Solar 1, LLC 20.00 Mar-2017 Mar-2037
American Falls Solar, LLC 20.00 Mar-2017 Mar-2037 Murphy Flat Power, LLC 20.00 Apr-2017 Apr-2037
Baker Solar Center 15.00 Feb-2020 Feb-2040 Ontario Solar Center 3.00 Mar-2020 Mar-2040
Brush Solar 2.75 Dec-2019 Dec-2039 Open Range Solar Center, LLC 10.00 Oct-2016 Oct-2036
Durkee Solar 3.00 Dec-2024 Mar-2042 Orchard Ranch Solar, LLC 20.00 Mar-2017 Mar-2037
Grand View PV Solar Two 80.00 Dec-2016 Dec-2036 Prairie City Solar 29.30 Dec-2024 Estimated
Grove Solar Center, LLC 6.00 Oct-2016 Oct-2036 Railroad Solar Center, LLC 4.50 Dec-2016 Dec-2036
Hyline Solar Center, LLC 9.00 Nov-2016 Nov-2036 Simcoe Solar, LLC 20.00 Mar-2017 Mar-2037
ID Solar 1 40.00 Aug-2016 Jan-2036 Thunderegg Solar Center, LLC 10.00 Nov-2016 Nov-2036
Moore's Hollow Solar 42.00 Dec-2024 Estimated Vale Air Solar Center, LLC 10.00 Nov-2016 Nov-2036
Morgan Solar 3.00 Apr-2020 Apr-2040 Vale 1 Solar 3.00 Jul-2020 Jul-2040
Total Solar Nameplate Rating 390.55 MW

Existing Resource Data
2023 Integrated Resource Plan—Appendix C Page 29
Wind Projects
Contract Contract
Project MW On-line Date End Date Project MW On-line Date End Date
Bennett Creek Wind Farm 21.00 Dec-2008 Dec-2028 Mainline Windfarm 23.00 Dec-2012 Dec-2032
Benson Creek Windfarm 10.00 Mar-2017 Mar-2037 Milner Dam Wind 19.92 Feb-2011 Feb-2031
Burley Butte Wind Park 21.30 Feb-2011 Feb-2031 Oregon Trail Wind Park 13.50 Jan-2011 Jan-2031
Camp Reed Wind Park 22.50 Dec-2010 Dec-2030 Payne's Ferry Wind Park 21.00 Dec-2010 Dec-2030
Cassia Wind Farm LLC 8.40 Mar-2009 Mar-2029 Pilgrim Stage Station Wind Park 10.50 Jan-2011 Jan-2031
Cold Springs Windfarm 23.00 Dec-2012 Dec-2032 Prospector Windfarm 10.00 Mar-2017 Mar-2037
Desert Meadow Windfarm 23.00 Dec-2012 Dec-2032 Rockland Wind Farm 80.00 Dec-2011 Dec-2036
Durbin Creek Windfarm 10.00 Mar-2017 Mar-2037 Ryegrass Windfarm 23.00 Dec-2012 Dec-2032
Fossil Gulch Wind 10.50 Sep-2005 Sep-2025 Salmon Falls Wind 22.00 Apr-2011 Apr-2031
Golden Valley Wind Park 12.00 Feb-2011 Feb-2031 Sawtooth Wind Project 22.00 Nov-2011 Nov-2031
Hammett Hill Windfarm 23.00 Dec-2012 Dec-2032 Thousand Springs Wind Park 12.00 Jan-2011 Jan-2031
High Mesa Wind Project 40.00 Dec-2012 Dec-2032 Tuana Gulch Wind Park 10.50 Jan-2011 Jan-2031
Horseshoe Bend Wind 9.00 Feb-2006 Feb-2026 Tuana Springs Expansion 35.70 May-2010 May-2030
Hot Springs Wind Farm 21.00 Dec-2008 Dec-2028 Two Ponds Windfarm 23.00 Dec-2012 Dec-2032
Jett Creek Windfarm 10.00 Mar-2017 Mar-2037 Willow Spring Windfarm 10.00 Mar-2017 Mar-2037
Lime Wind Energy 3.00 Dec-2011 Dec-2031 Yahoo Creek Wind Park 21.00 Dec-2010 Dec-2030
Total Wind Nameplate Rating 624.82 MW
Total Nameplate Rating 1,210.90 MW
The above is a summary of the nameplate rating for the CSPP projects under contract with Idaho Power as of July 31, 2023. In the case of CSPP projects, nameplate rating of the actual generation units is not an accurate or reasonable estimate of the actual energy these projects will deliver to Idaho Power. Historical generation information,
resource specific industry standard capacity factors, and other known and measurable operating characteristics are accounted for in determining a reasonable estimate of the energy these projects will produce.

Power Purchase Agreement Data
Project MW On-Line Date Contract End Date
Wind Projects
Elkhorn Wind Project 101 Dec-2007 Dec-2027
Total Wind Nameplate Rating 101
Geothermal Projects
Raft River Unit 1 13 Apr-2008 Apr-2033
Neal Hot Springs 22 Nov-2012 Nov-2037
Total Geothermal Nameplate Rating 35
Solar Projects
Black Mesa Solar 40 Jun-2023 Jun-2043
Franklin Solar 100 Jun-2024 Jun-2049
Jackpot Solar Facility 120 Dec-2022 Dec-2042
Pleasant Valley Solar 200 Mar-2025 Mar-2045
Total Solar Nameplate Rating 460
Total Nameplate Rating 596
The above is a summary of the Nameplate rating for the projects under contract with Idaho Power as of July 31, 2023. In the case of variable-energy resource projects, Nameplate rating of the actual generation units is not an accurate or reasonable estimate of the actual energy these projects will deliver to Idaho Power. Historical generation
information, resource specific industry standard capacity factors, and other known and measurable operating characteristics are accounted for in determining a reasonable estimate of the energy these projects will produce.
Existing-Side Resource Data
Page 30 2023 Integrated Resource Plan—Appendix C
Hydro Flow Modeling
Hydro Models
Idaho Power uses two modeling methods for the development of future hydro flow scenarios for the
IRP. The first method accounts for surface water regulation in the system while the second method
addresses groundwater processes.
The first modeling method consists of two models built in the Center for Advanced Decision Support
for Water and Environmental Systems (CADSWES) RiverWare modeling framework. The first of these
models covers the spatial extent of the Snake River basin from the headwaters to Brownlee inflow.
The second model takes the results of the first and regulates the flows through the Hells Canyon
Complex (HCC). The planning models have been updated to include hydrologic conditions for water
years 1981 through 2018.
The second modeling method uses the Eastern Snake Plain Aquifer Model (ESPAM) from the Idaho
Department of Water Resources (IDWR) to model aquifer management practices implemented on the
Eastern Snake Plain Aquifer (ESPA). ESPAM version 2.2 has been used for this modeling, which is the
latest version and was released in 2020.
Hydro Model Inputs
The inputs for the 2023 IRP were derived, in part, from management practices outlined in an
agreement between the Surface Water Coalition (SWC) and Idaho Groundwater Appropriators (IGWA).
The agreement set out specific targets for several management practices that include aquifer recharge,
irrigation system conversions from groundwater to surface water, and a total reduction in
groundwater diversions of 240,000 acre-ft annually. The modeling also included inputs from other
entities diverting groundwater on the ESPA who have separate mitigation agreements with SWC.
Model inputs also included a long-term analysis of trends in reach gains to the Snake River from
Palisades Dam to King Hill. Weather modification activities conducted by Idaho Power and other
participating entities were included in the modeling effort. The modeling also included aquifer
recharge by the Idaho Water Resource Board (IWRB) targeting an average annual natural flow recharge
of 250,000 acre-ft per year.
Recharge capacity modeled for the 2023 IRP included diversions with the capability of diverting all
available water at the Snake River below Milner Dam during the winter months under typical release
conditions. These diversions can have a significant impact to flows downstream of Milner Dam.
The number of system conversion acres modeled and associated water savings was based on data
provided by IDWR and local groundwater districts. The current model assumes approximately
57,000 acres of converted land on the ESPA. Water savings for conversion projects are calculated at a
rate of 2 acre-ft/converted acre. Diversions for conversion projects are modeled at approximately
114,000 acre-ft and are held essentially constant through all years of the IRP. The model accounted for
Existing Resource Data
2023 Integrated Resource Plan—Appendix C Page 31
an approximately 140,000 acre-ft decrease in groundwater pumping from ESPA. These reflect the same
assumptions of conversion projects as modeled in the 2021 IRP.
The decrease was spread evenly over groundwater irrigated lands subject to the agreement between
SWC and IGWA. The SWC agreement requires a total reduction of 240,000 acre-ft/year, but the
agreement allows for a portion to be offset by aquifer recharge activities. Based on recent
management activity, an approximate 100,000 acre-ft/year reduction is accomplished through other
forms of mitigation, such as private aquifer recharge.
The 2023 IRP modeling also recognized ongoing declines in specific reaches. Future reach declines
were determined using statistical analysis. Trend data indicate reach gains from Blackfoot to Neely and
from Lower Salmon Falls Dam to King Hill demonstrated a statistically significant decline from 1992 to
2021. The long-term declines are still present, and are relatively the same as the declines used in the
2021 IRP.
Weather modification was added to the model at various levels of development. For IRP years 2024
through 2029, weather modification reflects the 2022 level of program development in the Upper
Snake, Wood, Boise, and Payette river basins. From IRP year 2030 and onward, weather modification
levels in Upper Snake, Wood, and Boise river basins were increased due to an anticipation of
expanding the cloud seeding program. The level of weather modification was held constant at the
current level in the Payette River Basin throughout the IRP planning horizon. The modeling also
accounts for changes in reach gains from observed water management activities on the ESPA since
2014. Idaho Power used data from IDWR and other sources to determine the magnitude of the
management activities and ESPAM was used to model the projected reach gains. Those management
activities can have impacts on reach gains for up to 30 years.
Hydro Model Results
Overall inflow to Brownlee Reservoir increases from IRP modeled year 2024 through 2031. Flows peak
in 2031 with the 50% exceedance water year annual inflow to Brownlee Reservoir at 11.9 million
acre-ft/year. In 2043, those flows declined to approximately 11.8 million acre-ft/year.
The Brownlee inflow volumes for the 2023 IRP are lower than those reported in the 2021 IRP.
There are several factors leading to the decrease in modeled flows. Updates to recharge capacity to
reflect current infrastructure availability and capacities was likely the largest impact. While this does
have some improvement in the modeled aquifer health and reach gains, the surface water impacts,
reducing releases at Milner, significantly outweigh the groundwater impacts over the 20-year planning
window. Another notable change was the use of ESPAM 2.2, which has a better calibration of the
groundwater system, and reduced aquifer response below Milner which better reflects observations
over the last several years. As a result, groundwater management activities produce lower reach gains
throughout Idaho Power’s hydro system.

Existing-Side Resource Data
Page 32 2023 Integrated Resource Plan—Appendix C
Hydro Modeling Potential Energy Limits (aMW)
50th Percentile (planning case) Extreme Weather Scenario
Year Month HCC ROR Total HCC ROR Total
2024 Jan 642 276 917 1155 505 1,660
Feb 828 291 1,119 1151 474 1,625
Mar 739 339 1,078 990 505 1,494
Apr 873 355 1,229 1093 527 1,620
May 894 328 1,222 1131 531 1,662
June 846 362 1,208 1224 489 1,713
July 567 371 938 902 403 1,305
Aug 457 283 741 646 420 1,065
Sept 508 236 744 737 260 998
Oct 388 213 601 446 236 682
Nov 339 184 522 330 205 535
Dec 457 178 635 625 378 1,003
Annual aMW 628 285 913 869 411 1,280
2025 Jan 645 279 925 1185 497 1,683
Feb 831 294 1,125 1129 474 1,603
Mar 741 340 1,081 954 504 1,458
Apr 874 357 1,231 934 505 1,439
May 895 331 1,226 1047 513 1,560
June 847 363 1,210 1253 515 1,767
July 568 373 940 844 397 1,241
Aug 458 284 742 670 434 1,104
Sept 509 236 745 696 263 959
Oct 388 214 602 408 236 644
Nov 339 184 523 328 203 530
Dec 458 178 636 649 431 1,080
Annual aMW 629 286 915 841 414 1,256
*HCC=Hells Canyon Complex, **ROR=Run of River

Existing Resource Data
2023 Integrated Resource Plan—Appendix C Page 33
50th Percentile (planning case) Extreme Weather Scenario
Year Month HCC ROR Total HCC ROR Total
2026 Jan 647 282 929 1104 497 1,601
Feb 833 296 1,130 1077 467 1,544
Mar 744 340 1,084 1069 385 1,454
Apr 874 358 1,232 1127 475 1,602
May 895 331 1,227 915 499 1,414
June 848 363 1,211 897 415 1,312
July 568 373 941 624 402 1,025
Aug 458 284 742 463 285 748
Sept 509 237 745 616 243 858
Oct 388 214 602 391 225 617
Nov 339 184 523 334 193 527
Dec 459 178 637 447 182 629
Annual aMW 630 287 917 755 356 1,111
2027 Jan 648 283 931 543 261 805
Feb 834 298 1,132 587 252 840
Mar 744 341 1,085 520 281 800
Apr 874 359 1,233 544 223 767
May 895 332 1,227 533 230 763
June 848 364 1,211 510 355 865
July 568 373 941 474 273 747
Aug 458 284 742 403 211 614
Sept 509 237 746 409 195 604
Oct 388 214 602 350 194 544
Nov 339 184 523 339 175 514
Dec 459 179 638 427 169 596
Annual aMW 630 287 918 470 235 705
*HCC=Hells Canyon Complex, **ROR=Run of River

Existing-Side Resource Data
Page 34 2023 Integrated Resource Plan—Appendix C
50th Percentile (planning case) Extreme Weather Scenario
Year Month HCC ROR Total HCC ROR Total
2028 Jan 649 283 932 548 171 719
Feb 835 300 1,135 582 169 751
Mar 745 342 1,087 600 181 781
Apr 874 360 1,234 859 200 1,058
May 895 332 1,227 649 279 928
June 848 364 1,212 740 239 979
July 568 373 941 487 262 750
Aug 458 284 742 417 215 631
Sept 509 237 745 383 197 581
Oct 388 214 602 358 193 551
Nov 339 184 523 345 176 521
Dec 460 179 638 424 170 595
Annual aMW 631 288 918 533 204 737
2029 Jan 650 283 933 577 176 753
Feb 832 301 1,133 682 178 860
Mar 743 342 1,085 503 176 679
Apr 874 360 1,234 713 230 943
May 892 332 1,224 958 241 1,199
June 839 363 1,203 860 238 1,098
July 567 371 938 501 345 846
Aug 460 284 744 421 249 669
Sept 508 237 745 370 216 586
Oct 388 214 602 359 195 554
Nov 339 184 523 349 174 523
Dec 460 179 639 416 171 587
Annual aMW 629 288 917 559 216 775
*HCC=Hells Canyon Complex, **ROR=Run of River

Existing Resource Data
2023 Integrated Resource Plan—Appendix C Page 35
50th Percentile (planning case) Extreme Weather Scenario
Year Month HCC ROR Total HCC ROR Total
2030 Jan 710 288 998 535 202 737
Feb 850 325 1,176 687 214 901
Mar 795 348 1,143 722 257 979
Apr 883 380 1,263 794 268 1,062
May 926 362 1,288 728 233 961
June 880 381 1,261 654 261 915
July 573 376 949 567 333 900
Aug 463 288 751 452 217 670
Sept 511 238 749 462 199 661
Oct 388 215 603 375 187 563
Nov 339 185 523 331 170 501
Dec 464 180 644 446 166 612
Annual aMW 649 297 946 563 226 788
2031 Jan 714 290 1,003 489 169 658
Feb 849 327 1,177 508 161 669
Mar 796 350 1,146 378 162 540
Apr 884 382 1,266 559 229 788
May 926 365 1,291 926 315 1,241
June 882 381 1,263 701 283 984
July 573 376 949 586 382 968
Aug 463 288 752 451 277 727
Sept 511 239 750 455 225 680
Oct 388 215 603 366 202 568
Nov 339 185 523 347 171 518
Dec 464 180 644 616 172 788
Annual aMW 649 298 947 532 229 761
*HCC=Hells Canyon Complex, **ROR=Run of River

Existing-Side Resource Data
Page 36 2023 Integrated Resource Plan—Appendix C
50th Percentile (planning case) Extreme Weather Scenario
Year Month HCC ROR Total HCC ROR Total
2032 Jan 714 290 1,004 1123 292 1,415
Feb 847 327 1,174 1086 225 1,310
Mar 801 350 1,151 1045 422 1,467
Apr 885 391 1,276 1050 513 1,562
May 926 366 1,292 1152 514 1,667
June 882 381 1,263 1173 468 1,640
July 573 376 949 633 420 1,053
Aug 463 289 752 488 289 778
Sept 511 239 750 563 239 802
Oct 388 215 603 389 211 600
Nov 339 185 524 337 177 514
Dec 464 180 644 480 172 652
Annual aMW 649 299 948 793 328 1,122
2033 Jan 714 290 1,004 575 287 862
Feb 848 328 1,177 685 312 997
Mar 796 350 1,146 614 366 980
Apr 884 382 1,266 622 292 913
May 926 363 1,289 670 238 908
June 881 382 1,263 524 342 866
July 573 376 949 488 286 774
Aug 463 289 751 408 230 638
Sept 510 239 749 510 219 730
Oct 388 215 603 366 195 561
Nov 339 185 524 334 176 510
Dec 464 180 644 419 169 589
Annual aMW 649 298 947 518 259 777
*HCC=Hells Canyon Complex, **ROR=Run of River

Existing Resource Data
2023 Integrated Resource Plan—Appendix C Page 37
50th Percentile (planning case) Extreme Weather Scenario
Year Month HCC ROR Total HCC ROR Total
2034 Jan 714 289 1,003 509 163 672
Feb 849 328 1,176 610 161 771
Mar 796 350 1,145 631 169 800
Apr 884 381 1,265 831 335 1,166
May 926 363 1,289 934 247 1,181
June 881 381 1,262 977 269 1,245
July 572 376 949 595 316 910
Aug 462 289 751 504 350 853
Sept 510 238 748 482 232 714
Oct 388 215 603 391 205 596
Nov 338 185 524 341 173 514
Dec 463 180 644 415 169 584
Annual aMW 649 298 947 601 232 834
2035 Jan 713 289 1,002 711 416 1,127
Feb 848 328 1,176 806 399 1,205
Mar 796 350 1,145 863 475 1,337
Apr 884 381 1,265 1072 511 1,583
May 925 363 1,289 1007 429 1,437
June 881 381 1,262 1112 492 1,604
July 572 376 948 629 374 1,003
Aug 462 288 751 515 351 866
Sept 509 238 747 482 235 717
Oct 388 215 602 388 213 601
Nov 338 185 523 346 174 519
Dec 463 180 643 427 169 595
Annual aMW 648 298 946 696 353 1,050
*HCC=Hells Canyon Complex, **ROR=Run of River

Existing-Side Resource Data
Page 38 2023 Integrated Resource Plan—Appendix C
50th Percentile (planning case) Extreme Weather Scenario
Year Month HCC ROR Total HCC ROR Total
2036 Jan 713 289 1,001 625 303 928
Feb 849 327 1,176 696 300 996
Mar 795 349 1,144 628 310 938
Apr 884 381 1,264 712 256 968
May 925 363 1,288 815 310 1,125
June 880 381 1,261 1107 315 1,422
July 572 376 948 513 285 798
Aug 462 288 750 443 242 685
Sept 508 238 747 494 229 723
Oct 388 215 602 390 211 601
Nov 338 185 523 339 176 515
Dec 463 180 643 519 174 693
Annual aMW 648 298 946 607 260 866
2037 Jan 710 288 999 822 269 1,091
Feb 851 327 1,178 1053 303 1,356
Mar 794 349 1,143 945 479 1,424
Apr 883 381 1,264 915 465 1,380
May 925 363 1,288 976 444 1,420
June 880 381 1,261 1235 520 1,755
July 571 376 947 1096 512 1,609
Aug 461 288 750 695 441 1,136
Sept 508 238 746 659 258 917
Oct 387 215 602 419 219 638
Nov 338 185 523 339 184 523
Dec 463 180 643 618 444 1,062
Annual aMW 648 298 945 814 378 1,193
*HCC=Hells Canyon Complex, **ROR=Run of River

