20260814Reply Comments.pdf

04N IQAHO Ro
DONOVAN WALKER
Lead Counsel
dwa I ker(a)idaho power.corn
RECEIVED
AUGUST 14, 2026
August 14, 2026 IDAHO PUBLIC
UTILITIES COMMISSION
VIA ELECTRONIC FILING
Commission 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. I PC-E-26-04
Application of Idaho Power Company for Certificates of Public Convenience
and Necessity for the South Hills and Peregrine Power Plants and for an
Associated Accounting Order
Dear Commission Secretary:
Attached for electronic filing is Idaho Power Company's Reply Comments in the
above matter. The confidential version will be sent to the parties who executed the
Protective Agreement.
If you have any questions about any of the aforementioned documents, please do
not hesitate to contact me.
Very truly yours,
Donovan E. Walker
DEW:cd
Enclosures
1221 W. Idaho St(83702)
P.O. Box 70
Boise, ID 83707

DONOVAN E. WALKER (ISB No. 5921)
Idaho Power Company
1221 West Idaho Street (83702)
P.O. Box 70
Boise, Idaho 83707
Telephone: [phone]
Facsimile: [phone]
dwalker(a-)_idahopower.com
Attorney for Idaho Power Company
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER )
COMPANY'S APPLICATION FOR A ) CASE NO. IPC-E-26-04
CERTIFICATES OF PUBLIC )
CONVENIENCE AND NECESSITY FOR ) IDAHO POWER COMPANY'S
THE SOUTH HILLS AND PEREGRINE ) REPLY COMMENTS
POWER PLANTS AND FOR AN )
ASSOCIATED ACCOUNTING ORDER. )
COMES NOW, Idaho Power Company ("Idaho Power" or "Company"), and,
pursuant to Idaho Public Utilities Commission's ("Commission") Rules of Procedure 201-
204 and the Notice of Modified Procedure, Order No. 37048, hereby respectfully submits
the following Reply Comments in response to Comments filed by Commission Staff
("Staff"), the Idaho Irrigation Pumpers Association, Inc. ("IIPA"), and joint comments by
Renewable Northwest and NW Energy Coalition (together, "Joint Advocates"), on July 31,
2026.
IDAHO POWER COMPANY'S REPLY COMMENTS - 1

Idaho Power initially brought this matter before the Commission through its
Integrated Resource Plan ("IRP") which identified a need for additional resources. The
Company then conducted an extensive competitive bidding process following the
resource procurement rules of the Oregon Public Utility Commission ("OPUC"), as
required by the Idaho Commission at that time, employing a fair and competitive Request
for Proposal ("RFF) process that spanned nearly 18-months, in an effort to acquire
resources necessary to meet capacity deficiencies beginning in 2029.
To meet the identified capacity deficiencies, the Company further evaluated the
final shortlist of bids, noting that the only the remaining battery energy storage system
("BESS") projects would have the potential to fill the capacity deficiencies, but the
economics associated with the battery storage resources remained a concern. That,
coupled with the then recently published 2025 IRP that identified continued increased
peak load and the need for flexible generation resources, led Idaho Power to investigate
alternative resources, including the South Hills plant as a natural gas resource in 2029,
and the Peregrine plant, an alternative gas solution in 2030. The results of the evaluation
indicated the South Hills and Peregrine plants combined could more economically meet
the Company's resource needs by $- over the 20-year planning period as
compared to the next lowest cost portfolio alternative.
The record in this proceeding demonstrates Idaho Power's prompt and prudent
actions in compliance with the Commission's processes and procedures required at the
time for these resource acquisitions. Staff agrees with the identified 2029 and 2030
capacity needs, and that the proposed projects are part of a least-cost, least-risk solution
for meeting those needs, and found that the Company met the necessary regulatory
IDAHO POWER COMPANY'S REPLY COMMENTS - 2

requirements for a CPCN for both the South Hills and Peregrine plants. Staff's criticism
of Idaho Power's efforts monitoring timelines for material procurement in a very restrictive
environment, amidst several dynamic and evolving factors, are unreasonable and
unsupported by the facts. The resources are necessary and required to timely meet Idaho
Power's resource needs and continue to provide reliable and adequate service to the
Company's customers starting in the summer of 2029 and into the future. For these
reasons, the Commission should issue CPCNs for both the South Hills and Peregrine
plants and approve the requested accounting treatment.
I. BACKGROUND
1. Idaho Power closely monitors resource needs and responds with
appropriate urgency to acquire additional low-cost, reliable sources of generation and
capacity, as evidenced by Idaho Power's consecutive requests to acquire resources to
22324252Ebe online in 2023,' 2024, , , , an . In response to resource needs
identified in the 2023 IRP, on August 16, 2024, Idaho Power conducted a competitive
solicitation through the issuance of an All-Source RFP seeking to acquire a combination
of energy and capacity resources. The RFP did not restrict bids based on resource type
or ownership structure, however, Idaho Power outlined that the deficit required a minimum
of approximately 138 megawatts (WW") of incremental capacity needs and 555 MW of
supply-side resource additions in 2028. Further, the 2023 IRP identified incremental
capacity needs of 142 MW in 2029 and 369 MW in 2030, growing to over 1,150 MW by
Case Nos. IPC-E-22-06 and IPC-E-22-13.
2 Case Nos. IPC-E-23-05 and IPC-E-23-20.
3 Case Nos. IPC-E-22-29 and IPC-E-23