Existing Resource Data
2023 Integrated Resource Plan—Appendix C Page 39
50th Percentile (planning case) Extreme Weather Scenario
Year Month HCC ROR Total HCC ROR Total
2038 Jan 709 288 997 1068 488 1,556
Feb 852 326 1,178 1083 447 1,530
Mar 794 348 1,142 939 441 1,381
Apr 883 380 1,264 934 451 1,386
May 925 363 1,288 676 379 1,054
June 879 381 1,260 573 326 899
July 571 376 947 616 387 1,003
Aug 461 288 749 462 281 743
Sept 507 238 745 588 231 819
Oct 387 214 602 370 210 580
Nov 338 185 523 327 181 508
Dec 463 180 642 431 180 611
Annual aMW 647 297 945 672 334 1,006
2039 Jan 708 287 995 478 182 660
Feb 850 325 1,175 608 219 827
Mar 793 348 1,141 429 189 618
Apr 883 380 1,263 503 181 685
May 924 363 1,287 525 232 756
June 879 381 1,259 534 326 860
July 570 376 946 440 310 750
Aug 461 288 749 372 216 589
Sept 507 238 745 432 210 643
Oct 387 214 601 379 193 572
Nov 339 185 523 343 171 514
Dec 462 180 642 406 164 570
Annual aMW 647 297 944 454 216 670
*HCC=Hells Canyon Complex, **ROR=Run of River

Existing-Side Resource Data
Page 40 2023 Integrated Resource Plan—Appendix C
50th Percentile (planning case) Extreme Weather Scenario
Year Month HCC ROR Total HCC ROR Total
2040 Jan 706 286 992 451 174 625
Feb 849 325 1,174 595 174 769
Mar 792 347 1,139 812 306 1,118
Apr 883 385 1,268 759 417 1,176
May 925 356 1,280 695 315 1,010
June 878 380 1,258 622 297 919
July 570 376 945 515 385 900
Aug 460 288 748 436 282 718
Sept 506 238 744 426 223 649
Oct 387 214 601 369 211 580
Nov 339 185 523 339 172 510
Dec 462 180 642 499 174 672
Annual aMW 646 297 943 543 261 804
2041 Jan 704 287 991 667 328 994
Feb 847 325 1,173 943 360 1,303
Mar 791 348 1,139 561 332 892
Apr 882 384 1,267 518 298 816
May 924 355 1,279 449 282 731
June 877 380 1,257 456 310 766
July 570 375 945 497 375 872
Aug 460 288 747 378 269 647
Sept 505 238 743 384 226 610
Oct 386 214 601 358 200 558
Nov 339 185 523 341 168 509
Dec 462 180 641 475 165 640
Annual aMW 646 297 942 502 276 778
*HCC=Hells Canyon Complex, **ROR=Run of River

Existing Resource Data
2023 Integrated Resource Plan—Appendix C Page 41
50th Percentile (planning case) Extreme Weather Scenario
Year Month HCC ROR Total HCC ROR Total
2042 Jan 701 286 987 547 196 743
Feb 846 324 1,171 697 206 903
Mar 790 347 1,137 746 174 919
Apr 882 383 1,265 932 243 1,175
May 924 354 1,278 818 245 1,064
June 877 380 1,256 575 244 819
July 569 375 945 508 355 862
Aug 459 288 747 400 242 642
Sept 504 237 742 440 218 658
Oct 386 214 600 371 190 561
Nov 339 185 523 342 156 498
Dec 461 179 641 437 158 595
Annual aMW 645 296 941 568 219 787
2043 Jan 701 268 969 734 226 960
Feb 846 306 1,153 1098 406 1,504
Mar 790 329 1,119 946 509 1,454
Apr 882 366 1,248 952 499 1,450
May 924 335 1,259 1089 514 1,603
June 877 360 1,237 1187 456 1,643
July 569 356 925 650 343 992
Aug 459 269 728 553 360 913
Sept 504 217 721 620 236 857
Oct 386 195 581 407 212 618
Nov 339 168 506 329 175 503
Dec 461 162 623 454 196 650
Annual aMW 645 278 922 751 344 1,096
*HCC=Hells Canyon Complex, **ROR=Run of River

Long-Term Capacity Expansion Results
Page 42 2023 Integrated Resource Plan—Appendix C
LONG-TERM CAPACITY EXPANSION RESULTS (MW)
Main Cases
Preferred Portfolio–Valmy 1 & 2 (MW)
Year Coal Exits Gas Exits New Gas H2 Wind Solar 4-Hr 8-Hr 100-Hr Trans. Geo Demand Response
Energy Efficiency Forecast
2024 -357 0 357 0 0 100 96 0 0 0 0 0 17
2025 0 0 0 0 0 200 227 0 0 0 0 0 18
2026 -134 0 261 0 0 100 0 0 0 Jul B2H 0 0 19
2027 0 0 0 0 400 375 5 0 0 0 0 0 20
2028 0 0 0 0 400 150 5 0 0 0 0 0 21
2029 0 0 0 0 400 0 5 0 0 GWW1 0 20 22
2030 -350 0 350 0 100 500 155 0 0 0 30 0 21
2031 0 0 0 0 400 400 5 0 0 GWW2 0 0 21
2032 0 0 0 0 100 100 205 0 0 0 0 0 20
2033 0 0 0 0 0 0 105 0 0 0 0 20 20
2034 0 0 0 0 0 0 5 0 0 0 0 40 19
2035 0 0 0 0 0 0 5 0 0 0 0 40 18
2036 0 0 0 0 0 0 5 0 0 0 0 40 17
2037 0 0 0 0 0 0 55 50 0 0 0 0 17
2038 0 -706 0 340 0 0 155 50 200 0 0 0 17
2039 0 0 0 0 0 0 5 50 0 0 0 0 15
2040 0 0 0 0 0 400 5 0 0 GWW3 0 0 14
2041 0 0 0 0 0 200 5 0 0 0 0 0 14
2042 0 0 0 0 0 200 55 0 0 0 0 0 14
2043 0 0 0 0 0 600 0 0 0 0 0 0 14
Subtotal -841 -706 967 340 1,800 3,325 1,103 150 200 30 160 360
Total 6,888 Portfolio Cost: $9,746M

Long-Term Capacity Expansion Results
2023 Integrated Resource Plan—Appendix C Page 43
Valmy 2 (MW)
Year
Coal
Exits
Gas
Exits
New
Gas H2 Wind Solar 4-Hr 8-Hr 100-Hr Trans. Geo
Demand
Response
Energy
Efficiency
Forecast
2024 -357 0 357 0 0 100 96 0 0 0 0 0 17
2025 0 0 0 0 0 200 227 0 0 0 0 0 18
2026 -134 0 134 0 0 0 5 0 0 Jul B2H 0 0 19
2027 0 0 0 0 400 475 5 0 0 0 0 0 20
2028 0 0 0 0 400 150 5 0 0 0 0 20 21
2029 0 0 0 0 400 0 55 150 0 GWW1 0 20 22
2030 -350 0 350 0 300 300 5 0 0 0 30 20 21
2031 0 0 0 0 300 100 5 0 0 GWW2 0 0 21
2032 0 0 0 0 0 600 105 0 0 0 0 0 20
2033 0 0 0 0 0 0 105 0 0 0 0 40 20
2034 0 0 0 0 0 0 155 0 0 0 0 0 19
2035 0 0 0 0 0 0 205 0 0 0 0 0 18
2036 0 0 0 0 0 0 5 0 0 0 0 0 17
2037 0 0 0 0 0 0 5 0 0 0 0 40 17
2038 0 -706 340 340 0 0 55 50 50 0 0 0 17
2039 0 0 0 0 0 0 5 0 0 0 0 0 15
2040 0 0 0 0 0 200 5 0 0 GWW3 0 0 14
2041 0 0 0 0 0 500 0 0 0 0 0 0 14
2042 0 0 0 0 0 0 0 0 50 0 0 0 14
2043 0 0 0 0 0 0 5 0 0 0 0 0 14
Subtotal -841 -706 1,180 340 1,800 2,625 1,053 200 100 30 140 360
Total 6,281 Portfolio Cost: $9,795M

Long-Term Capacity Expansion Results
Page 44 2023 Integrated Resource Plan—Appendix C
Without Valmy (MW)
Year
Coal
Exits
Gas
Exits
New
Gas H2 Wind Solar 4-Hr 8-Hr 100-Hr Trans.
Demand
Response
Energy
Efficiency
Forecast
2024 -357 0 357 0 0 100 96 0 0 0 0 17
2025 0 0 0 0 0 200 227 0 0 0 0 18
2026 -134 0 0 0 0 100 5 0 0 Jul B2H 20 19
2027 0 0 0 0 400 375 5 0 0 0 40 20
2028 0 0 0 0 400 150 155 0 0 0 40 21
2029 0 0 170 0 400 200 5 0 0 GWW1 0 22
2030 -350 0 350 0 400 0 5 0 0 0 0 21
2031 0 0 0 0 200 400 5 0 0 GWW2 0 21
2032 0 0 0 0 0 400 205 0 0 0 0 20
2033 0 0 0 0 0 0 205 0 0 0 0 20
2034 0 0 0 0 0 0 55 0 0 0 20 19
2035 0 0 0 0 0 0 55 0 0 0 20 18
2036 0 0 0 0 0 0 5 100 0 0 0 17
2037 0 0 0 0 0 0 5 0 0 0 0 17
2038 0 -706 170 340 0 0 5 50 200 0 0 17
2039 0 0 0 0 0 0 5 50 0 0 0 15
2040 0 0 0 0 0 0 5 0 0 0 20 14
2041 0 0 0 0 0 500 0 0 0 GWW3 0 14
2042 0 0 0 0 0 400 5 0 0 0 0 14
2043 0 0 0 0 0 600 0 0 0 0 0 14
Subtotal -841 -706 1,046 340 1,800 3,425 1,053 200 200 160 360
Total 7,037 Portfolio Cost: $9,824M

Long-Term Capacity Expansion Results
2023 Integrated Resource Plan—Appendix C Page 45
November 2026 B2H Valmy 1 & 2 (MW)
Year
Coal
Exits
Gas
Exits
New
Gas H2 Wind Solar 4-Hr 8-Hr 100-Hr Trans.
Demand
Response
Energy
Efficiency
Forecast
2024 -357 0 357 0 0 100 96 0 0 0 0 17
2025 0 0 0 0 0 200 227 0 0 0 0 18
2026 -134 0 261 0 0 400 155 0 0 Nov B2H 40 19
2027 0 0 0 0 400 375 5 0 0 0 0 20
2028 0 0 0 0 100 150 5 0 0 0 0 21
2029 0 0 0 0 400 200 5 0 0 GWW1 0 22
2030 -350 0 350 0 400 0 5 0 0 0 0 21
2031 0 0 0 0 400 500 55 0 0 GWW2 0 21
2032 0 0 0 0 100 0 5 0 0 0 20 20
2033 0 0 0 0 0 0 55 0 0 0 40 20
2034 0 0 0 0 0 0 55 0 0 0 40 19
2035 0 0 0 0 0 0 55 0 0 0 0 18
2036 0 0 0 0 0 0 5 50 0 0 0 17
2037 0 0 170 0 0 0 5 50 0 0 0 17
2038 0 -706 0 340 0 0 55 0 200 0 20 17
2039 0 0 0 0 0 0 50 0 0 0 20 15
2040 0 0 0 0 0 0 5 50 0 0 0 14
2041 0 0 0 0 0 300 5 0 0 GWW3 0 14
2042 0 0 0 0 0 300 5 0 0 0 0 14
2043 0 0 0 0 0 300 55 0 0 0 0 14
Subtotal -841 -706 1,137 340 1,800 2,825 908 150 200 180 360
Total 6,353 Portfolio Cost: $9,767M

Long-Term Capacity Expansion Results
Page 46 2023 Integrated Resource Plan—Appendix C
November 2026 B2H Valmy 2 (MW)
Year
Coal
Exits
Gas
Exits
New
Gas H2 Wind Solar 4-Hr 8-Hr 100-Hr Trans.
Demand
Response
Energy
Efficiency
Forecast
Energy
Efficiency
Bundles
2024 -357 0 357 0 0 100 96 0 0 0 0 17 0
2025 0 0 0 0 0 200 227 0 0 0 0 18 0
2026 -134 0 134 0 0 400 205 100 0 Nov B2H 20 19 0
2027 0 0 0 0 400 375 5 0 0 0 0 20 0
2028 0 0 0 0 100 150 5 0 0 0 0 21 0
2029 0 0 0 0 400 100 5 0 0 GWW1 20 22 0
2030 -350 0 350 0 400 0 5 0 0 0 20 21 0
2031 0 0 0 0 400 0 5 0 0 GWW2 0 21 0
2032 0 0 0 0 100 0 5 0 50 0 0 20 0
2033 0 0 0 0 0 0 5 0 50 0 20 20 0
2034 0 0 0 0 0 200 5 0 50 0 0 19 0
2035 0 0 0 0 0 0 5 0 0 0 0 18 0
2036 0 0 0 0 0 0 5 0 0 0 40 17 0
2037 0 0 170 0 0 0 5 0 0 0 0 17 0
2038 0 -706 0 340 0 200 705 0 50 0 0 17 0
2039 0 0 0 0 0 200 55 0 0 0 20 15 0
2040 0 0 0 0 0 300 5 0 0 GWW3 20 14 0
2041 0 0 0 0 0 300 5 0 0 0 0 14 14
2042 0 0 0 0 0 400 55 0 0 0 0 14 0
2043 0 0 0 0 0 400 5 0 0 0 0 14 0
Subtotal -841 -706 1,010 340 1,800 3,325 1,413 100 200 160 360 14
Total 7,175 Portfolio Cost: $9,880M

Long-Term Capacity Expansion Results
2023 Integrated Resource Plan—Appendix C Page 47
November 2026 B2H Without Valmy (MW)
Year
Coal
Exits
Gas
Exits
New
Gas H2 Wind Solar 4-Hr 8-Hr 100-Hr Trans. Geo
Demand
Response
Energy
Efficiency
Forecast
Energy
Efficiency
Bundles
2024 -357 0 357 0 0 100 96 0 0 0 0 0 17 0
2025 0 0 0 0 0 200 227 0 0 0 0 0 18 0
2026 -134 0 0 0 0 400 100 300 0 Nov B2H 0 40 19 27
2027 0 0 0 0 400 375 5 0 0 0 0 0 20 0
2028 0 0 0 0 100 150 5 0 0 0 0 0 21 0
2029 0 0 0 0 400 200 5 0 0 GWW1 0 20 22 0
2030 -350 0 350 0 400 0 0 0 0 0 30 0 21 0
2031 0 0 0 0 400 100 5 0 0 GWW2 0 0 21 0
2032 0 0 0 0 100 400 205 0 0 0 0 0 20 0
2033 0 0 0 0 0 0 105 0 0 0 0 0 20 0
2034 0 0 0 0 0 0 55 0 0 0 0 40 19 0
2035 0 0 0 0 0 0 5 0 0 0 0 40 18 0
2036 0 0 0 0 0 0 5 0 0 0 0 40 17 0
2037 0 0 340 0 0 0 0 0 0 0 0 0 17 0
2038 0 -706 0 340 0 0 5 0 100 0 0 0 17 0
2039 0 0 0 0 0 0 0 0 50 0 0 0 15 0
2040 0 0 0 0 0 0 0 0 0 0 0 0 14 0
2041 0 0 0 0 0 600 0 0 0 GWW3 0 0 14 0
2042 0 0 0 0 0 300 5 0 0 0 0 0 14 0
2043 0 0 0 0 0 500 5 0 0 0 0 0 14 0
Subtotal -841 -706 1,046 340 1,800 3,325 833 300 150 30 180 360 27
Total 6,844 Portfolio Cost: $10,192M

Long-Term Capacity Expansion Results
Page 48 2023 Integrated Resource Plan—Appendix C
Without GWW Segments (MW)
Year
Coal
Exits
Gas
Exits
New
Gas H2 Wind Solar 4-Hr
Pumped
Storage 100-Hr Trans. Geo
Demand
Response
Energy
Efficiency
Forecast
2024 -357 0 357 0 0 100 96 0 0 0 0 0 17
2025 0 0 0 0 0 200 227 0 0 0 0 0 18
2026 -134 0 261 0 0 0 0 0 0 Jul B2H 0 0 19
2027 0 0 0 0 100 375 0 0 0 0 0 20 20
2028 0 0 0 0 0 150 0 0 0 0 0 40 21
2029 0 0 300 0 0 0 150 0 0 0 0 40 22
2030 -350 0 350 0 200 0 0 0 0 0 30 0 21
2031 0 0 0 0 100 0 0 0 0 0 0 0 21
2032 0 0 0 0 200 0 0 0 0 0 0 0 20
2033 0 0 170 0 100 0 5 0 0 0 0 0 20
2034 0 0 0 0 0 0 0 0 0 0 0 0 19
2035 0 0 0 0 200 0 0 0 0 0 0 0 18
2036 0 0 0 0 0 0 0 0 0 0 0 0 17
2037 0 0 0 170 0 0 0 0 0 0 0 0 17
2038 0 -706 300 0 0 0 0 0 0 0 30 0 17
2039 0 0 0 170 0 0 0 0 0 0 0 0 15
2040 0 0 0 0 0 0 0 0 0 0 0 0 14
2041 0 0 0 0 0 0 0 0 0 0 0 0 14
2042 0 0 0 0 0 0 0 0 50 0 0 0 14
2043 0 0 0 0 0 0 0 250 0 0 0 0 14
Subtotal -841 -706 1,737 340 900 825 478 250 50 60 100 360
Total 3,553 Portfolio Cost: $10,326M

Long-Term Capacity Expansion Results
2023 Integrated Resource Plan—Appendix C Page 49
GWW Segment 1 Only (MW)
Year
Coal
Exits
Gas
Exits
New
Gas H2 Wind Solar 4-Hr 8-Hr
Pumped
Storage 100-Hr Trans. Geo
Demand
Response
Energy
Efficiency
Forecast
2024 -357 0 357 0 0 100 96 0 0 0 0 0 0 17
2025 0 0 0 0 0 200 227 0 0 0 0 0 0 18
2026 -134 0 261 0 0 400 0 0 0 0 Jul B2H 0 0 19
2027 0 0 0 0 200 675 5 0 0 0 0 0 0 20
2028 0 0 0 0 0 150 5 0 0 0 0 0 0 21
2029 0 0 170 0 0 200 155 0 0 0 GWW1 0 20 22
2030 -350 0 350 0 0 0 5 0 0 0 0 0 20 21
2031 0 0 0 0 200 0 5 0 0 0 0 0 20 21
2032 0 0 0 0 400 0 5 0 0 0 0 30 20 20
2033 0 0 300 0 200 0 5 0 0 0 0 0 0 20
2034 0 0 0 0 0 0 5 0 0 0 0 0 0 19
2035 0 0 0 0 0 0 5 0 0 0 0 0 0 18
2036 0 0 0 0 0 0 5 0 0 0 0 0 0 17
2037 0 0 0 0 0 0 5 0 0 0 0 0 0 17
2038 0 -706 0 170 0 0 5 300 0 100 0 0 60 17
2039 0 0 0 170 0 0 0 0 0 50 0 0 0 15
2040 0 0 0 0 0 0 0 0 0 0 0 0 0 14
2041 0 0 0 0 0 0 0 0 0 50 0 0 0 14
2042 0 0 0 0 0 0 0 0 0 0 0 0 0 14
2043 0 0 0 0 0 0 0 0 250 0 0 0 0 14
Subtotal -841 -706 1,437 340 1,000 1,725 533 300 250 200 30 140 360
Total 4,768 Portfolio Cost: $10,263M

Long-Term Capacity Expansion Results
Page 50 2023 Integrated Resource Plan—Appendix C
GWW Segments 1 & 2 Only (MW)
Year
Coal
Exits
Gas
Exits
New
Gas H2 Wind Solar 4-Hr 100-Hr Trans. Geo
Demand
Response
Energy
Efficiency
Forecast
2024 -357 0 357 0 0 100 96 0 0 0 0 17
2025 0 0 0 0 0 200 227 0 0 0 0 18
2026 -134 0 261 0 0 100 5 0 Jul B2H 0 0 19
2027 0 0 0 0 400 375 5 0 0 0 0 20
2028 0 0 0 0 400 150 5 0 0 0 0 21
2029 0 0 0 0 400 0 105 0 GWW1 0 0 22
2030 -350 0 350 0 200 400 55 0 0 0 0 21
2031 0 0 0 0 300 0 5 0 GWW2 0 0 21
2032 0 0 0 0 100 300 305 0 0 0 0 20
2033 0 0 0 0 0 300 150 0 0 0 0 20
2034 0 0 0 0 0 0 5 0 0 0 0 19
2035 0 0 0 0 0 0 5 0 0 0 20 18
2036 0 0 0 0 0 0 5 0 0 0 40 17
2037 0 0 0 170 0 0 50 50 0 0 40 17
2038 0 -706 340 170 0 0 5 0 0 0 40 17
2039 0 0 0 0 0 0 0 50 0 0 0 15
2040 0 0 0 0 0 0 0 0 0 0 0 14
2041 0 0 0 0 0 0 0 50 0 0 0 14
2042 0 0 0 0 0 0 0 0 0 0 0 14
2043 0 0 0 0 0 0 5 0 0 30 0 14
Subtotal -841 -706 1,307 340 1,800 1,925 1,033 150 30 140 360
Total 5,538 Portfolio Cost: $9,759M

Long-Term Capacity Expansion Results
2023 Integrated Resource Plan—Appendix C Page 51
Scenarios and Sensitivities
High Gas High Carbon (MW)
Year Coal Exits Gas Exits New Gas Wind Solar 4-Hr 8-Hr Pumped Storage 100-Hr Trans. Geo Demand Response
Energy Efficiency Forecast
Energy Efficiency Bundles
2024 -357 0 357 0 100 96 0 0 0 0 0 0 17 0
2025 0 0 0 0 200 227 0 0 0 0 0 0 18 0
2026 -134 0 134 0 100 0 0 0 0 Jul B2H 0 0 19 0
2027 0 0 0 400 375 0 0 0 0 0 0 0 20 0
2028 0 0 0 400 150 5 0 0 0 0 0 0 21 9
2029 0 0 170 400 100 5 50 0 0 GWW1 0 0 22 9
2030 -350 -134 820 200 0 5 50 0 0 0 30 0 21 11
2031 0 0 0 400 600 5 200 250 0 GWW2 30 40 21 12
2032 0 0 0 0 100 5 0 0 0 0 0 0 20 0
2033 0 0 0 0 200 50 0 0 0 0 0 0 20 0
2034 0 0 0 0 0 0 0 0 0 0 0 0 19 0
2035 0 0 0 0 0 0 0 0 0 0 0 0 18 0
2036 0 0 0 0 0 0 0 0 0 0 0 20 17 0
2037 0 0 0 0 0 150 0 0 0 0 0 20 17 0
2038 0 -706 0 0 0 355 0 0 50 0 0 20 17 0
2039 0 0 0 0 0 5 0 0 0 0 0 40 15 0
2040 0 0 0 0 0 5 0 0 0 0 0 40 14 0
2041 0 0 0 0 0 0 0 0 50 0 0 0 14 0
2042 0 0 0 0 0 0 0 0 0 0 0 0 14 0
2043 0 0 0 0 600 0 0 0 0 GWW3 0 0 14 0
Subtotal -841 -840 1,480 1,800 2,525 913 300 250 100 60 180 360 41
Total 6,328 Portfolio Cost: $12,520M

Long-Term Capacity Expansion Results
Page 52 2023 Integrated Resource Plan—Appendix C
Low Gas Zero Carbon (MW)
Year
Coal
Exits
Gas
Exits
New
Gas H2 Wind Solar 4-Hr 8-Hr 100-Hr Trans.
Demand
Response
Energy
Efficiency
Forecast
2024 -357 0 357 0 0 100 96 0 0 0 0 17
2025 0 0 0 0 0 200 227 0 0 0 0 18
2026 -134 0 261 0 0 0 0 0 0 Jul B2H 0 19
2027 0 0 0 0 400 375 5 0 0 0 0 20
2028 0 0 0 0 200 150 5 0 0 0 0 21
2029 0 0 0 0 400 300 5 0 0 GWW1 0 22
2030 -350 0 350 0 400 200 155 0 0 0 0 21
2031 0 0 0 0 400 400 155 0 0 GWW2 0 21
2032 0 0 0 0 0 200 155 0 0 0 0 20
2033 0 0 0 0 0 0 55 0 0 0 0 20
2034 0 0 0 0 0 0 5 0 0 0 20 19
2035 0 0 0 0 0 0 5 0 0 0 40 18
2036 0 0 0 0 0 0 5 0 0 0 40 17
2037 0 0 340 0 0 0 5 0 0 0 0 17
2038 0 -706 0 340 0 0 5 0 100 0 0 17
2039 0 0 0 0 0 0 5 50 0 0 0 15
2040 0 0 0 0 0 0 5 0 0 0 40 14
2041 0 0 0 0 0 500 0 0 0 GWW3 0 14
2042 0 0 0 0 0 400 5 0 0 0 0 14
2043 0 0 0 0 0 600 5 0 0 0 0 14
Subtotal -841 -706 1,307 340 1,800 3,425 903 50 100 140 360
Total 6,878 Portfolio Cost: $8,594M

Long-Term Capacity Expansion Results
2023 Integrated Resource Plan—Appendix C Page 53
Constrained Storage (MW)
Year
Coal
Exits
Gas
Exits
New
Gas H2 Wind Solar 4-Hr 8-Hr 100-Hr Trans. Geo
Demand
Response
Energy
Efficiency
Forecast
Energy
Efficiency
Bundles
2024 -357 0 357 0 0 100 96 0 0 0 0 0 17 0
2025 0 0 0 0 0 200 227 0 0 0 0 0 18 0
2026 -134 0 134 0 0 0 0 0 0 Jul B2H 0 0 19 0
2027 0 0 0 0 400 475 5 0 0 0 0 20 20 0
2028 0 0 0 0 400 150 5 0 0 0 0 40 21 0
2029 0 0 0 0 400 400 55 0 0 GWW1 0 40 22 0
2030 -350 0 350 0 200 0 5 200 0 0 0 0 21 0
2031 0 -134 0 0 400 500 5 100 0 GWW2 30 20 21 0
2032 0 0 0 0 0 100 5 0 0 0 30 20 20 0
2033 0 0 0 0 0 0 5 100 0 0 30 0 20 0
2034 0 0 0 0 0 0 5 0 0 0 30 0 19 0
2035 0 0 0 0 0 0 5 50 0 0 0 0 18 0
2036 0 0 0 0 0 0 5 50 0 0 0 0 17 0
2037 0 0 170 0 0 0 5 0 50 0 0 0 17 0
2038 0 -706 170 340 0 0 5 0 50 0 0 0 17 0
2039 0 0 0 0 0 0 5 50 0 0 0 0 15 0
2040 0 0 0 0 0 0 5 0 50 0 0 0 14 0
2041 0 0 0 0 0 0 5 0 0 0 0 0 14 0
2042 0 0 0 0 0 200 5 0 0 GWW3 0 0 14 0
2043 0 0 0 0 0 300 5 0 0 0 0 20 14 14
Subtotal -841 -840 1,180 340 1,800 2,425 458 550 150 120 160 360 14
Total 5,876 Portfolio Cost: $10,007M

Long-Term Capacity Expansion Results
Page 54 2023 Integrated Resource Plan—Appendix C
100% Clean by 2045 (MW)
Year
Coal
Exits
Gas
Exits
New
Gas H2 Wind Solar 4-Hr 8-Hr 100-Hr Trans. Geo
Demand
Response
Energy
Efficiency
Forecast
2024 -357 0 357 0 0 100 96 0 0 0 0 0 17
2025 0 0 0 0 0 200 227 0 0 0 0 0 18
2026 -134 0 134 0 0 100 0 0 0 Jul B2H 0 0 19
2027 0 0 0 0 400 375 5 0 0 0 0 0 20
2028 0 0 0 0 400 150 5 0 0 0 0 20 21
2029 -175 0 340 0 400 0 305 0 0 GWW1 0 40 22
2030 -174 0 0 0 400 200 205 0 50 0 30 40 21
2031 0 0 0 0 200 100 5 0 0 GWW2 0 20 21
2032 0 0 0 0 0 300 5 0 0 0 0 0 20
2033 0 0 0 0 0 400 5 50 0 0 0 0 20
2034 0 0 0 0 0 0 5 0 100 0 0 0 19
2035 0 -134 0 0 0 0 5 0 0 0 0 0 18
2036 0 0 0 0 0 0 5 0 0 0 0 40 17
2037 0 0 0 170 0 0 5 0 0 0 0 0 17
2038 0 -357 0 170 0 0 5 100 50 0 0 0 17
2039 0 0 0 0 0 0 0 50 0 0 0 0 15
2040 0 0 0 0 0 200 55 0 0 GWW3 0 0 14
2041 0 0 0 0 0 100 55 0 0 0 0 0 14
2042 0 0 0 0 0 200 0 50 0 0 0 0 14
2043 0 0 0 0 0 300 0 0 0 0 0 0 14
Subtotal -841 -491 831 340 1,800 2,725 993 250 200 30 160 360
Total 6,357 Portfolio Cost: $9,808M

Long-Term Capacity Expansion Results
2023 Integrated Resource Plan—Appendix C Page 55
Additional Large Load 100 MW (MW)
Year
Coal
Exits Gas
New
Gas H2 Wind Solar 4-Hr 8-Hr 100-Hr Trans. Geo
Demand
Response
Energy
Efficiency
Forecast
2024 -357 0 357 0 0 100 96 0 0 0 0 0 17
2025 0 0 0 0 0 200 227 0 0 0 0 0 18
2026 -134 0 261 0 0 0 5 0 0 Jul B2H 0 0 19
2027 0 0 0 0 400 475 5 0 0 0 0 0 20
2028 0 0 0 0 400 150 5 0 0 0 0 40 21
2029 0 0 0 0 400 0 55 50 0 GWW1 0 40 22
2030 -350 0 350 0 300 300 105 0 0 0 30 0 21
2031 0 0 0 0 300 0 5 0 0 GWW2 0 0 21
2032 0 0 0 0 0 600 155 0 0 0 0 0 20
2033 0 0 0 0 0 0 205 0 0 0 0 20 20
2034 0 0 0 0 0 100 155 0 0 0 0 0 19
2035 0 0 0 0 0 0 105 0 0 0 0 0 18
2036 0 0 0 0 0 0 5 0 0 0 0 20 17
2037 0 0 0 170 0 0 5 0 0 0 0 0 17
2038 0 -706 170 170 0 0 5 100 200 0 0 40 17
2039 0 0 0 0 0 0 5 50 0 0 0 0 15
2040 0 0 0 0 0 500 5 0 0 GWW3 0 0 14
2041 0 0 0 0 0 200 5 0 0 0 0 0 14
2042 0 0 0 0 0 200 55 0 0 0 0 0 14
2043 0 0 0 0 0 500 5 0 0 0 0 0 14
Subtotal -841 -706 1,137 340 1,800 3,325 1,213 200 200 30 160 360
Total 7,218 Portfolio Cost: $10,236M

Long-Term Capacity Expansion Results
Page 56 2023 Integrated Resource Plan—Appendix C
Additional Large Load 200 MW (MW)
Year
Coal
Exits
Gas
Exits
New
Gas H2 Wind Solar 4-Hr 8-Hr 100-Hr Trans. Geo
Demand
Response
Energy
Efficiency
Forecast
2024 -357 0 357 0 0 100 96 0 0 0 0 0 17
2025 0 0 0 0 0 200 227 0 0 0 0 0 18
2026 -134 0 261 0 0 0 5 0 0 Jul B2H 0 20 19
2027 0 0 0 0 400 475 5 0 0 0 0 20 20
2028 0 0 0 0 400 150 5 100 0 0 0 20 21
2029 0 0 0 0 400 300 255 0 0 GWW1 0 40 22
2030 -350 0 350 0 300 0 205 0 0 0 30 0 21
2031 0 0 0 0 300 500 5 0 0 GWW2 30 0 21
2032 0 0 0 0 0 200 5 0 0 0 30 40 20
2033 0 0 0 0 0 0 5 100 0 0 0 20 20
2034 0 0 0 0 0 0 5 50 0 0 0 20 19
2035 0 0 0 0 0 0 0 0 50 0 0 0 18
2036 0 0 0 0 0 0 0 0 0 0 0 0 17
2037 0 0 170 0 0 0 5 0 0 0 0 0 17
2038 0 -706 170 340 0 0 5 0 150 0 0 0 17
2039 0 0 0 0 0 0 5 0 0 0 0 0 15
2040 0 0 0 0 0 100 5 0 0 GWW3 0 0 14
2041 0 0 0 0 0 400 5 0 0 0 0 0 14
2042 0 0 0 0 0 100 55 0 0 0 0 0 14
2043 0 0 0 0 0 200 100 0 0 0 0 0 14
Subtotal -841 -706 1,307 340 1,800 2,725 998 250 200 90 180 360
Total 6,703 Portfolio Cost: $10,747

Long-Term Capacity Expansion Results
2023 Integrated Resource Plan—Appendix C Page 57
100% Clean by 2035 (MW)
Year
Coal
Exits
Gas
Exits
New
Gas H2 Wind Solar 4-Hr 8-Hr
Pumped
Storage 100-Hr Trans. Geo Biomass
Demand
Response
Energy
Efficiency
Forecast
Energy
Efficiency
Bundles
2024 -357 0 357 0 0 100 96 0 0 0 0 0 0 0 17 0
2025 0 0 0 0 0 200 227 0 0 0 0 0 0 0 18 0
2026 -134 0 134 0 0 100 105 0 0 0 Jul B2H 0 0 0 19 0
2027 0 0 0 0 400 375 5 0 0 0 0 0 0 0 20 0
2028 0 0 0 0 400 150 5 0 0 0 0 0 0 20 21 0
2029 -175 0 0 0 400 0 5 250 0 0 GWW1 0 0 40 22 0
2030 -174 0 0 0 400 200 105 0 0 50 0 30 30 20 21 0
2031 0 0 0 0 200 500 5 50 0 0 GWW2 30 0 0 21 0
2032 0 0 0 0 0 200 105 50 0 50 0 30 30 0 20 0
2033 0 0 0 0 0 100 205 0 0 0 0 30 30 0 20 0
2034 0 0 0 0 0 0 55 100 0 50 0 0 30 40 19 0
2035 0 -1,260 0 0 0 0 5 150 500 50 0 30 30 60 18 43
2036 0 0 0 0 0 0 55 0 0 0 0 0 0 0 17 0
2037 0 0 0 170 0 0 0 0 0 0 0 0 0 0 17 0
2038 0 0 0 170 0 0 0 0 0 0 0 0 0 0 17 0
2039 0 0 0 0 0 0 5 0 0 0 0 0 0 0 15 0
2040 0 0 0 0 0 100 5 0 0 0 GWW3 0 0 0 14 0
2041 0 0 0 0 0 0 5 0 0 0 0 0 0 0 14 0
2042 0 0 0 0 0 100 5 0 0 0 0 0 0 0 14 42
2043 0 0 0 0 0 0 55 250 0 0 0 0 0 0 14 41
Subtotal -841 -1,260 491 340 1,800 2,125 1,053 850 500 200 150 150 180 360 127
Total 7,168 Portfolio Cost: $11,351M

Long-Term Capacity Expansion Results
Page 58 2023 Integrated Resource Plan—Appendix C
New Forecasted PURPA (MW)
Year
Coal
Exits
Gas
Exits
New
Gas Wind Solar 4-Hr 8-Hr 100-Hr Trans. Hydro
Demand
Response
Energy
Efficiency
Forecast
2024 -357 0 357 0 100 96 0 0 0 0 0 17
2025 0 0 0 0 200 227 0 0 0 0 0 18
2026 -134 0 261 0 100 0 0 0 Jul B2H 0 0 19
2027 0 0 0 400 775 5 0 0 0 0 0 20
2028 0 0 0 23 182 5 0 0 0 2 0 21
2029 0 0 0 423 32 5 0 0 GWW1 2 0 22
2030 -350 0 350 423 232 5 0 0 0 2 0 21
2031 0 0 0 423 32 55 100 0 GWW2 2 0 21
2032 0 0 0 223 432 5 0 0 0 2 0 20
2033 0 0 0 23 32 5 0 0 0 2 0 20
2034 0 0 0 23 32 55 0 0 0 2 0 19
2035 0 0 0 23 32 5 0 0 0 2 20 18
2036 0 0 0 23 32 5 0 0 0 2 40 17
2037 0 0 0 23 32 5 0 0 0 2 40 17
2038 0 -706 0 23 32 505 200 150 0 2 40 17
2039 0 0 0 23 32 5 0 0 0 2 20 15
2040 0 0 0 23 32 0 0 0 0 2 0 14
2041 0 0 0 23 32 5 0 0 0 2 0 14
2042 0 0 0 23 32 5 0 0 0 2 0 14
2043 0 0 0 23 132 5 0 0 GWW3 2 0 14
Subtotal -841 -706 967 2,168 2,537 1,003 300 150 32 160 360
Total 6,130 Portfolio Cost: $10,720M 0

Long-Term Capacity Expansion Results
2023 Integrated Resource Plan—Appendix C Page 59
Extreme Weather (MW)
Year
Coal
Exits
Gas
Exits
New
Gas H2 Wind Solar 4-Hr 8-Hr 100-Hr Trans.
Demand
Response
Energy
Efficiency
Forecast
2024 -357 0 357 0 0 100 96 0 0 0 0 17
2025 0 0 0 0 0 200 227 0 0 0 0 18
2026 -134 0 261 0 0 100 5 100 0 Jul B2H 20 19
2027 0 0 0 0 400 375 5 0 0 0 40 20
2028 0 0 0 0 400 150 55 50 0 0 20 21
2029 0 0 170 0 400 0 0 0 0 GWW1 0 22
2030 -350 0 350 0 300 300 5 0 0 0 0 21
2031 0 0 0 0 300 0 5 0 0 GWW2 0 21
2032 0 0 0 0 0 300 5 0 0 0 0 20
2033 0 0 0 0 0 400 205 0 0 0 0 20
2034 0 0 0 0 0 0 5 0 0 0 0 19
2035 0 0 0 0 0 0 5 0 0 0 0 18
2036 0 0 0 0 0 0 5 0 0 0 20 17
2037 0 0 0 0 0 0 105 50 0 0 20 17
2038 0 -706 170 340 0 0 5 0 200 0 20 17
2039 0 0 0 0 0 0 5 0 0 0 0 15
2040 0 0 0 0 0 0 55 0 0 0 0 14
2041 0 0 0 0 0 0 5 0 0 0 40 14
2042 0 0 0 0 0 200 55 0 0 GWW3 0 14
2043 0 0 0 0 0 500 5 100 0 0 0 14
Subtotal -841 -706 1,307 340 1,800 2,625 858 300 200 180 360
Total 6,423 Portfolio Cost: $10,211M

Long-Term Capacity Expansion Results
Page 60 2023 Integrated Resource Plan—Appendix C
Rapid Electrification Air-Source Heat Pump (MW)
Year
Coal
Exits
Gas
Exits
New
Gas H2 Wind Solar 4-Hr 8-Hr 100-Hr Trans. Geo
Demand
Response
Energy
Efficiency
Forecast
2024 -357 0 357 0 0 100 96 0 0 0 0 0 17
2025 0 0 0 0 0 200 227 0 0 0 0 0 18
2026 -134 0 261 0 0 100 5 0 0 Jul B2H 0 0 19
2027 0 0 0 0 400 375 5 50 0 0 0 20 20
2028 0 0 0 0 400 150 5 200 0 0 0 40 21
2029 0 0 300 0 400 300 5 0 0 GWW1 0 0 22
2030 -350 0 350 0 300 0 5 0 0 0 30 0 21
2031 0 0 170 0 300 400 5 0 0 GWW2 0 0 21
2032 0 0 0 0 0 300 355 0 0 0 0 0 20
2033 0 0 0 0 0 0 705 0 0 0 0 0 20
2034 0 0 340 0 0 0 5 0 0 0 0 20 19
2035 0 0 0 0 0 0 5 0 50 0 0 20 18
2036 0 0 0 0 0 0 5 0 0 0 0 0 17
2037 0 0 340 0 0 0 5 0 0 0 0 0 17
2038 0 -706 170 340 0 0 5 0 150 0 30 20 17
2039 0 0 0 0 0 0 5 0 150 0 0 20 15
2040 0 0 0 0 0 400 0 0 200 GWW3 0 0 14
2041 0 0 0 0 0 400 0 0 0 0 0 0 14
2042 0 0 0 0 0 300 5 0 0 0 0 0 14
2043 0 0 0 0 0 400 5 100 50 0 0 20 14
Subtotal -841 -706 2,287 340 1,800 3,425 1,453 350 600 60 160 360
Total 9,288 Portfolio Cost: $12,271M

Long-Term Capacity Expansion Results
2023 Integrated Resource Plan—Appendix C Page 61
Rapid Electrification Ground-Source Heat Pump (MW)
Year
Coal
Exits
Gas
Exits
New
Gas H2 Wind Solar 4-Hr 8-Hr 100-Hr Trans.
Demand
Response
Energy
Efficiency
Forecast
2024 -357 0 357 0 0 100 96 0 0 0 0 17
2025 0 0 0 0 0 200 227 0 0 0 0 18
2026 -134 0 261 0 0 0 5 0 0 Jul B2H 0 19
2027 0 0 0 0 400 475 5 0 0 0 0 20
2028 0 0 0 0 400 150 5 0 0 0 0 21
2029 0 0 300 0 400 0 5 0 0 GWW1 0 22
2030 -350 0 350 0 200 400 5 0 0 0 0 21
2031 0 0 0 0 400 0 5 0 0 GWW2 0 21
2032 0 0 170 0 0 300 5 50 0 0 20 20
2033 0 0 0 0 0 300 5 250 0 0 20 20
2034 0 0 0 0 0 0 5 0 0 0 20 19
2035 0 0 0 0 0 0 5 0 0 0 0 18
2036 0 0 170 0 0 0 5 0 0 0 0 17
2037 0 0 340 0 0 0 5 0 0 0 20 17
2038 0 -706 340 170 0 0 5 0 0 0 20 17
2039 0 0 0 0 0 0 5 0 0 0 40 15
2040 0 0 0 170 0 0 5 0 0 0 0 14
2041 0 0 0 0 0 0 5 0 0 0 20 14
2042 0 0 0 0 0 100 5 0 0 GWW3 20 14
2043 0 0 0 0 0 100 5 0 50 0 0 14
Subtotal -841 -706 2,287 340 1,800 2,125 413 300 50 180 360
Total 6,308 Portfolio Cost: $11,175M

Long-Term Capacity Expansion Results
Page 62 2023 Integrated Resource Plan—Appendix C
Load Flattening (MW)
Year
Coal
Exits
Gas
Exits
New
Gas H2 Wind Solar 4-Hr 8-Hr 100-Hr Trans. Geo
Demand
Response
Energy
Efficiency
Forecast
Energy
Efficiency
Bundles
2024 -357 0 357 0 0 100 96 0 0 0 0 0 17 0
2025 0 0 0 0 0 200 227 0 0 0 0 0 18 0
2026 -134 0 261 0 0 100 5 0 0 Jul B2H 0 20 19 0
2027 0 0 0 0 400 375 5 0 0 0 0 20 20 0
2028 0 0 0 0 400 150 55 50 0 0 0 40 21 0
2029 0 0 0 0 400 0 255 0 0 GWW1 0 0 22 0
2030 -350 0 350 0 300 300 205 0 0 0 30 0 21 0
2031 0 0 0 0 300 600 205 0 0 GWW2 30 0 21 0
2032 0 0 0 0 0 100 55 0 0 0 0 20 20 0
2033 0 0 0 0 0 0 5 0 0 0 0 20 20 0
2034 0 0 0 0 0 0 5 0 50 0 0 0 19 0
2035 0 0 0 0 0 0 5 0 0 0 0 20 18 0
2036 0 0 0 0 0 0 5 0 0 0 0 20 17 0
2037 0 0 170 0 0 0 5 0 0 0 0 0 17 0
2038 0 -706 170 340 0 0 5 0 150 0 0 0 17 0
2039 0 0 0 0 0 0 5 0 0 0 0 0 15 0
2040 0 0 0 0 0 400 5 0 0 GWW3 0 0 14 0
2041 0 0 0 0 0 200 5 0 0 0 0 0 14 0
2042 0 0 0 0 0 500 5 0 0 0 0 0 14 0
2043 0 0 0 0 0 300 5 0 0 0 0 20 14 14
Subtotal -841 -706 1,307 340 1,800 3,325 1,163 50 200 60 180 360 14
Total 7,252 Portfolio Cost: $10,663M

Long-Term Capacity Expansion Results
2023 Integrated Resource Plan—Appendix C Page 63
Validation and Verification
Valmy 1 & 2 Early Exit (MW)
Year Coal Exits Gas Exits New Gas H2 Wind Solar 4-Hr 8-Hr 100-Hr Trans. Geo Demand Response
Energy Efficiency Forecast
2024 -357 0 357 0 0 100 96 0 0 0 0 0 17
2025 0 0 0 0 0 200 227 0 0 0 0 0 18
2026 -134 0 261 0 0 100 0 0 0 Jul B2H 0 0 19
2027 0 0 0 0 400 375 5 0 0 0 0 0 20
2028 0 0 0 0 400 150 5 0 0 0 0 0 21
2029 0 0 0 0 400 0 5 0 0 GWW1 0 20 22
2030 -350 0 350 0 100 500 155 0 0 0 30 0 21
2031 0 -127 0 0 400 400 155 0 0 GWW2 0 0 21
2032 0 -134 170 0 100 100 205 0 0 0 0 0 20
2033 0 0 0 0 0 0 105 0 0 0 0 20 20
2034 0 0 0 0 0 0 5 0 0 0 0 40 19
2035 0 0 0 0 0 0 5 0 0 0 0 40 18
2036 0 0 0 0 0 0 5 0 0 0 0 40 17
2037 0 0 0 0 0 0 55 50 0 0 0 0 17
2038 0 -706 170 340 0 0 5 50 200 0 0 0 17
2039 0 0 0 0 0 0 5 50 0 0 0 0 15
2040 0 0 0 0 0 400 5 0 0 GWW3 0 0 14
2041 0 0 0 0 0 200 5 0 0 0 0 0 14
2042 0 0 0 0 0 200 55 0 0 0 0 0 14
2043 0 0 0 0 0 600 0 0 0 0 0 0 14
Subtotal -841 -967 1,307 340 1,800 3,325 1,103 150 200 30 160 360
Total 6,967 Portfolio Cost: $9,803M

Long-Term Capacity Expansion Results
Page 64 2023 Integrated Resource Plan—Appendix C
Valmy 2 Early Exit (MW)
Year
Coal
Exits
Gas
Exits
New
Gas H2 Wind Solar 4-Hr 8-Hr 100-Hr Trans. Geo
Demand
Response
Energy
Efficiency
Forecast
2024 -357 0 357 0 0 100 96 0 0 0 0 0 17
2025 0 0 0 0 0 200 227 0 0 0 0 0 18
2026 -134 0 134 0 0 100 5 0 0 Jul B2H 0 40 19
2027 0 0 0 0 400 375 5 0 0 0 0 0 20
2028 0 0 0 0 400 150 5 0 0 0 0 0 21
2029 0 -134 170 0 400 0 5 0 0 GWW1 0 20 22
2030 -350 0 350 0 400 0 5 0 50 0 0 20 21
2031 0 0 0 0 100 0 5 0 0 GWW2 0 20 21
2032 0 0 0 0 0 0 5 100 0 0 30 0 20
2033 0 0 0 0 0 0 5 100 0 0 0 0 20
2034 0 0 0 0 100 600 205 0 0 0 0 20 19
2035 0 0 0 0 0 400 205 0 0 0 0 20 18
2036 0 0 170 0 0 0 150 0 0 0 0 0 17
2037 0 0 0 170 0 0 5 0 0 0 0 0 17
2038 0 -706 0 170 0 0 5 0 100 0 0 40 17
2039 0 0 0 0 0 0 5 0 50 0 0 0 15
2040 0 0 0 0 0 200 5 0 0 GWW3 0 0 14
2041 0 0 0 0 0 100 5 0 0 0 0 0 14
2042 0 0 0 0 0 200 55 0 0 0 0 0 14
2043 0 0 0 0 0 300 55 0 0 0 0 0 14
Subtotal -841 -840 1,180 340 1,800 2,725 1,058 200 200 30 180 360
Total 6,392 Portfolio Cost: $9,878M

Long-Term Capacity Expansion Results
2023 Integrated Resource Plan—Appendix C Page 65
November 2026 B2H Valmy 1 & 2 Early Exit (MW)
Year
Coal
Exits
Gas
Exits
New
Gas H2 Wind Solar 4-Hr 8-Hr 100-Hr Trans. Geo
Demand
Response
Energy
Efficiency
Forecast
2024 -357 0 357 0 0 100 96 0 0 0 0 0 17
2025 0 0 0 0 0 200 227 0 0 0 0 0 18
2026 -134 0 261 0 0 200 205 0 0 Nov B2H 0 20 19
2027 0 0 0 0 400 375 5 0 0 0 0 0 20
2028 0 0 0 0 300 150 5 0 0 0 0 0 21
2029 0 -127 0 0 400 200 5 0 0 GWW1 0 40 22
2030 -350 -134 520 0 400 0 55 0 0 0 0 0 21
2031 0 0 0 0 300 0 155 0 0 GWW2 0 0 21
2032 0 0 0 0 0 600 5 0 0 0 0 0 20
2033 0 0 0 0 0 100 5 50 0 0 0 0 20
2034 0 0 0 0 0 0 5 50 0 0 0 20 19
2035 0 0 0 0 0 0 55 0 0 0 0 0 18
2036 0 0 0 0 0 0 55 0 0 0 0 0 17
2037 0 0 0 0 0 0 5 50 0 0 0 40 17
2038 0 -706 170 340 0 0 5 50 200 0 0 20 17
2039 0 0 0 0 0 0 5 0 0 0 0 20 15
2040 0 0 0 0 0 300 0 50 0 GWW3 0 0 14
2041 0 0 0 0 0 200 0 0 0 0 0 0 14
2042 0 0 0 0 0 300 5 0 0 0 0 0 14
2043 0 0 0 0 0 600 0 0 0 0 0 0 14
Subtotal -841 -967 1,307 340 1,800 3,325 898 250 200 0 160 360
Total 6,832 Portfolio Cost: $9,880M

Long-Term Capacity Expansion Results
Page 66 2023 Integrated Resource Plan—Appendix C
November 2026 B2H Valmy 2 Early Exit (MW)
Year
Coal
Exits
Gas
Exits
New
Gas H2 Wind Solar 4-Hr 8-Hr 100-Hr Trans.
Demand
Response
Energy
Efficiency
Forecast
2024 -357 0 357 0 0 100 96 0 0 0 0 17
2025 0 0 0 0 0 200 227 0 0 0 0 18
2026 -134 0 134 0 0 400 205 100 0 Nov B2H 20 19
2027 0 0 0 0 400 375 0 0 0 0 0 20
2028 0 0 0 0 100 150 5 0 0 0 0 21
2029 0 -134 170 0 400 200 5 0 0 GWW1 0 22
2030 -350 0 350 0 400 0 5 0 0 0 0 21
2031 0 0 0 0 400 100 5 0 0 GWW2 0 21
2032 0 0 0 0 100 400 0 0 50 0 0 20
2033 0 0 0 0 0 0 5 0 50 0 0 20
2034 0 0 0 0 0 0 5 0 0 0 0 19
2035 0 0 0 0 0 0 55 0 0 0 0 18
2036 0 0 0 0 0 0 55 0 0 0 0 17
2037 0 0 170 0 0 0 105 0 0 0 20 17
2038 0 -706 0 340 0 0 405 0 100 0 40 17
2039 0 0 0 0 0 0 5 0 0 0 40 15
2040 0 0 0 0 0 500 0 0 0 GWW3 0 14
2041 0 0 0 0 0 400 5 0 0 0 0 14
2042 0 0 0 0 0 200 55 0 0 0 0 14
2043 0 0 0 0 0 400 5 0 0 0 20 14
Subtotal -841 -840 1,180 340 1,800 3,425 1,248 100 200 140 360
Total 7,112 Portfolio Cost: $9,956M

Long-Term Capacity Expansion Results
2023 Integrated Resource Plan—Appendix C Page 67
Without Bridger 3 & 4 (MW)
Year
Coal
Exits
Gas
Exits
New
Gas H2 Wind Solar 4-Hr 8-Hr 100-Hr Trans. Geo
Demand
Response
Energy
Efficiency
Forecast
2024 -357 0 357 0 0 100 96 0 0 0 0 0 17
2025 0 0 0 0 0 200 227 0 0 0 0 0 18
2026 -134 0 261 0 0 0 5 0 0 Jul B2H 0 0 19
2027 0 0 0 0 400 575 5 0 0 0 0 20 20
2028 0 0 0 0 300 150 5 0 0 0 0 20 21
2029 0 0 170 0 400 0 5 0 0 GWW1 0 20 22
2030 -350 0 0 0 400 200 105 0 50 0 30 40 21
2031 0 0 0 0 300 100 155 0 0 GWW2 0 0 21
2032 0 0 0 0 0 600 205 0 0 0 0 0 20
2033 0 0 0 0 0 0 155 0 0 0 0 0 20
2034 0 0 0 0 0 0 155 0 0 0 0 0 19
2035 0 0 0 0 0 0 5 0 0 0 0 0 18
2036 0 0 0 0 0 0 5 0 0 0 0 40 17
2037 0 0 0 0 0 0 5 0 50 0 0 0 17
2038 0 -357 170 170 0 0 5 150 0 0 0 0 17
2039 0 0 0 0 0 0 5 0 0 0 0 0 15
2040 0 0 0 0 0 400 5 0 0 GWW3 0 0 14
2041 0 0 0 0 0 200 5 0 0 0 0 20 14
2042 0 0 0 0 0 500 5 0 0 0 0 0 14
2043 0 0 0 0 0 400 5 0 0 0 0 0 14
Subtotal -841 -357 958 170 1,800 3,425 1,163 150 100 30 160 360
Total 7,468 Portfolio Cost: $9,945M

Long-Term Capacity Expansion Results
Page 68 2023 Integrated Resource Plan—Appendix C
Nuclear (MW)
Year
Coal
Exits
Gas
Exits
New
Gas H2 Wind Solar 4-Hr 8-Hr 100-Hr Trans. Nuclear
Demand
Response
Energy
Efficiency
Forecast
2024 -357 0 357 0 0 100 96 0 0 0 0 0 17
2025 0 0 0 0 0 200 227 0 0 0 0 0 18
2026 -134 0 261 0 0 300 5 0 0 Jul B2H 0 0 19
2027 0 0 0 0 400 375 5 0 0 0 0 0 20
2028 0 0 0 0 200 150 5 0 0 0 0 20 21
2029 0 0 0 0 400 200 5 0 0 GWW1 0 20 22
2030 -350 0 350 0 400 0 5 0 0 0 0 0 21
2031 0 0 0 0 400 200 5 0 0 GWW2 0 0 21
2032 0 0 0 0 0 0 205 0 0 0 0 0 20
2033 0 0 0 0 0 400 205 0 0 0 0 0 20
2034 0 0 0 0 0 0 155 0 0 0 0 0 19
2035 0 0 0 0 0 0 5 0 0 0 0 0 18
2036 0 0 0 0 0 0 0 0 0 0 0 20 17
2037 0 0 170 0 0 0 5 0 0 0 100 0 17
2038 0 -706 0 340 0 0 5 200 50 0 0 40 17
2039 0 0 0 0 0 0 5 0 0 0 0 40 15
2040 0 0 0 0 0 200 5 0 0 GWW3 0 20 14
2041 0 0 0 0 0 300 55 0 0 0 0 0 14
2042 0 0 0 0 0 200 5 0 0 0 0 0 14
2043 0 0 0 0 0 400 50 0 0 0 0 0 14
Subtotal -841 -706 1,137 340 1,800 3,025 1,053 200 50 100 160 360
Total 6,678 Portfolio Cost: $10,013M

Long-Term Capacity Expansion Results
2023 Integrated Resource Plan—Appendix C Page 69
Wind +30% Cost (MW)
Year
Coal
Exits
Gas
Exits
New
Gas H2 Wind Solar 4-Hr 8-Hr 100-Hr Trans.
Demand
Response
Energy
Efficiency
Forecast
2024 -357 0 357 0 0 100 96 0 0 0 0 17
2025 0 0 0 0 0 200 227 0 0 0 0 18
2026 -134 0 261 0 0 0 5 0 0 Jul B2H 0 19
2027 0 0 0 0 400 475 5 0 0 0 0 20
2028 0 0 0 0 200 350 5 0 0 0 0 21
2029 0 0 0 0 400 400 55 0 0 GWW1 20 22
2030 -350 0 350 0 100 100 155 0 0 0 0 21
2031 0 0 0 0 200 600 155 0 0 GWW2 0 21
2032 0 0 0 0 100 100 205 0 0 0 0 20
2033 0 0 0 0 0 0 155 0 0 0 0 20
2034 0 0 0 0 0 0 155 0 0 0 0 19
2035 0 0 0 0 0 0 5 0 0 0 0 18
2036 0 0 0 0 0 0 5 0 0 0 20 17
2037 0 0 340 0 0 0 5 0 0 0 0 17
2038 0 -706 0 340 0 0 5 100 50 0 20 17
2039 0 0 0 0 0 0 5 0 0 0 20 15
2040 0 0 0 0 0 300 5 0 0 GWW3 20 14
2041 0 0 0 0 100 0 0 0 0 0 0 14
2042 0 0 0 0 100 0 5 0 0 0 0 14
2043 0 0 0 0 0 600 0 0 0 0 0 14
Subtotal -841 -706 1,307 340 1,600 3,225 1,253 100 50 100 360
Total 6,788 Portfolio Cost: $10,397M

Long-Term Capacity Expansion Results
Page 70 2023 Integrated Resource Plan—Appendix C
Energy Efficiency (MW)
Year
Coal
Exits
Gas
Exits
New
Gas H2 Wind Solar 4-Hr 8-Hr 100-Hr Trans.
Demand
Response
Energy
Efficiency
Forecast
Energy
Efficiency
Bundles
2024 -357 0 357 0 0 100 96 0 0 0 0 17 0
2025 0 0 0 0 0 200 227 0 0 0 0 18 0
2026 -134 0 261 0 0 0 5 0 0 Jul B2H 0 19 27
2027 0 0 0 0 400 675 5 0 0 0 0 20 33
2028 0 0 0 0 200 150 5 0 0 0 20 21 38
2029 0 0 0 0 400 200 5 0 0 GWW1 20 22 0
2030 -350 0 350 0 400 0 5 0 0 0 0 21 0
2031 0 0 0 0 400 100 205 0 0 GWW2 0 21 0
2032 0 0 0 0 0 100 205 0 0 0 0 20 0
2033 0 0 0 0 0 400 205 0 0 0 0 20 0
2034 0 0 0 0 0 0 5 0 0 0 0 19 0
2035 0 0 0 0 0 0 0 0 0 0 0 18 0
2036 0 0 0 0 0 0 5 0 0 0 20 17 0
2037 0 0 0 0 0 0 55 0 0 0 0 17 0
2038 0 -706 0 340 0 0 5 50 200 0 40 17 0
2039 0 0 0 0 0 0 5 0 0 0 40 15 0
2040 0 0 0 0 0 300 5 0 0 GWW3 20 14 0
2041 0 0 0 0 0 100 5 0 50 0 0 14 0
2042 0 0 0 0 0 100 5 0 0 0 0 14 0
2043 0 0 0 0 0 200 5 0 0 0 0 14 0
Subtotal -841 -706 967 340 1,800 2,625 1,048 50 250 160 360 98
Total 6,151 Portfolio Cost: $10,042M

Long-Term Capacity Expansion Results
2023 Integrated Resource Plan—Appendix C Page 71
Demand Response (MW)
Year
Coal
Exits
Gas
Exits
New
Gas H2 Wind Solar 4-Hr 8-Hr 100-Hr Trans.
Demand
Response
Energy
Efficiency
Forecast
2024 -357 0 357 0 0 100 96 0 0 0 0 17
2025 0 0 0 0 0 200 227 0 0 0 0 18
2026 -134 0 261 0 0 300 0 0 0 Jul B2H 40 19
2027 0 0 0 0 400 375 5 0 0 0 0 20
2028 0 0 0 0 200 150 5 0 0 0 20 21
2029 0 0 0 0 400 0 5 0 0 GWW1 0 22
2030 -350 0 350 0 400 200 105 0 0 0 0 21
2031 0 0 0 0 400 400 205 0 0 GWW2 0 21
2032 0 0 0 0 0 0 205 0 0 0 0 20
2033 0 0 0 0 0 200 155 0 0 0 0 20
2034 0 0 0 0 0 0 5 0 0 0 0 19
2035 0 0 0 0 0 0 55 0 0 0 0 18
2036 0 0 0 0 0 0 5 0 0 0 0 17
2037 0 0 0 170 0 0 5 0 0 0 20 17
2038 0 -706 0 170 0 0 55 100 200 0 20 17
2039 0 0 0 0 0 0 5 0 0 0 40 15
2040 0 0 0 0 0 400 0 0 0 GWW3 20 14
2041 0 0 0 0 0 200 5 0 0 0 20 14
2042 0 0 0 0 0 400 5 0 0 0 0 14
2043 0 0 0 0 0 100 0 50 0 0 0 14
Subtotal -841 -706 967 340 1,800 3,025 1,148 150 200 180 360
Total 6,623 Portfolio Cost: $9,816M

Portfolio Emissions Forecast
Page 72 2023 Integrated Resource Plan—Appendix C
PORTFOLIO EMISSIONS FORECAST
Total emissions forecasts for Idaho Power’s resources are outputs of the AURORA model and are presented below.
Main Cases CO2 Emissions (Metric Tons)

Portfolio Emissions Forecast
2023 Integrated Resource Plan—Appendix C Page 73
Scenarios and Sensitivities CO2 Emissions (Metric Tons):

Portfolio Emissions Forecast
Page 74 2023 Integrated Resource Plan—Appendix C
Main Cases SO2 Emissions (Metric Tons)

Portfolio Emissions Forecast
2023 Integrated Resource Plan—Appendix C Page 75
Scenarios and Sensitivities SO2 Emissions (Metric Tons)

Portfolio Emissions Forecast
Page 76 2023 Integrated Resource Plan—Appendix C
Main Cases NOx Emissions (Metric Tons)

Portfolio Emissions Forecast
2023 Integrated Resource Plan—Appendix C Page 77
Scenarios and Sensitivities NOx Emissions (Metric Tons)

Portfolio Emissions Forecast
Page 78 2023 Integrated Resource Plan—Appendix C
Portfolio Emissions
Main Cases CO2 Emissions (Metric Tons)
Jul 2026 B2H Nov 2026 B2H Without B2H GWW Sensitivities
Year
Without
Valmy Valmy 2 Valmy 1 & 2
Without
Valmy Valmy 2 Valmy 1 & 2 Without B2H
Without
GWW Phases
GWW Phase
1 Only
GWW Phase
1 & 2 Only
2024 3,366,607 3,367,669 3,357,617 3,379,473 3,363,060 3,320,049 3,505,699 3,372,487 3,363,600 3,361,768
2025 3,521,270 3,524,571 3,536,838 3,529,678 3,535,784 3,511,761 3,545,252 3,525,218 3,527,529 3,518,734
2026 3,421,105 3,486,914 3,421,537 3,335,433 3,467,332 3,565,157 3,587,283 3,611,925 3,531,603 3,564,589
2027 2,364,726 2,423,051 2,372,879 2,243,730 2,311,886 2,498,553 2,600,665 2,560,169 2,569,174 2,449,896
2028 2,244,285 2,281,218 2,278,820 2,096,509 2,215,993 2,217,390 2,425,029 2,439,040 2,524,128 2,330,484
2029 2,085,818 1,961,086 2,076,325 1,887,008 1,936,454 2,066,820 2,536,951 2,561,134 2,243,672 2,007,467
2030 1,477,117 1,340,036 1,496,445 1,267,148 1,331,183 1,462,190 1,702,552 2,041,235 1,751,621 1,443,322
2031 1,458,780 1,285,705 1,425,949 1,140,020 1,337,016 1,277,913 1,495,017 1,864,447 1,680,097 1,360,531
2032 1,172,307 1,184,680 1,140,766 1,028,873 1,130,518 1,154,399 1,345,738 1,686,763 1,343,955 1,073,175
2033 1,088,608 1,139,628 1,137,758 970,416 1,074,124 1,063,863 1,249,073 1,642,284 1,633,253 1,082,760
2034 1,102,207 1,014,563 1,129,448 1,038,398 1,147,504 1,016,265 1,418,127 1,736,761 1,607,203 1,185,587
2035 969,045 954,940 1,017,423 930,579 962,194 875,927 1,141,263 1,070,749 1,209,862 1,000,129
2036 1,077,427 1,113,226 1,083,840 1,006,886 1,091,843 819,126 1,290,885 1,272,803 1,326,011 1,229,695
2037 1,090,301 1,096,750 1,064,933 1,099,131 1,112,048 779,574 1,280,417 1,260,130 1,303,552 1,186,632
2038 743,217 806,782 628,576 753,154 774,355 594,170 912,474 1,014,657 790,423 896,369
2039 685,923 731,854 616,514 685,672 707,627 521,610 878,149 1,011,587 800,412 789,588
2040 622,696 679,881 574,580 628,354 674,372 520,401 825,877 847,676 711,556 719,350
2041 673,577 731,911 580,115 645,700 655,082 525,143 812,933 989,300 798,559 726,832
2042 642,186 673,392 601,119 635,835 676,903 497,737 869,267 948,793 752,595 759,144
2043 607,501 607,373 543,147 597,090 578,131 529,398 803,878 846,165 775,112 650,958
Total 30,414,704 30,405,231 30,084,630 28,899,086 30,083,409 28,817,444 34,226,528 36,303,324 34,243,917 31,337,010

Portfolio Emissions Forecast
2023 Integrated Resource Plan—Appendix C Page 79
Scenarios and Sensitivities CO2 Emissions (Metric Tons)
Year

2024 2,572,462 2,788,395 2,459,954 3,413,958 2,819,296 3,392,946 3,376,949 3,275,537 2,893,122 3,474,577 3,469,601 3,357,763
2025 3,259,121 3,223,349 2,306,435 3,543,104 3,065,046 3,532,625 3,535,449 3,475,413 3,100,913 3,705,229 3,677,727 3,523,437
2026 2,406,086 2,597,012 1,925,374 3,216,503 3,279,298 3,621,864 3,660,011 3,548,596 3,393,467 3,785,269 3,781,453 3,566,612
2027 2,489,885 2,317,189 1,638,136 3,076,668 2,502,057 2,554,003 2,652,083 2,464,076 2,669,099 3,081,909 3,016,419 2,520,532
2028 1,596,254 1,542,255 1,550,767 3,256,017 2,205,721 2,384,873 2,495,377 2,338,139 2,402,382 3,113,073 3,108,384 2,418,106
2029 1,413,765 1,370,321 1,529,683 3,174,843 2,181,757 2,161,617 2,176,872 2,186,954 2,306,365 3,483,681 3,575,556 2,135,205
2030 1,047,247 1,090,560 1,230,354 2,365,063 1,490,599 1,465,961 1,385,654 1,632,989 1,647,326 2,330,532 2,522,836 1,383,329
2031 916,489 929,948 866,374 2,160,803 1,217,032 1,383,323 1,262,529 1,410,813 1,456,834 2,226,891 2,434,331 1,250,750
2032 876,033 829,906 910,590 2,207,182 1,218,345 1,202,806 1,172,400 1,356,313 1,417,330 2,051,860 2,423,357 1,118,555
2033 746,999 1,067,784 846,866 2,353,038 1,534,567 1,142,774 1,020,460 1,351,844 2,288,038 1,220,937 1,342,934 1,052,518
2034 694,949 656,800 746,704 2,229,880 1,417,643 1,177,205 1,161,662 1,455,013 1,555,519 976,138 1,078,904 1,137,265
2035 668,646 0 857,657 2,187,898 1,258,748 990,771 1,029,449 1,144,189 1,416,909 1,156,242 1,373,717 1,030,143
2036 702,143 0 818,176 2,132,573 1,077,717 1,161,334 1,178,978 1,311,954 1,560,046 1,244,090 1,395,180 1,207,898
2037 733,896 0 826,401 1,647,646 950,335 1,202,837 1,196,169 1,283,968 1,368,145 1,315,306 1,575,520 1,198,405
2038 592,944 0 569,757 1,363,592 851,923 813,425 863,271 733,943 1,011,075 1,042,721 1,179,398 902,311
2039 504,911 0 582,999 1,129,455 547,078 771,230 815,822 697,520 748,979 921,425 946,707 813,825
2040 479,076 0 531,306 1,163,529 494,451 708,366 702,658 634,022 584,837 873,019 1,015,758 777,044
2041 423,743 0 498,185 1,617,905 461,334 703,574 725,831 693,229 619,930 911,629 1,015,080 751,549
2042 419,399 0 465,932 1,603,036 470,795 752,596 751,711 670,367 563,178 932,952 1,026,588 817,762
2043 418,697 0 477,896 1,671,359 369,659 646,428 664,168 653,545 460,393 763,139 870,710 681,926
Total 22,962,745 18,413,520 21,639,546 45,514,053 29,413,400 31,770,558 31,827,503 32,318,424 33,463,885 38,610,619 40,830,159 31,644,936

Portfolio Emissions Forecast
Page 80 2023 Integrated Resource Plan—Appendix C
Main Cases SO2 Emissions (Metric Tons)
Jul 2026 B2H Nov 2026 B2H Without B2H GWW Sensitivities
Year
Without
Valmy Valmy 2 Valmy 1 & 2
Without
Valmy Valmy 2 Valmy 1 & 2 Without B2H
Without
GWW Phases
GWW Phase
1 Only
GWW Phase
1 & 2 Only
2024 1,110 1,114 1,104 1,115 1,106 1,092 1,218 1,112 1,107 1,110
2025 1,316 1,316 1,319 1,314 1,318 1,302 1,321 1,315 1,318 1,316
2026 1,380 1,388 1,399 1,342 1,360 1,376 1,400 1,400 1,372 1,396
2027 1,036 1,031 1,060 989 1,010 1,091 1,121 1,079 1,106 1,044
2028 1,017 1,032 1,032 971 1,008 1,033 1,074 1,085 1,133 1,033
2029 881 825 895 814 837 891 849 863 955 858
2030 40 41 47 41 46 43 46 59 60 46
2031 38 40 40 36 41 41 39 62 60 43
2032 55 54 56 51 58 59 56 78 68 59
2033 58 57 58 54 63 59 57 80 66 59
2034 60 61 61 57 64 58 54 80 69 60
2035 42 41 43 40 44 41 43 55 50 43
2036 34 34 35 32 37 33 36 50 43 36
2037 32 32 34 31 36 30 35 48 41 34
2038 60 59 62 56 67 62 63 95 78 63
2039 74 72 75 71 77 81 67 107 95 76
2040 70 66 67 64 66 73 70 104 89 71
2041 64 63 64 62 63 69 66 96 89 75
2042 60 61 63 58 59 65 65 96 81 72
2043 51 55 52 49 50 57 54 89 77 61
Total 7,477 7,442 7,565 7,248 7,411 7,556 7,735 7,954 7,957 7,557

Portfolio Emissions Forecast
2023 Integrated Resource Plan—Appendix C Page 81
Scenarios and Sensitivities SO2 Emissions (Metric Tons)
Year

2024 638 648 755 1,135 927 1,120 1,113 1,088 952 1,166 1,164 1,112
2025 1,126 1,012 727 1,257 1,150 1,320 1,316 1,290 1,168 1,366 1,357 1,311
2026 898 936 691 1,148 1,330 1,411 1,408 1,376 1,365 1,425 1,421 1,389
2027 1,219 1,112 643 1,082 1,130 1,067 1,102 1,058 1,127 1,203 1,186 1,061
2028 675 693 597 1,172 1,033 1,058 1,083 1,067 1,058 1,258 1,247 1,077
2029 381 358 544 1,101 897 898 876 922 913 1,075 1,081 890
2030 40 41 27 45 48 47 49 44 50 55 50 52
2031 31 29 22 47 45 44 43 37 51 58 58 43
2032 28 28 22 45 44 61 60 51 51 53 51 60
2033 46 34 24 52 85 62 63 52 103 51 50 64
2034 38 13 18 50 66 63 64 54 67 52 57 65
2035 32 0 21 60 54 44 45 37 56 42 42 47
2036 33 0 22 52 49 37 37 31 57 40 39 39
2037 34 0 24 39 42 36 36 29 48 43 43 37
2038 67 0 58 77 95 68 68 46 77 124 115 72
2039 66 0 57 87 107 82 83 55 107 132 124 89
2040 59 0 57 105 77 70 78 50 78 131 130 79
2041 85 0 53 152 71 69 75 50 75 123 132 77
2042 81 0 71 141 78 68 71 49 85 119 132 71
2043 84 0 60 151 67 55 63 42 64 110 122 62
Total 5,662 4,903 4,494 7,998 7,395 7,679 7,733 7,429 7,553 8,629 8,599 7,698

Portfolio Emissions Forecast
Page 82 2023 Integrated Resource Plan—Appendix C
Main Cases NOx Emissions (Metric Tons)
Jul 2026 B2H Nov 2026 B2H Without B2H GWW Sensitivities
Year
Without
Valmy Valmy 2 Valmy 1 & 2
Without
Valmy Valmy 2 Valmy 1 & 2 Without B2H
Without
GWW Phases
GWW Phase
1 Only
GWW Phase
1 & 2 Only
2024 1,859 1,853 1,849 1,870 1,855 1,832 1,966 1,863 1,851 1,851
2025 1,849 1,859 1,867 1,862 1,867 1,839 1,879 1,851 1,860 1,845
2026 1,654 1,641 1,685 1,610 1,631 1,666 1,646 1,661 1,598 1,613
2027 980 1,020 986 872 925 987 1,020 1,088 1,042 1,005
2028 931 919 925 795 852 890 937 996 999 953
2029 764 783 895 733 779 813 777 838 786 791
2030 740 787 994 738 756 925 638 795 806 827
2031 769 765 963 676 775 862 595 729 777 805
2032 622 738 742 618 645 756 495 641 611 608
2033 535 726 758 606 641 673 482 651 648 631
2034 532 577 661 588 639 457 560 528 536 641
2035 446 509 561 520 502 377 447 405 449 500
2036 598 684 678 641 662 392 621 553 594 719
2037 588 670 659 655 658 415 614 551 569 700
2038 415 498 471 481 535 269 386 351 277 511
2039 299 310 489 306 407 228 257 337 307 326
2040 280 281 455 265 373 218 254 287 285 301
2041 307 324 446 300 402 227 249 326 320 323
2042 306 313 551 297 423 185 288 341 302 340
2043 267 264 478 263 332 203 262 315 312 286
Total 14,740 15,522 17,112 14,695 15,659 14,214 14,374 15,105 14,927 15,576

Portfolio Emissions Forecast
2023 Integrated Resource Plan—Appendix C Page 83
Scenarios and Sensitivities NOx Emissions (Metric Tons)
Year

2024 1,507 1,721 1,135 1,885 1,534 1,872 1,869 1,797 1,589 1,928 1,926 1,842
2025 1,741 1,800 994 1,921 1,583 1,862 1,866 1,846 1,596 1,985 1,968 1,858
2026 1,141 1,225 713 1,656 1,523 1,652 1,700 1,624 1,555 1,762 1,760 1,633
2027 1,027 947 602 1,602 1,006 1,042 1,123 994 1,097 1,304 1,295 1,032
2028 673 658 575 1,700 865 955 1,016 912 970 1,329 1,326 969
2029 516 617 479 1,711 770 903 920 898 861 1,232 1,329 888
2030 447 603 428 1,363 742 861 763 1,022 798 1,094 1,216 771
2031 374 568 274 1,316 599 789 721 836 718 1,064 1,216 706
2032 366 540 310 1,333 624 758 719 894 787 990 1,212 618
2033 346 834 289 1,409 773 650 582 910 1,302 548 639 669
2034 340 543 197 1,327 695 665 625 868 792 254 482 622
2035 388 18 306 1,277 640 501 521 655 705 430 609 516
2036 398 17 282 1,276 536 693 712 786 801 457 620 724
2037 452 48 297 1,051 492 697 680 750 717 494 697 689
2038 213 64 158 647 431 513 506 423 478 307 404 532
2039 117 58 163 423 206 420 334 441 290 216 224 353
2040 126 60 152 387 192 362 294 379 243 196 228 326
2041 173 61 139 519 196 394 311 481 265 206 248 333
2042 187 62 158 536 189 442 333 465 268 207 246 376
2043 184 42 155 573 152 347 286 475 198 184 213 287
Total 10,717 10,488 7,807 23,913 13,747 16,378 15,881 17,456 16,032 16,190 17,859 15,744

Stochastic Risk Analysis
Page 84 2023 Integrated Resource Plan—Appendix C
STOCHASTIC RISK ANALYSIS
The stochastic analysis assesses the effect on portfolio costs when select variables take on values
different from their planning-case levels. Stochastic variables are selected based on the degree to
which there is uncertainty regarding their forecasts and the degree to which they can affect the
analysis results (i.e., portfolio costs).
The purpose of the analysis is to understand the range of portfolio costs across a wide extent of
stochastic shocks (i.e., across the full set of 60 stochastic iterations) and how the ranges for portfolios
costs differ.
Idaho Power identified the following four variables for the stochastic analysis:
Natural Gas Sampling (Nominal $/MMBtu)
1. Natural gas price—Based on the historical Henry Hub natural gas price, it was determined that
natural gas price variance around the trend approximates a log-normal distribution with a year-
to-year correlation factor of 0.55. The graph below shows planning case average annual price in
the black dashed line and the remaining-colored lines show the 60 different stochastic
iterations for Henry Hub gas prices.

Stochastic Risk Analysis
2023 Integrated Resource Plan—Appendix C Page 85
Customer Load Sampling (Annual MWh)
2. Customer load—Customer load follows a normal distribution and is adjusted around the
planning case load forecast, which is shown as the dashed line in the figure below. To assess the
reasonableness of the stochastic error bounds as they relate to customer load, the upper and
lower bounds were compared to the load forecast 90/10 error bounds. For both the upper and
lower bound, the stochastic values were found to fall slightly outside of the 90/10 bounds
which is to be expected.

Hydro Generation Sampling (Annual MWh)
3. Hydroelectric variability—Hydroelectric generation variability was found to approximate a
uniform distribution based on historical generation. Although an unexpected result based on
the non-uniform distribution of rainfall across the Snake River Basin, the regulation of
streamflow likely explains the difference between rainfall and generation distributions.
Stochastic Risk Analysis
Page 86 2023 Integrated Resource Plan—Appendix C
In addition to the distribution, the historical data also shows a correlation between years
of 0.55.

Carbon Price Sampling (Annual MWh)
4. Carbon Price—Though historical carbon price adder prices have always been zero, a wide-range
of possible values are modeled into the future. The stochastic lower bound was set near zero
and the upper bound was set to roughly approximate the Social Cost of Carbon1 curve after

1 epa.gov/system/files/documents/2022-11/epa_scghg_report_draft_0.pdf, page 67, retrieved September 7 2023
Stochastic Risk Analysis
2023 Integrated Resource Plan—Appendix C Page 87
discussions with IRPAC. Stochastic values were then produced such that the average of all the
values approximated the planning carbon price adder case.

The four selected stochastic variables are key drivers of variability in year-to-year power-supply costs
and therefore provide suitable stochastic shocks to allow differentiated results for analysis.
Due to the significant time required to perform the stochastic risk analysis, Idaho Power was limited to
performing a maximum of 60 risk iterations. Based on the sample size, the choice was made to use the
Latin Hypercube sampling technique over a pure Monte Carlo method. The Latin Hypercube design
samples the distribution range with a relatively smaller sample size, allowing a reduction in simulation
run times. The Latin Hypercube method does this by sampling at regular intervals across the
distribution spectrum. Contrast this to Monte Carlo methods where samples are taken randomly from
the distribution range. The random Monte Carlo draw requires far more than 60 iterations to ensure a
good distribution of draws. Once the stochastic elements are drawn, the company then calculated the
$/
s
h
o
r
t

t
o
n
Stochastic Risk Analysis
Page 88 2023 Integrated Resource Plan—Appendix C
20-year NPV portfolio cost for each of the 60 iterations for all evaluated portfolios. The graph below
shows the distribution of 20-year NPV portfolio costs for the portfolios.

Portfolio Stochastic Analysis, Total Portfolio Cost
NPV Years 2024–2043 ($ x 1,000)
In the figure above, each line represents the likelihood of occurrence by NPV. Higher values on the line
represent a higher probability of occurrence with values near the horizontal axis representing
improbable events. Values that occur toward the left have lower cost while values toward the right
have higher cost. As indicated by the peak of the graph being furthest left, the results of the stochastic
analysis show that the Preferred Portfolio is likely to have the lowest cost given a range of natural gas
prices, load forecasts, carbon prices, and hydroelectric generation levels. Indeed, in all 60 risk
iterations spanning the range of stochastic variables, the Preferred Portfolio (Jul2026 B2H Valmy 1 & 2)
was the least-cost option.

Stochastic Kernel Comparison (Probability of Observation by Portfolio NPV $000,000)
Loss of Load Expectation
2023 Integrated Resource Plan—Appendix C Page 89
LOSS OF LOAD EXPECTATION
As utilities continue to add more renewable energy to the electric grid, it is becoming more critical to
analyze the effect Variable Energy Resources (VER) and Energy Limited Resources (ELR) have on
system reliability.
weather, for example, solar and wind projects.
able to dispatch for a limited amount of time and under certain conditions, for
example, battery storage projects and demand response programs.

For the 2023 IRP, Idaho Power used the risk-based equations and methodologies described in this
section to calculate the capacity contribution of different VERs and ELRs for the AURORA LTCE model
and quantitatively analyze the risk associated with the portfolios. The company chose to conduct this
study because of the recognition that VER output changes over time (VER hourly output being
dependent on a multitude of factors like weather and environmental conditions) and that it is essential
to capture that variability.
Methodology Components
The Loss of Load Probability (LOLP) is the likelihood of the system load exceeding the available
generating capacity during a given time period (typically an hour). The LOLP can be calculated by
determining the probability that the available generation at any given hour is able to meet the net load
during that same hour. The LOLP can be defined as: 𝐿𝐿𝐿𝐿𝐿𝐿𝐿𝐿=𝐿𝐿𝑖𝑖(𝐺𝐺𝑖𝑖−𝐿𝐿𝑖𝑖)
where 𝐿𝐿𝑖𝑖 is the cumulative probability of the available generation required to meet the system demand
at hour 𝑖𝑖, 𝐺𝐺𝑖𝑖 is the available generation required to meet the system demand at hour 𝑖𝑖, and 𝐿𝐿𝑖𝑖 is the
net system demand at hour 𝑖𝑖.
The Loss of Load Expectation (LOLE) is the expected number of days per time period for which the
available generation capacity is insufficient to serve the demand at least once per day. The LOLE can be
calculated by adding the maximum LOLP from each day for a time period (typically over the course of a
year). LOLE can be defined as: 𝐿𝐿𝐿𝐿𝐿𝐿𝐿𝐿= �𝑚𝑚𝑚𝑚𝑚𝑚[𝑖𝑖=1𝐻𝐻(𝐿𝐿𝐿𝐿𝐿𝐿𝐿𝐿𝑖𝑖)]𝐷𝐷
𝑑𝑑=1
where 𝐿𝐿𝐿𝐿𝐿𝐿𝐿𝐿𝑖𝑖 is the LOLP at hour 𝑖𝑖. For the 2023 IRP, Idaho Power has adopted a LOLE threshold of
0.1 event-days per year.
Loss of Load Expectation
Page 90 2023 Integrated Resource Plan—Appendix C
The Effective Load Carrying Capability (ELCC) is a reliability-based metric used to assess the
contribution to peak of any given generation unit or power plant. ELCC decomposes an individual
generator’s contribution to the overall system reliability and is driven by the timing of high LOLP hours.
To calculate the ELCC of a resource, there are two definitions that should first be stated:
the number of hours a generation unit is forced off-line compared to the
number of hours the unit runs; for example, an EFORd of 3% means a
generator is forced off 3% of its running time.
available and never forced off-line.

The ELCC of a resource is determined by first calculating the perfect generation required to achieve a
LOLE of 0.1 event-days per year. Then, the resource being evaluated is added to the system and the
perfect generation required is calculated once again. The ELCC (%) of a given resource will be equal to
the difference in the size of the perfect generators from the two runs divided by the resource’s
nameplate: 𝐿𝐿𝐿𝐿𝐸𝐸𝐸𝐸=𝐿𝐿𝐺𝐺1 −𝐿𝐿𝐺𝐺2𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑁𝑁𝑁𝑁∗100
where 𝐿𝐿𝐺𝐺1 is the perfect generation required to achieve a LOLE of 0.1 event-days per year without
including the evaluated resource, 𝐿𝐿𝐺𝐺2 is the perfect generation required to achieve the same LOLE of
0.1 event-days per year with the evaluated resource included, and 𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑁𝑁𝑁𝑁 is the nameplate of
the evaluated resource.
Modeling Idaho Power’s System
Idaho Power developed the Reliability and Capacity Assessment Tool (RCAT) to implement the LOLE
methodology and maximize computational efficiency for modeling Idaho Power’s existing and potential
resource stack. Within this tool, the company’s resources were split into three categories: dispatchable
resources, VERs, and ELRs. Dispatchable resources were modeled using a monthly outage table that
was calculated using their monthly capacity and EFORd. The outage table is comprised of the following
four components:
Capacity In: capacity available to serve load (MW)
Capacity Out: forced outage capacity (MW)
Individual Probability: probability that a specific event will occur
Cumulative Probability: cumulative distribution of the individual probabilities

Loss of Load Expectation
2023 Integrated Resource Plan—Appendix C Page 91
Existing dispatchable resources include hydro with reservoir storage (the Hells Canyon Complex),
thermal resources, and various transmission assets with access to the market.
VERs were modeled by using six years of historical hourly output data to maintain the relationship
between load and renewable generation. Other resources for which Idaho Power does not have direct
control over dispatch were also modeled using the six years of historical hourly output data.
Examples of these resources include dairy digestors, non-wind and non-solar PURPA projects,
ROR hydroelectric plants, and geothermal generation. In the model, these variable resources
are subtracted from the system-adjusted load to produce a net load that is then used in the
LOLE calculations.
Because resources, such as battery storage and demand response, are dispatched based on the daily
load shape, Idaho Power devised a separate way to model ELRs. The RCAT begins by sorting the days in
a year from high to low based on their net load peak. After verifying that the operating parameters of
the demand response portfolio or storage resource are met on that day, the algorithm optimizes the
daily dispatch based on the sorted updated net load.
This customization functionality of the RCAT allows for a detailed approach to modeling Idaho Power’s
system. As system needs continue to change, new analyses such as LOLE are essential in best
evaluating the company’s reliability and highest-risk hours.
Western Resource Adequacy Program Modeling
The Western Resource Adequacy Program (WRAP) is a regional planning and capacity-sharing program
in which Idaho Power is a participant. The function and purpose of WRAP is provided in Chapter 2 of
the IRP. Because the WRAP is designed as program of last resort, Idaho Power assumed for the
2023 IRP that it will leverage WRAP only once per year. As Idaho Power gains operational experience
with WRAP, the company will develop a more refined understanding of how often it is likely to
leverage the WRAP operations program.
To model the benefit of leveraging WRAP once per year, Idaho Power first performed an LOLP analysis
on six historical test years of load and resource data and identified the highest-risk day in each
historical test year. Using Idaho Power’s RCAT, 100 MW of capacity was then added to the resource
stack for each of the six identified highest-risk days. The 100 MW resource addition represents the
amount of capacity leveraged from WRAP required to bring the LOLP values of the highest-risk day in
the worst-performing historical test year down to a similar risk profile as other days in that year.
The RCAT analysis found that, on average, an additional 100 MW from WRAP on the company’s
highest-risk day results in Idaho Power needing 14 MW less perfect generation to meet a
0.1 event-days per year LOLE. In other words, leveraging WRAP to significantly reduce the risk of the
highest-risk day each year is the equivalent of avoiding 14 MW of perfect generation.
Loss of Load Expectation
Page 92 2023 Integrated Resource Plan—Appendix C
For the 2023 IRP, Idaho Power included the 14 MW of WRAP capacity benefit beginning in 2027—
the assumed date of binding participation—and continuing each year through the planning horizon.
Idaho Power is working with other WRAP participants to align on a collective binding date. Should that
date change from 2027, the company will adjust the first benefit year in future IRPs.
Effective Load-Carrying Capability Results
The ELCC of future VERs and ELRs are dependent upon the resources built before them, making the
ELCC calculation of future resources challenging. For the 2023 IRP AURORA LTCE model, Idaho Power
implemented seasonal saturation ELCC curves for each of the VERs and ELRs. The seasonal saturation
ELCC curves assist in synchronizing the RCAT and AURORA models in terms of recognizing similar
capacity needs and allow for recognition of how quickly a particular resource can become saturated.
For example, the capacity contribution of solar during the summer declines as the net peak shifts to
later in the day; however, during the winter, solar has a significantly lower capacity contribution when
the highest-risk hours (typically) occur outside the limited sunlight hours.
The ELCC of future and existing resources can be calculated by using the “last-in” ELCC method,
where each resource is assumed to be the last one added to the mix independent of the order on
which they were added to the system. For example, the ELCC of demand response appears to be lower
than in past IRPs but it is primarily due to the amount of battery storage included in the resource
buildout. The ELCC values in the table below are provided for informational purposes.
ELCC of Existing and Expected Resources ELCC of Future Resources
Resource Average Resource Average
Solar 51.3% Solar 27.7%
Wind 20.0% Wind (ID) 15.5%
Demand Response 34.0% Wind (WY) 20.8%
4-Hour Stand-Alone Battery Storage 81.2% 4-Hour Stand-Alone Battery Storage 38.5%
Solar + 4-Hour Battery Storage (1:1) 85.1% 8-Hour Stand-Alone Battery Storage 79.2%
Solar + 4-Hour Battery Storage (1:0.6) 61.2% Incremental Existing Demand Response 19.4%
Storage Demand Response 35.0%
Pricing Demand Response 32.2%

Timing of Highest Risk
The calculation of LOLE involves determining the LOLP for each hour, which Idaho Power performs for
each of the test years used in the RCAT. In terms of capacity, the hourly LOLP values were used to
determine the seasons and hours of highest risk for the 2023 IRP.
The seasons of highest risk were determined by first selecting the LOLP values that made up 90% of the
total hourly risk (i.e., sum of all LOLPs). These LOLPs were then grouped by their time of occurrence to
Loss of Load Expectation
2023 Integrated Resource Plan—Appendix C Page 93
create the seasons of highest risk. The seasons of highest risk for the 2023 IRP were identified to be
November 1 through February 28 for winter and June 1 through September 15 for summer.
To establish the hours of medium and highest risk, the RCAT was set to select the top LOLP daily hours
that resulted in 50% of the risk of each month in the season for each of the test years; the results from
the different test years were then combined. Using the test year combined top LOLP hours, a percent
of occurrences threshold was developed to identify the medium-risk and high-risk hours.
The 2023 IRP hours of high, medium, and low risk by season are provided in the tables below.
Summer Risk Hours (June 1–September 15)
Hour End Sunday Monday Tuesday Wednesday Thursday Friday Saturday Holiday
1 SLR SLR SLR SLR SLR SLR SLR SLR
2 SLR SLR SLR SLR SLR SLR SLR SLR
3 SLR SLR SLR SLR SLR SLR SLR SLR
4 SLR SLR SLR SLR SLR SLR SLR SLR
5 SLR SLR SLR SLR SLR SLR SLR SLR
6 SLR SLR SLR SLR SLR SLR SLR SLR
7 SLR SLR SLR SLR SLR SLR SLR SLR
8 SLR SLR SLR SLR SLR SLR SLR SLR
9 SLR SLR SLR SLR SLR SLR SLR SLR
10 SLR SLR SLR SLR SLR SLR SLR SLR
11 SLR SLR SLR SLR SLR SLR SLR SLR
12 SLR SLR SLR SLR SLR SLR SLR SLR
13 SLR SLR SLR SLR SLR SLR SLR SLR
14 SLR SLR SLR SLR SLR SLR SLR SLR
15 SLR SLR SLR SLR SLR SLR SLR SLR
16 SLR SLR SLR SLR SLR SLR SLR SLR
17 SLR SLR SLR SLR SLR SLR SLR SLR
18 SLR SMR SMR SMR SMR SMR SMR SLR
19 SLR SMR SMR SMR SMR SMR SMR SLR
20 SLR SHR SHR SHR SHR SHR SHR SLR
21 SLR SHR SHR SHR SHR SHR SHR SLR
22 SLR SHR SHR SHR SHR SHR SHR SLR
23 SLR SMR SMR SMR SMR SMR SMR SLR
24 SLR SLR SLR SLR SLR SLR SLR SLR
SLR—Summer Low-Risk
SMR—Summer Medium-Risk
SHR—Summer High-Risk
Loss of Load Expectation
Page 94 2023 Integrated Resource Plan—Appendix C
Winter Risk Hours (November 1–February 28/29)
Hour End Sunday Monday Tuesday Wednesday Thursday Friday Saturday Holiday
1 WLR WLR WLR WLR WLR WLR WLR WLR
2 WLR WLR WLR WLR WLR WLR WLR WLR
3 WLR WLR WLR WLR WLR WLR WLR WLR
4 WLR WLR WLR WLR WLR WLR WLR WLR
5 WLR WLR WLR WLR WLR WLR WLR WLR
6 WLR WLR WLR WLR WLR WLR WLR WLR
7 WLR WHR WHR WHR WHR WHR WHR WLR
8 WLR WHR WHR WHR WHR WHR WHR WLR
9 WLR WHR WHR WHR WHR WHR WHR WLR
10 WLR WHR WHR WHR WHR WHR WHR WLR
11 WLR WMR WMR WMR WMR WMR WMR WLR
12 WLR WMR WMR WMR WMR WMR WMR WLR
13 WLR WLR WLR WLR WLR WLR WLR WLR
14 WLR WLR WLR WLR WLR WLR WLR WLR
15 WLR WLR WLR WLR WLR WLR WLR WLR
16 WLR WLR WLR WLR WLR WLR WLR WLR
17 WLR WMR WMR WMR WMR WMR WMR WLR
18 WLR WHR WHR WHR WHR WHR WHR WLR
19 WLR WHR WHR WHR WHR WHR WHR WLR
20 WLR WHR WHR WHR WHR WHR WHR WLR
21 WLR WMR WMR WMR WMR WMR WMR WLR
22 WLR WLR WLR WLR WLR WLR WLR WLR
23 WLR WLR WLR WLR WLR WLR WLR WLR
24 WLR WLR WLR WLR WLR WLR WLR WLR

WLR—Winter Low-Risk
WMR—Winter Medium-Risk
WHR—Winter High-Risk

Loss of Load Expectation
2023 Integrated Resource Plan—Appendix C Page 95
Off-Season Risk Hours (March 1–May 31, September 16–October 31)
Hour End Sunday Monday Tuesday Wednesday Thursday Friday Saturday Holiday
1 OFLR OFLR OFLR OFLR OFLR OFLR OFLR OFLR
2 OFLR OFLR OFLR OFLR OFLR OFLR OFLR OFLR
3 OFLR OFLR OFLR OFLR OFLR OFLR OFLR OFLR
4 OFLR OFLR OFLR OFLR OFLR OFLR OFLR OFLR
5 OFLR OFLR OFLR OFLR OFLR OFLR OFLR OFLR
6 OFLR OFLR OFLR OFLR OFLR OFLR OFLR OFLR
7 OFLR OFLR OFLR OFLR OFLR OFLR OFLR OFLR
8 OFLR OFLR OFLR OFLR OFLR OFLR OFLR OFLR
9 OFLR OFLR OFLR OFLR OFLR OFLR OFLR OFLR
10 OFLR OFLR OFLR OFLR OFLR OFLR OFLR OFLR
11 OFLR OFLR OFLR OFLR OFLR OFLR OFLR OFLR
12 OFLR OFLR OFLR OFLR OFLR OFLR OFLR OFLR
13 OFLR OFLR OFLR OFLR OFLR OFLR OFLR OFLR
14 OFLR OFLR OFLR OFLR OFLR OFLR OFLR OFLR
15 OFLR OFLR OFLR OFLR OFLR OFLR OFLR OFLR
16 OFLR OFLR OFLR OFLR OFLR OFLR OFLR OFLR
17 OFLR OFLR OFLR OFLR OFLR OFLR OFLR OFLR
18 OFLR OFLR OFLR OFLR OFLR OFLR OFLR OFLR
19 OFLR OFLR OFLR OFLR OFLR OFLR OFLR OFLR
20 OFLR OFLR OFLR OFLR OFLR OFLR OFLR OFLR
21 OFLR OFLR OFLR OFLR OFLR OFLR OFLR OFLR
22 OFLR OFLR OFLR OFLR OFLR OFLR OFLR OFLR
23 OFLR OFLR OFLR OFLR OFLR OFLR OFLR OFLR
24 OFLR OFLR OFLR OFLR OFLR OFLR OFLR OFLR
OFLR —Off-Season Low-Risk
Loss of Load Expectation
Page 96 2023 Integrated Resource Plan—Appendix C
While the identified seasons and hours capture over 95% of the total hourly risk, the magnitude of
LOLP values vary. Planning to the 0.1 event-days per year LOLE threshold, the percentage of risk
distribution can be visualized through the lens of the monthly LOLE results, as shown in the
following table.
Month LOLE Percentage
Jan *0.6%
Feb *0.0%
Mar 0.0%
Apr 0.0%
May 0.0%
Jun 2.8%
Jul 58.5%
Aug 19.3%
Sep 3.6%
Oct 1.0%
Nov 6.7%
Dec 7.4%
Total 100.0%
*January and February are expected to be as high as November and Decemberf for the 2025–2026 winter season due to forecasted industrial customer
load ramps.

Compliance with State of Oregon IRP Guidelines
2023 Integrated Resource Plan—Appendix C Page 97
COMPLIANCE WITH STATE OF OREGON IRP GUIDELINES
Guideline 1: Substantive Requirements
a. All resources must be evaluated on a consistent and comparable basis.
• All known resources for meeting the utility's load should be considered, including supply-
side options which focus on the generation, purchase and transmission of power or gas
purchases, transportation, and storage and demand side options which focus on
conservation and demand response.
• Utilities should compare different resource fuel types, technologies, lead times, in-service
dates, durations and locations in portfolio risk modeling.
• Consistent assumptions and methods should be used for evaluation of all resources.
• The after-tax marginal weighted-average cost of capital (WACC) should be used to discount
all future resource costs.
Idaho Power response:
Idaho Power considered a range of resource types including renewables (e.g., wind and solar), demand-side management,
transmission, market purchases, thermal resources, and energy storage. Each of these resources was included as options in the
AURORA capacity expansion modeling.
Supply-side and purchased resources for meeting the utility’s load are discussed in Chapter 4. Idaho Power Today; demand-side
options are discussed in Chapter 6. Demand-Side Resources; and transmission resources are discussed in Chapter 7. Transmission
Planning.
New resource options including fuel types, technologies, lead times, in-service dates, durations, and locations are described in Chapter
5. Future Supply-Side Generation and Storage Resources, Chapter 6. Demand-Side Resources, Chapter 7. Transmission Planning, and
Chapter 8. Planning Period Forecasts.
The consistent modeling method for evaluating new resource options is described in Chapter 8. Planning Period Forecasts and Chapter
10. Modeling Analysis.
The after-tax marginal WACC rate used to discount all future resource costs is discussed in Appendix C: Technical Appendix Supply-Side
Resource Data – Key Financial and Forecast Assumptions.

b. Risk and uncertainty must be considered.
• At a minimum, utilities should address the following sources of risk and uncertainty:
1. Electric utilities: load requirements, hydroelectric generation, plant forced outages, fuel
prices, electricity prices, and costs to comply with any regulation of greenhouse gas
emissions.
2. Natural gas utilities: demand (peak, swing, and baseload), commodity supply and price,
transportation availability and price, and costs to comply with any regulation of
greenhouse gas emissions.
• Utilities should identify in their plans any additional sources of risk and uncertainty.
Compliance with State of Oregon IRP Guidelines
Page 98 2023 Integrated Resource Plan—Appendix C
Idaho Power response:
Electric utility risk and uncertainty factors (load, natural gas, and hydroelectric generation) for resource portfolios are considered in
Chapter 10. Modeling Analysis. Plant forced outages are modeled in RCAT on a unit basis and are discussed in Appendix C: Technical
Appendix Loss of Load Expectation. Risk and uncertainty associated with fuel prices and greenhouse gas emissions are discussed in Chapter 9 Portfolios. The AURORA generated electricity prices are impacted by the above assumptions and are considered in the analysis.
Additional sources of risk and uncertainty including qualitative risks are discussed in Chapter 10. Modeling Analysis.

c. The primary goal must be the selection of a portfolio of resources with the best combination of
expected costs and associated risks and uncertainties for the utility and its customers.
• The planning horizon for analyzing resource choices should be at least 20 years and account
for end effects. Utilities should consider all costs with a reasonable likelihood of being
included in rates over the long term, which extends beyond the planning horizon and the
life of the resource.
• Utilities should use present value of revenue requirement (PVRR) as the key cost metric.
The plan should include analysis of current and estimated future costs for all long-lived
resources such as power plants, gas storage facilities, and pipelines, as well as all short-lived
resources such as gas supply and short-term power purchases.
• To address risk, the plan should include, at a minimum:
a. Two measures of PVRR risk: one that measures the variability of costs and one that
measures the severity of bad outcomes.
b. Discussion of the proposed use and impact on costs and risks of physical and financial
hedging.
• The utility should explain in its plan how its resource choices appropriately balance cost
and risk.
Idaho Power response:
The IRP methodology and the planning horizon of 20 years are discussed in Chapter 1. Background.
Modeling analysis of current and estimated future costs for all long-lived resources such as power plants, gas storage facilities, and pipelines, as well as all short-lived resources such as gas supply and short-term power purchases is discussed in Chapter 10. Modeling Analysis.
The discussion of cost variability and extreme outcomes, including bad outcomes is discussed in Chapter 10. Modeling Analysis.
Idaho Power’s Risk Management Policy regarding physical and financial hedging is discussed in Chapter 1. Background. Idaho Power’s Energy Risk Management Program is designed to systematically identify, quantify, and manage the exposure of the company and its customers to the uncertainties related to the energy markets in which the company is an active participant. The company’s Risk Management Standards limit term purchases to the prompt 18 months of the forward curve.
Idaho Power’s plan and how the resource choices appropriately balance cost and risk is presented in Chapter 11. Preferred Portfolio and Action Plan.

d. The plan must be consistent with the long-run public interest as expressed in Oregon and
federal energy policies.
Compliance with State of Oregon IRP Guidelines
2023 Integrated Resource Plan—Appendix C Page 99
Idaho Power response:
Long-run public interest issues are discussed in Chapter 2. Political, Regulatory, and Operational Issues and Chapter 3. Clean Energy &
Climate Change. The company also evaluated four future scenarios, including rapid electrification, climate change, 100% clean by 2035, and 100% clean by 2045. These are discussed in Chapter 9. Portfolios.

Guideline 2: Procedural Requirements
a. The public, which includes other utilities, should be allowed significant involvement in the
preparation of the IRP. Involvement includes opportunities to contribute information and ideas,
as well as to receive information. Parties must have an opportunity to make relevant inquiries
of the utility formulating the plan. Disputes about whether information requests are relevant or
unreasonably burdensome, or whether a utility is being properly responsive, may be submitted
to the Commission for resolution.
Idaho Power response:
The IRPAC meetings are open to the public. A roster of the IRPAC members along with meeting schedules and agendas is provided in
Appendix C: Technical Appendix, IRP Advisory Council..

b. While confidential information must be protected, the utility should make public, in its plan,
any non-confidential information that is relevant to its resource evaluation and action plan.
Confidential information may be protected through use of a protective order, through
aggregation or shielding of data, or through any other mechanism approved by the
Commission.
Idaho Power response:
Idaho Power makes public extensive information relevant to its resource evaluation and action plan. This information is discussed in IRPAC meetings and found throughout the 2021 IRP, the 2021 Load and Sales Forecast and in the 2021 Technical Appendix.

c. The utility must provide a draft IRP for public review and comment prior to filing a final plan
with the Commission.
Idaho Power response:
Prior to filing, Idaho Power posted online a draft 2023 IRP Report for public review and comment in September 2023..
Guideline 3: Plan Filing, Review, and Updates
a. A utility must file an IRP within two years of its previous IRP acknowledgment order. If the
utility does not intend to take any significant resource action for at least two years after its next
IRP is due, the utility may request an extension of its filing date from the Commission.
Compliance with State of Oregon IRP Guidelines
Page 100 2023 Integrated Resource Plan—Appendix C
Idaho Power response:
The OPUC acknowledged Idaho Power’s 2021 IRP on December 6, 2022, in Order 23-004. Filing the 2023 IRP in September 2023

b. The utility must present the results of its filed plan to the Commission at a public meeting prior
to the deadline for written public comment.
Idaho Power response:
Idaho Power will work with Commission Staff and other interested parties to set a schedule for review of the 2023 IRP, including a
public meeting with the Commission following the September 2023 filing.

c. Commission staff and parties should complete their comments and recommendations within six
months of IRP filing.
Idaho Power response:
This will be conducted following the filing of this IRP.

d. The Commission will consider comments and recommendations on a utility’s plan at a public
meeting before issuing an order on acknowledgment. The Commission may provide the utility
an opportunity to revise the plan before issuing an acknowledgment order.
Idaho Power response:
This will be conducted following the filing of this IRP.

e. The Commission may provide direction to a utility regarding any additional analyses or actions
that the utility should undertake in its next IRP.
Idaho Power response:
No response needed.

f. Each utility must submit an annual update on its most recently acknowledged plan. The update
is due on or before the acknowledgment order anniversary date. Once a utility anticipates a
significant deviation from its acknowledged IRP, it must file an update with the Commission,
unless the utility is within six months of filing its next IRP. The utility must summarize the
update at a Commission public meeting. The utility may request acknowledgment of changes in
proposed actions identified in an update.
Compliance with State of Oregon IRP Guidelines
2023 Integrated Resource Plan—Appendix C Page 101
Idaho Power response:
Idaho Power will file an annual update of the 2023 IRP, assuming the annual update will occur more than six months before filing the

g. Unless the utility requests acknowledgement of changes in proposed actions, the annual
update is an informational filing that:
• Describes what actions the utility has taken to implement the plan;
• Provides an assessment of what has changed since the acknowledgment order that affects
the action plan, including changes in such factors as load, expiration of resource contracts,
supply-side and demand-side resource acquisitions, resource costs, and transmission
availability; and
• Justifies any deviations from the acknowledged action plan.
Idaho Power response:
Not applicable to this filling; this activity will be conducted at a later time.
Guideline 4: Plan Components
At a minimum, the plan must include the following elements:
a. An explanation of how the utility met each of the substantive and procedural requirements;
Idaho Power response:
The information in this section is intended to show how the company complied with this guideline.

b. Analysis of high and low load growth scenarios in addition to stochastic load risk analysis with
an explanation of major assumptions;
Idaho Power response:
High-growth scenarios are tested using the Rapid Electrification case as discussed in Chapter 9. Portfolios. Stochastic analysis was performed on load (which creates high and low load conditions) and the details of that analysis are contained in Chapter 10. Modeling Analysis.

c. For electric utilities, a determination of the levels of peaking capacity and energy capability
expected for each year of the plan, given existing resources; identification of capacity and
energy needed to bridge the gap between expected loads and resources; modeling of all
existing transmission rights, as well as future transmission additions associated with the
resource portfolios tested;
Compliance with State of Oregon IRP Guidelines
Page 102 2023 Integrated Resource Plan—Appendix C
Idaho Power response:
Peaking capacity and energy capability expected for existing resources are modeled in AURORA. Identification of capacity and energy
needed to bridge the gap between expected loads and resources is an output of AURORA LTCE modeling; results of which are found in Appendix C: Technical Appendix. All existing transmission rights and future transmission additions are modeled in AURORA.
Detailed forecasts are provided in Appendix C: Technical Appendix, Sales and Load Forecast Data and Existing Resource Data.
Identification of capacity and energy needed to bridge the gap between expected loads and resources is discussed in Chapter 11. Preferred Portfolio and Action Plan.

d. For natural gas utilities, a determination of the peaking, swing and base-load gas supply and
associated transportation and storage expected for each year of the plan, given existing
resources; and identification of gas supplies (peak, swing, and baseload), transportation and
storage needed to bridge the gap between expected loads and resources;
Idaho Power response:
Not applicable to Idaho Power.

e. Identification and estimated costs of all supply-side and demand-side resource options, taking
into account anticipated advances in technology;
Idaho Power response:
Supply-side resources are discussed in Chapter 5. Future Supply-Side Generation and Storage Resources.
Demand-side resources are discussed in Chapter 6. Demand-Side Resources.
Resource costs are discussed in Chapter 8. Planning Period Forecasts and presented in Appendix C: Technical Appendix,
Supply-Side Resource Data.

f. Analysis of measures the utility intends to take to provide reliable service, including
cost-risk tradeoffs;
Idaho Power response:
Resource reliability and cost-risk tradeoffs are covered in Chapter 10. Modeling Analysis.

g. Identification of key assumptions about the future (e.g., fuel prices and environmental
compliance costs) and alternative scenarios considered;
Idaho Power response:
Key Assumptions including the natural gas price forecast are discussed in Chapter 8. Planning Period Forecasts and in Appendix C:
Technical Appendix, Key Financial and Forecast Assumptions. Environmental compliance costs are addressed in Chapter 10.
Modeling Analysis.

Compliance with State of Oregon IRP Guidelines
2023 Integrated Resource Plan—Appendix C Page 103
h. Construction of a representative set of resource portfolios to test various operating
characteristics, resource types, fuels and sources, technologies, lead times, in-service dates,
durations, and general locations – system-wide or delivered to a specific portion of the system;
Idaho Power response:
Resource portfolios considered for the 2023 IRP are described in Chapter 9. Portfolios and Appendix C: Technical Appendix, Long-Term
Capacity Expansion Results.

i. Evaluation of the performance of the candidate portfolios over the range of identified risks and
uncertainties;
Idaho Power response:
Evaluation of the portfolios over a range of risks and uncertainties is discussed in Chapter 10. Modeling Analysis.

j. Results of testing and rank ordering of the portfolios by cost and risk metric, and interpretation
of those results;
Idaho Power response:
Portfolio cost, risk results, interpretations and the selection of the Preferred Portfolio are provided in Chapter 10. Modeling Analysis.

k. Analysis of the uncertainties associated with each portfolio evaluated;
Idaho Power response:
The quantitative and qualitative uncertainties associated with each portfolio are evaluated in Chapter 10. Modeling Analysis.

l. Selection of a portfolio that represents the best combination of cost and risk for the utility and
its customers
Idaho Power response:
The Preferred Portfolio is identified in Chapter 11. Preferred Portfolio and Action Plan and represents the best combination of cost
and risk.

m. Identification and explanation of any inconsistencies of the selected portfolio with any state
and federal energy policies that may affect a utility’s plan and any barriers to implementation;
and
Idaho Power response:
The company has identified that its plans are consistent with all state and federal energy policies as of the time of filing.

Compliance with State of Oregon IRP Guidelines
Page 104 2023 Integrated Resource Plan—Appendix C
n. An action plan with resource activities the utility intends to undertake over the next two to four
years to acquire the identified resources, regardless of whether the activity was acknowledged
in a previous IRP, with the key attributes of each resource specified as in portfolio testing.
Idaho Power response:
An action plan is provided in the Executive Summary and in Chapter 11. Preferred Portfolio and Action Plan.

Guideline 5: Transmission
Portfolio analysis should include costs to the utility for the fuel transportation and electric
transmission required for each resource being considered. In addition, utilities should consider fuel
transportation and electric transmission facilities as resource options, taking into account their
value for making additional purchases and sales, accessing less costly resources in remote
locations, acquiring alternative fuel supplies, and improving reliability.
Idaho Power response:
All identified requirements in Guideline 5: Transmission are met and modeled in AURORA. Transmission assumptions for supply-side
resources and market access are included in Chapter 7. Transmission Planning. Transportation for natural gas is discussed in Chapter 8.
Planning Period Forecasts.

Guideline 6: Conservation
a. Each utility should ensure that a conservation potential study is conducted periodically for its
entire service territory.
Idaho Power response:
The contractor-provided conservation potential study for the 2023 IRP is described in Chapter 6. Demand-Side Resources and is
included as Appendix B: DSM Annual Report.

b. To the extent that a utility controls the level of funding for conservation programs in its service
territory, the utility should include in its action plan all best cost/risk portfolio conservation
resources for meeting projected resource needs, specifying annual savings targets.
Idaho Power response:
A recast for energy efficiency is provided in Chapter 6. Demand-Side Resources. The load forecast put into AURORA included the
reduction to customer sales of all future achievable economic energy efficiency potential.

c. To the extent that an outside party administers conservation programs in a utility’s service
territory at a level of funding that is beyond the utility’s control, the utility should:
• Determine the amount of conservation resources in the best cost/risk portfolio without
regard to any limits on funding of conservation programs; and
Compliance with State of Oregon IRP Guidelines
2023 Integrated Resource Plan—Appendix C Page 105
• Identify the preferred portfolio and action plan consistent with the outside party’s
projection of conservation acquisition.
Idaho Power response:
Idaho Power administers all its conservation programs except market transformation. Third-party market transformation savings are
provided by the Northwest Energy Efficiency Alliance (NEEA) and are discussed in Appendix B: Idaho Power’s Demand-Side
Management 2020 Annual Report. NEEA savings are included as savings to meet targets because of the overlap of NEEA initiatives and
IPC’s most recent potential study.

Guideline 7: Demand Response
Plans should evaluate demand response resources, including voluntary rate programs, on par with
other options for meeting energy, capacity, and transmission needs (for electric utilities) or gas
supply and transportation needs (for natural gas utilities).
Idaho Power response:
Idaho Power’s examination of the potential for expanded DR resources is presented in Chapter 6. Demand-Side Resources.

Guideline 8: Environmental Costs
a. Base case and other compliance scenarios: The utility should construct a base-case scenario to
reflect what it considers to be the most likely regulatory compliance future for carbon dioxide
(CO2), nitrogen oxides, sulfur oxides, and mercury emissions. The utility should develop several
compliance scenarios ranging from the present CO2 regulatory level to the upper reaches of
credible proposals by governing entities. Each compliance scenario should include a time profile
of CO2 compliance requirements. The utility should identify whether the basis of those
requirements, or “costs,” would be CO2 taxes, a ban on certain types of resources, or CO2 caps
(with or without flexibility mechanisms such as an allowance for credit trading as a safety
valve). The analysis should recognize significant and important upstream emissions that would
likely have a significant impact on resource decisions. Each compliance scenario should
maintain logical consistency, to the extent practicable, between the CO2 regulatory
requirements and other key inputs.
Idaho Power response:
The carbon price forecasts used in the 2023 IRP are found in Chapter 9. Portfolios. Compliance with existing environmental regulation
and emissions for each portfolio are discussed in Chapter 10. Modeling Analysis. Emissions for each portfolio are shown in Appendix C:
Technical Appendix, Portfolio Emissions Forecast.

b. Testing alternative portfolios against the compliance scenarios: The utility should estimate,
under each of the compliance scenarios, the present value revenue requirement (PVRR) costs
and risk measures, over at least 20 years, for a set of reasonable alternative portfolios from
Compliance with State of Oregon IRP Guidelines
Page 106 2023 Integrated Resource Plan—Appendix C
which the preferred portfolio is selected. The utility should incorporate end-effect
considerations in the analyses to allow for comparisons of portfolios containing resources with
economic or physical lives that extend beyond the planning period. The utility should also
modify projected lifetimes as necessary to be consistent with the compliance scenario under
analysis. In addition, the utility should include, if material, sensitivity analyses on a range of
reasonably possible regulatory futures for nitrogen oxides, sulfur oxides, and mercury to further
inform the preferred portfolio selection.
Idaho Power response:
See Chapter 9. Portfolios and Chapter 10. Modeling Analysis for discussion on the various scenarios and comparative analysis of the scenarios. Economic lives were adjusted based on portfolio conditions.

c. Trigger point analysis: The utility should identify at least one CO2 compliance “turning point”
scenario, which, if anticipated now, would lead to, or “trigger” the selection of a portfolio of
resources that is substantially different from the preferred portfolio. The utility should develop
a substitute portfolio appropriate for this trigger-point scenario and compare the substitute
portfolio’s expected cost and risk performance to that of the preferred portfolio – under the
base case and each of the above CO2 compliance scenarios. The utility should provide its
assessment of whether a CO2 regulatory future that is equally or more stringent that the
identified trigger point will be mandated.
Idaho Power response:
See Chapter 9. Portfolios and Chapter 10. Modeling Analysis for discussion on the various scenarios and comparative analysis of
the scenarios.

d. Oregon compliance portfolio: If none of the above portfolios is consistent with Oregon energy
policies (including state goals for reducing greenhouse gas emissions) as those policies are
applied to the utility, the utility should construct the best cost/risk portfolio that achieves that
consistency, present its cost and risk parameters, and compare it to those in the preferred and
alternative portfolios.
Idaho Power response:
The company evaluated “100% Clean by 2035” and “100% Clean by 2045” scenarios. The results of the portfolios are presented in Appendix C: Technical Appendix, Long-Term Capacity Expansion Results..

Guideline 9: Direct Access Loads
An electric utility’s load-resource balance should exclude customer loads that are effectively
committed to service by an alternative electricity supplier.
Compliance with State of Oregon IRP Guidelines
2023 Integrated Resource Plan—Appendix C Page 107
Idaho Power response:
Idaho Power does not have any customers served by alternative electricity suppliers and no direct access loads.

Guideline 10: Multi-state Utilities
Multi-state utilities should plan their generation and transmission systems, or gas supply and
delivery, on an integrated-system basis that achieves a best cost/risk portfolio for all their
retail customers.
Idaho Power response:
Idaho Power’s analysis was performed on an integrated-system basis discussed in Chapter 10. Modeling Analysis. Idaho Power will file
the 2023 IRP in both the Idaho and Oregon jurisdictions.

Guideline 11: Reliability
Electric utilities should analyze reliability within the risk modeling of the actual portfolios being
considered. Loss of load probability, expected planning reserve margin, and expected and worst-
case unserved energy should be determined by year for top-performing portfolios. Natural gas
utilities should analyze, on an integrated basis, gas supply, transportation, and storage, along with
demand-side resources, to reliably meet peak, swing, and base-load system requirements.
Electric and natural gas utility plans should demonstrate that the utility’s chosen portfolio achieves
its stated reliability, cost, and risk objectives.
Idaho Power response:
The capacity planning margin and regulating reserves are discussed in Chapter 9. Portfolios. A loss of load expectation analysis to
determine the company’s annual capacity positions is discussed in Chapter 10. Modeling Analysis and Appendix C: Technical Appendix,
Loss of Load Expectation.

Guideline 12: Distributed Generation
Electric utilities should evaluate distributed generation technologies on par with other supply-side
resources and should consider, and quantify where possible, the additional benefits of distributed
generation.
Idaho Power response:
Distribution-connected storage technologies were evaluated in Chapter 5. Future Supply-Side Generation and Storage Resources and in
Chapter 8. Planning Period Forecasts.

Guideline 13: Resource Acquisition
a. An electric utility should, in its IRP:
• Identify its proposed acquisition strategy for each resource in its action plan.
Compliance with State of Oregon IRP Guidelines
Page 108 2023 Integrated Resource Plan—Appendix C
• Assess the advantages and disadvantages of owning a resource instead of purchasing power
from another party.
• Identify any Benchmark Resources it plans to consider in competitive bidding.
Idaho Power response:
Idaho Power identifies its proposed acquisition strategy in Chapter 11. Preferred Portfolio and Action Plan. Idaho Power follows an all-source RFP process where possible to acquire resources which may or may not be owned by the company and are evaluated to provide maximum benefit to its customers.

b. Natural gas utilities should either describe in the IRP their bidding practices for gas supply and
transportation, or provide a description of those practices following IRP acknowledgment.
Idaho Power response:
Not applicable to Idaho Power.

Compliance with EV Guidelines
2023 Integrated Resource Plan—Appendix C Page 109
COMPLIANCE WITH EV GUIDELINES
Guideline 1: Forecast the Demand for Flexible Capacity
Forecast the Demand for Flexible Capacity: The electric utilities shall forecast the balancing
reserves needed at different time intervals (e.g., ramping needed within 5 minutes) to respond to
variation in load and intermittent renewable generation over the 20-year planning period;
Idaho Power response:
A discussion of Idaho Power’s analysis for the flexibility guideline is provided in Chapter 9. Portfolios.

Guideline 2: Forecast the Supply for Flexible Capacity
Forecast the Supply of Flexible Capacity: The electric utilities shall forecast the balancing reserves
available at different time intervals (e.g., ramping available within 5 minutes) from existing
generating resources over the 20-year planning period;
Idaho Power response:
A discussion of the capacity planning reserve margin and regulating reserves is found at Chapter 9. Portfolios.

Guideline 3: Evaluate Flexible Resources on a Consistent and
Comparable Basis
In planning to fill any gap between the demand and supply of flexible capacity, the electric utilities
shall evaluate all resource options, including the use of EVs, on a consistent and comparable basis.
Idaho Power response:
Future supply-side resource options are discussed in Chapter 5. Future Supply Side Generation and Storage Resources. Future demand-
side resource options are discussed in Chapter 6. Demand-Side Resources. Demand response storage-related programs, like EVs could provide, were modeled; this is discussed in Chapter 6. Demand-Side Resources.

State of Oregon Action Items
Page 110 2023 Integrated Resource Plan—Appendix C
STATE OF OREGON ACTION ITEMS REGARDING
IDAHO POWER’S 2021 IRP
Action Item 1: B2H
Conduct ongoing Boardman to Hemingway (B2H) permitting activities. Negotiate and execute B2H
partner construction agreements. Once the agreements are in place, file for a certificate of public
convenience and necessity with state Commissions.
Idaho Power response:
Discussions of Idaho Power’s B2H permitting activities, partner construction agreements, and CPCN filings are included in Chapter 7:
Transmission Planning.

Action Item 2: SWIP–North
Discuss partnership opportunities related to SWIP-North with the project developer for more
detailed evaluation in future IRPs with the condition that Idaho Power study the impact of the
Greenlink transmission projects in reducing congestion between Idaho Power's service territory
and southern wholesale energy markets.
Idaho Power response:
Opportunities related to SWIP-North are discussed in Chapter 7: Transmission Planning. Idaho Power also discusses SWIP-North and its impact on congestion and southern market opportunity in Chapter 7: Transmission Planning.

Action Item 3: Jackpot Solar
Solar is contracted to provide 120 MW starting December 2022. Work with the developer to
determine, if necessary, mitigating measures if the project cannot meet the negotiated timeline.
Idaho Power response:
Not applicable. Jackpot Solar began commercial operations in December 2022, as scheduled.

Action Item 4: Jim Bridger Units 1 and 2
Plan and coordinate with PacifiCorp and regulators for conversion to natural gas operation with a
2034 exit date for Bridger Units 1 and 2. The conversion is targeted before the summer peak
of 2024.
Idaho Power response:
In Chapter 5: Future Supply-Side Generation and Storage Resources, Idaho Power discusses its plans with PacifiCorp to convert Bridger
Units 1 and 2 to natural gas operation in 2024. Coordination with PacifiCorp has led to a scheduled exit date of 2037 for Bridger Units
1 and 2.

State of Oregon Action Items
2023 Integrated Resource Plan—Appendix C Page 111
Action Item 5: 2024 and 2025 RFP
Issue a Request for Proposal (“RFP”) to procure resources to meet identified deficits in 2024
and 2025.
Idaho Power response:
Idaho Power completed an RFP process to meet the deficits identified in 2024 and 2025.

Action Item 6: Jim Bridger Units 3 and 4
Plan and coordinate with PacifiCorp and regulators for the exit/closure of Bridger Unit 3 by year-
end 2025 with Bridger Unit 4 following the Action Plan window in 2028.
Idaho Power response:
In Chapter 5: Future Supply-Side Generation and Storage Resources, Idaho Power discusses updates to its plans with PacifiCorp
regarding Bridger Units 3 and 4 conversion/exit dates.

Action Item 7: Demand Response
Redesign existing DR programs then determine the amount of additional DR necessary to meet the
identified need.
Idaho Power response:
Idaho Power discusses its existing DR programs in Chapter 6: Demand-Side Resources. The amount of additional DR necessary to meet the identified need is included in Chapter 11: Preferred Portfolio and Action Plan.

Action Item 8: B2H
Conduct preliminary construction activities, acquire long lead materials, and construct the
B2H project.
Idaho Power response:
Updates regarding B2H construction activities are included in Chapter 7: Transmission Planning.

Action Item 9: Energy Efficiency
Implement cost-effective energy efficiency measures each year as identified in the energy
efficiency potential assessment.
Idaho Power response:
Idaho Power’s implementation of cost-effective energy efficiency measures is discussed in Chapter 6: Demand-Side Resources.

State of Oregon Action Items
Page 112 2023 Integrated Resource Plan—Appendix C
Action Item 10: Large-Load Customers
Work with large-load customers to support their energy needs with solar resources.
Idaho Power response:
Idaho Power’s Clean Energy Your Way–Construction program supports Idaho-based large-load customers’ energy needs with
renewable resources, including solar. The program is described in more detail in Chapter 3: Clean Energy & Climate Change.
Examples of Clean Energy Your Way–Construction projects are included in Chapter 4: Idaho Power Today.

Action Item 11: Storage Projects
Finalize candidate locations for distributed storage projects and implement where possible to defer
T&D investments as identified in the Action Plan.
Idaho Power response:
The implementation of four distribution-connected storage projects is discussed in Chapter 5: Future Supply-Side Generation and
Storage Resources. The four projects are expected to be online in fall of 2023, and are located at Filer, Weiser, Melba, and Elmore
substations.

Action Item 12: Valmy Unit 2
Exit Valmy unit 2 by December 31, 2025.
Idaho Power response:
The Executive Summary discusses Idaho Power’s updated plans regarding Valmy Unit 2 exit/conversion.

Action Item 13: Jim Bridger Unit 3
Subject to coordination with PacifiCorp, and B2H in-service prior to summer 2026, exit Bridger
Unit 3 by December 31, 2025.
Idaho Power response:
Idaho Power describes its updated plan with PacifiCorp regarding Bridger Unit 3 exit/conversion date in the Executive Summary.

Additional Recommendation 1: B2H
Direct Idaho Power to produce a fresh, rigorous estimate of the total cost of B2H and all associated
swaps and investments, breaking the total cost down by component, disclosing all data and
assumptions for each estimated component cost, and model cost contingencies based on this
updated total cost estimate for the 2023 IRP or sooner if necessary to support procurement
actions.
State of Oregon Action Items
2023 Integrated Resource Plan—Appendix C Page 113
Idaho Power response:
B2H cost estimates were updated as of September 2023 and are included in Chapter 7: Transmission Planning. B2H-related swaps and
investments, breaking the total down by component, and disclosing all data and assumptions for each estimated component cost were provided in OPUC Docket No. PCN 5 to support procurement actions.

Additional Recommendation 2: Wholesale Prices
Direct Idaho Power to work with stakeholders and demonstrate the impact of extremely high
wholesale electricity prices and decreased liquidity on resource selection in the 2023 IRP.
In addition, Idaho Power shall provide insight into volatility and need.
Idaho Power response:
Idaho Power worked with members of IRPAC to change its stochastic analysis to help incorporate a greater range of wholesale
electricity prices derived from modeled periods of decreased liquidity in wholesale markets. The changes to the stochastic analysis
generated a wide range of electricity prices and their influence on portfolio cost can be found in Appendix C: Technical Appendix,
Stochastic Risk Analysis.

Additional Recommendation 3: Grant Opportunities
Direct Idaho Power to document the Company’s monitoring and pursuit of grant opportunities in
the regular reporting on transmission projects under Docket No. RE 136, including the items
bulleted in Staff’s Report.
Idaho Power response:
The monitoring and pursuit of Idaho Power’s grant opportunities are discussed in Chapter 7: Transmission Planning.

Additional Recommendation 4: Demand Response
Direct Idaho Power to model new DR for the 2023 IRP based on the results of the IPC-specific DR
potential study expected to be complete in the fall of 2022. Results should include exploring
whether current programs have additional potential, additional kinds of DR programs including
pricing programs, and more accurately estimating costs of future programs.
Idaho Power response:
Idaho Power completed the potential study and modeled new and expanded DR in the 2023 IRP; DR resource potential is discussed in
Chapter 6: Demand-Side Resources.

Additional Recommendation 5: Large-Load Customers
For all clean energy special contracts with large load customers, direct Idaho power to include
large-load customer resource acquisition sizing and timing needs in the 2023 IRP Action Plan in a
manner that does not compromise Idaho Power or customer confidentiality.
State of Oregon Action Items
Page 114 2023 Integrated Resource Plan—Appendix C
Idaho Power response:
Clean Energy Your Way special contract timing needs are included in the Action Plan and can be found in the Executive Summary.
Additionally, existing Clean Energy Your Way–Construction projects are discussed in Chapter 3: Clean Energy & Climate Change.

Additional Recommendation 6: WRAP
Direct Idaho Power to continue to explore how participating in the WRAP may alter transmission
assumptions and implications for capacity contracts.
Idaho Power response:
Idaho Power provides a brief overview of WRAP in Chapter 2: Political, Regulatory, and Operational Considerations. Additionally,
WRAP modeling assumptions are discussed in this appendix. As WRAP operations continue to mature, Idaho Power will monitor how
participating in WRAP may alter planning assumptions.

Additional Recommendation 7: Reliability
Direct Idaho Power to include all necessary resources in scored portfolios to meet the Company’s
reliability standard.
Idaho Power response:
All main cases in the 2023 IRP include the resources necessary to produce an annual capacity position of surplus (to meet
Idaho Power’s 0.1 event-day/year LOLE threshold).

Additional Recommendation 8: QF Renewal Rate
Direct Idaho Power to revisit the assumed renewal rate of wind QFs.
Idaho Power response:
Idaho Power addresses the assumed renewal rates of wind QFs in Chapter 9: Portfolios. Idaho Power and IRPAC revisited the wind QF renewal rates, and the company conducted the New Forecasted PURPA scenario based on their input.

Additional Recommendation 9: QF Forecast
Direct Idaho Power to work with Staff and stakeholders to develop a reasonable forecast of new
QFs in the 2023 IRP.
Idaho Power response:
Idaho Power addresses the QF forecast in Chapter 9: Portfolios. Idaho Power worked with IRPAC to add a QF forecast, and the
company conducted the New Forecasted PURPA scenario based on their input.

Additional Recommendation 10: GHG Emissions
Direct Idaho Power to include, in the executive summary of the Company’s 2023 IRP, a graph
showing Idaho Power’s GHG emissions for 2019-2022 and comparing those historical emissions to
State of Oregon Action Items
2023 Integrated Resource Plan—Appendix C Page 115
the IRP 20-year forecast of IRP emissions calculated in a reasonably similar method. The data
should include emissions from market purchases and remove emissions from market sales.
Idaho Power response:
Idaho Power included a GHG historical/forecast comparison graph in the Executive Summary.

Additional Recommendation 11: Green Hydrogen Proxy
Direct Idaho Power to include the most reasonable proxy of green hydrogen as a potential resource
in its next IRP, either available for selection in a portfolio or in a sensitivity.
Idaho Power response:
Idaho Power modeled green hydrogen resources in portfolios and sensitivities for the 2023 IRP.

State of Oregon Action Items
Page 116 2023 Integrated Resource Plan—Appendix C

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-23-23

IDAHO POWER COMPANY

ATTACHMENT 2

IRP COMMITMENTS AND COMPLIANCE
1 

Idaho 
Reference Topic  IRP Requirement, Recommendation or Commitment  How the Item is Addressed in the 2023 IRP 
Order No. 35603, p. 4 Jim Bridger Units Develop a Bridger exit agreement with PacifiCorp that 
determines potential costs of extending or exiting operations 
early similar to the exit agreement developed for the closure of 
Valmy and incorporate those costs into its coal plant exit costs to 
properly value different exit dates in its 2023 IRP. 
In Chapter 5: Future Supply‐Side Generation and Storage Resources, 
Idaho Power discusses its plans with PacifiCorp to convert Bridger Units 
1 and 2 to natural gas operation in 2024. Coordination with PacifiCorp 
has led to a scheduled exit date of 2037 for Bridger Units 1 and 2. 
Additionally, Idaho Power discusses updates to its plans with PacifiCorp 
regarding Bridger Units 3 and 4 conversion/exit dates.  
Order No. 35603, p. 4 Extreme 
Weather 
Incorporate extreme weather events and variability of water 
availability through its load and resource input assumptions, 
rather than compensating by changing the LOLE reliability target, 
which should be set as a matter of public policy. 
In Chapter 8: Planning Period Forecasts, Idaho Power discusses its 70th 
percentile load forecast and how it accounts for load variability due to 
weather events. A more detailed discussion of Idaho Power’s weather‐
based probabilistic scenarios and seasonal peaks is included in Appendix 
A—Sales and Load Forecast. In the Loss of Load Expectation section of 
Appendix C—Technical Report, Idaho Power also discusses its utilization 
of a 0.1 event‐days per year LOLE threshold for the 2023 IRP. 
Order No. 35603, p. 4 Market Access Only include market access backed by firm transmission 
reservations in its Load and Resource Balance. 
In the Existing Transmission Capacity for Firm Market Imports section of 
Chapter 7: Transmission Planning, Idaho Power describes the existing 
transmission modeled in the 2023 IRP that provides transmission 
capacity for firm market imports.  
Order No. 35603, p. 4 PRM Evaluate the risks and inaccuracies caused by using a single 
benchmark year (2023) to determine the LOLE‐based Planning 
Reserve Margin. 
In the Capacity Planning Reserve Margin section of Chapter 9: Portfolios, 
Idaho Power explains the implementation of LOLE‐based seasonal 
Planning Reserve Margin calculations performed at different points 
along the planning horizon for utilization in the AURORA LTCE model. 
Additional information regarding the LOLE methodology can be found in 
the Loss of Load Expectation section of Appendix C—Technical Report.  
Order No. 35603, p. 4 Validation and 
Verification 
Provide a comprehensive Quality Assurance plan to verify and 
validate its models by describing the purpose of each test, how 
the test was conducted, and the result. 
Idaho Power provides details regarding its verification tests and overall 
validation and verification process in Chapter 9: Portfolios with resource 
buildouts located in Appendix C—Technical Report. Additionally, in 
Chapter 10: Modeling Analysis, Idaho Power provides a qualitative risk 
analysis and comparison for different portfolio buildouts analyzed in the 
2023 IRP.  
Order No. 35603, p. 4 Flexible 
Resource 
Strategy 
Study the costs and benefits of implementing a flexible resource 
strategy. 
In Chapter 11: Preferred Portfolio and Near‐Term Action Plan, Idaho 
Power describes the flexible resource strategy identified in the Preferred 
Portfolio and compares the costs and benefits of the Preferred Portfolio 
to varying future scenarios analyzed in the 2023 IRP.  

2 

Oregon 
Reference Topic  IRP Requirement, Recommendation or Commitment  How the Item is Addressed in the 2023 IRP 
Order No. 23‐004, 
Appendix A, p. 8 
Jim Bridger Units 
1 and 2 
Plan and coordinate with PacifiCorp and regulators for 
conversion to natural gas operation with a 2034 exit date for 
Bridger Units 1 and 2. The conversion is targeted before the 
summer peak of 2024. 
In Chapter 5: Future Supply‐Side Generation and Storage Resources, 
Idaho Power discusses its plans with PacifiCorp to convert Bridger Units 
1 and 2 to natural gas operation in 2024. Coordination with PacifiCorp 
has led to a scheduled exit date of 2037 for Bridger Units 1 and 2.  
Order No. 23‐004, 
Appendix A, p. 8 
Jim Bridger Units 
3 and 4  
Plan and coordinate with PacifiCorp and regulators for the 
exit/closure of Bridger Unit 3 by year‐end 2025 with Bridger Unit 
4 following the Action Plan window in 2028. 
In Chapter 5: Future Supply‐Side Generation and Storage Resources, 
Idaho Power discusses updates to its plans with PacifiCorp regarding 
Bridger Units 3 and 4 conversion/exit dates.  
Order No. 23‐004, 
Appendix A, p. 8 
Jim Bridger Unit 
3 
Subject to coordination with PacifiCorp, and B2H in‐service prior 
to summer 2026, exit Bridger Unit 3 by December 31, 2025. 
Idaho Power describes its updated plan with PacifiCorp regarding 
Bridger Unit 3 exit/conversion date in the Executive Summary.  
Order No. 23‐004, 
Appendix A, p. 10 
SWIP‐North Discuss partnership opportunities related to SWIP‐North with 
the project developer for more detailed evaluation in future IRPs 
with the condition that Idaho Power study the impact of the 
Greenlink transmission projects in reducing congestion between 
Idaho Power's service territory and southern wholesale energy 
markets. 
Opportunities related to SWIP‐North are discussed in Chapter 7: 
Transmission Planning. Idaho Power also discusses SWIP‐North and its 
impact on congestion and southern market opportunity in Chapter 7: 
Transmission Planning.  
Order No. 23‐004, 
Appendix A, p. 19 and 
Idaho Power’s Reply 
Comments, p. 5  
B2H Conduct ongoing B2H permitting activities. Negotiate and 
execute B2H partner construction agreements. Conduct ongoing 
activities related to petitions for a certificate of public 
convenience and necessity with state commissions.  
Discussions of Idaho Power’s B2H permitting activities, partner 
construction agreements, and CPCN filings are included in Chapter 7: 
Transmission Planning.  
Order No. 23‐004, 
Appendix A, p. 19 
B2H Conduct preliminary construction activities, acquire long lead 
materials, and construct the B2H project. 
Updates regarding B2H construction activities are included in Chapter 7: 
Transmission Planning.  
Order No. 23‐004, 
Appendix A, p. 19 
B2H Direct Idaho Power to produce a fresh, rigorous estimate of the 
total cost of B2H and all associated swaps and investments, 
breaking the total cost down by component, disclosing all data 
and assumptions for each estimated component cost, and model 
cost contingencies based on this updated total cost estimate for 
the 2023 IRP or sooner if necessary to support procurement 
actions. 
B2H cost estimates were updated as of September 2023 and are 
included in Chapter 7: Transmission Planning. B2H‐related swaps and 
investments, breaking the total down by component, and disclosing all 
data and assumptions for each estimated component cost were 
provided in OPUC Docket No. PCN 5 to support procurement actions.  
Order No. 23‐004, 
Appendix A, p. 19 
Wholesale Prices Direct Idaho Power to work with stakeholders and demonstrate 
the impact of extremely high wholesale electricity prices and 
decreased liquidity on resource selection in the 2023 IRP. In 
addition, Idaho Power shall provide insight into volatility and 
need. 
Idaho Power worked with members of IRPAC to change its stochastic 
analysis to help incorporate a greater range of wholesale electricity 
prices derived from modeled periods of decreased liquidity in wholesale 
markets. The changes to the stochastic analysis generated a wide range 
of electricity prices and their influence on portfolio cost can be found in 
Appendix C: Technical Appendix, Stochastic Risk Analysis.  
Order No. 23‐004, 
Appendix A, p. 19 
Grant 
Opportunities 
Direct Idaho Power to document the Company’s monitoring and 
pursuit of grant opportunities in the regular reporting on 
transmission projects under Docket No. RE 136, including the 
items bulleted in Staff’s Report. 
The monitoring and pursuit of Idaho Power’s grant opportunities are 
discussed in Chapter 7: Transmission Planning.  
Order No. 23‐004, 
Appendix A, p. 20 
2024 and 2025 
RFP 
Issue a Request for Proposal (“RFP”) to procure resources to 
meet identified deficits in 2024 and 2025. 
Idaho Power completed an RFP process to meet the deficits identified in 
2024 and 2025.  
3 

Order No. 23‐004, 
Appendix A, p. 23 
Demand 
Response 
Redesign existing DR programs then determine the amount of 
additional DR necessary to meet the identified need. 
Idaho Power discusses its existing DR programs in Chapter 6: Demand‐
Side Resources. The amount of additional DR necessary to meet the 
identified need is included in Chapter 11: Preferred Portfolio and Near‐
Term Action Plan.  
Order No. 23‐004, 
Appendix A, p. 23 
Energy Efficiency Implement cost‐effective energy efficiency measures each year 
as identified in the energy efficiency potential assessment. 
Idaho Power’s implementation of cost‐effective energy efficiency 
measures is discussed in Chapter 6: Demand‐Side Resources.  
Order No. 23‐004, 
Appendix A, p. 23 
Demand 
Response 
Direct Idaho Power to model new DR for the 2023 IRP based on 
the results of the IPC‐specific DR potential study expected to be 
complete in the fall of 2022. Results should include exploring 
whether current programs have additional potential, additional 
kinds of DR programs including pricing programs, and more 
accurately estimating costs of future programs. 
Idaho Power completed the potential study and modeled both the 
potential of existing programs and identified new programs in the 2023 
IRP; DR resource potential is discussed in Chapter 6: Demand‐Side 
Resources.  
Order No. 23‐004, 
Appendix A, p. 24 
Large‐Load 
Customers 
Work with large‐load customers to support their energy needs 
with solar resources. 
Idaho Power’s Clean Energy Your Way – Construction program supports 
Idaho‐based large‐load customers’ energy needs with renewable 
resources, including solar. The program is described in more detail in 
Chapter 3: Clean Energy & Climate Change. Examples of Clean Energy 
Your Way – Construction projects are included in Chapter 4: Idaho Power 
Today.  
Order No. 23‐004, 
Appendix A, p. 24 and 
Idaho Power’s Reply 
Comments, p. 10 
Large‐Load 
Customers 
For all clean energy special contracts with large load customers, 
direct Idaho power to include large‐load customer resource 
acquisition sizing and timing needs in the 2023 IRP Action Plan in 
a manner that does not compromise Idaho Power or customer 
confidentiality.  
Clean Energy Your Way special contract timing needs are included in the 
Action Plan and can be found in the Executive Summary. Additionally, 
existing Clean Energy Your Way – Construction projects are discussed in 
Chapter 3: Clean Energy & Climate Change. 
Order No. 23‐004, 
Appendix A, p. 25 
Valmy Unit 2 Exit Valmy unit 2 by December 31, 2025. The Executive Summary discusses Idaho Power’s updated plans 
regarding Valmy Unit 2 exit/conversion.  
Order No. 23‐004, 
Appendix A, p. 26 
Jackpot Solar  Solar is contracted to provide 120 MW starting December 2022. 
Work with the developer to determine, if necessary, mitigating 
measures if the project cannot meet the negotiated timeline. 
Not applicable. Jackpot Solar began commercial operations in December 
2022, as scheduled.  
Order No. 23‐004, 
Appendix A, p. 27 
Storage Projects  Finalize candidate locations for distributed storage projects and 
implement where possible to defer T&D investments as 
identified in the Action Plan. 
The implementation of four distribution‐connected storage projects is 
discussed in Chapter 5: Future Supply‐Side Generation and Storage 
Resources. The four projects are expected to be online in fall of 2023, 
and are located at Filer, Weiser, Melba, and Elmore substations.  
Order No. 23‐004, 
Appendix A, p. 28 
WRAP Direct Idaho Power to continue to explore how participating in 
the WRAP may alter transmission assumptions and implications 
for capacity contracts. 
Idaho Power provides a brief overview of WRAP in Chapter 2: Political, 
Regulatory, and Operational Considerations. Additionally, WRAP 
modeling assumptions are discussed in this appendix. As WRAP 
operations continue to mature, Idaho Power will monitor how 
participating in WRAP may alter planning assumptions.    
Order No. 23‐004, 
Appendix A, p. 35 
Reliability  Direct Idaho Power to include all necessary resources in scored 
portfolios to meet the Company’s reliability standard. 
All main cases in the 2023 IRP include the resources necessary to 
produce an annual capacity position of surplus (to meet Idaho Power’s 
0.1 event‐day/year LOLE threshold).  
4 

Order No. 23‐004, 
Appendix A, p. 37 
QF Renewal 
Rate 
Direct Idaho Power to revisit the assumed renewal rate of wind 
QFs. 
Idaho Power addresses the assumed renewal rates of wind QFs in 
Chapter 9: Portfolios. Idaho Power and IRPAC revisited the wind QF 
renewal rates, and the company conducted the New Forecasted PURPA 
scenario based on the IRPAC’s input.  
Order No. 23‐004, 
Appendix A, p. 37 and 
Idaho Power’s Reply 
Comments, p. 12 
QF Forecast Direct Idaho Power to work with Staff and stakeholders to 
develop a reasonable forecast of new QFs in the 2023 IRP. 
Idaho Power addresses the QF forecast in Chapter 9: Portfolios. Idaho 
Power worked with IRPAC to add a QF forecast, and the company 
conducted the New Forecasted PURPA scenario based on their input. 
Order No. 23‐004, 
Appendix A, p. 38 and 
Idaho Power’s Reply 
Comments, p. 14 
GHG Emissions Direct Idaho Power to include, in the executive summary of the 
Company’s 2023 IRP, a graph showing Idaho Power’s GHG 
emissions for 2019‐2022 and comparing those historical 
emissions to the IRP 20‐year forecast of IRP emissions calculated 
in a reasonably similar method. The data should include 
emissions from market purchases and remove emissions from 
market sales.  
Idaho Power included a GHG historical/forecast comparison graph in the 
Executive Summary.  
Order No. 23‐004, 
Appendix A, p. 39 
Green Hydrogen 
Proxy 
Direct Idaho Power to include the most reasonable proxy of 
green hydrogen as a potential resource in its next IRP, either 
available for selection in a portfolio or in a sensitivity. 
Idaho Power modeled green hydrogen resources in portfolios and 
sensitivities for the 2023 IRP.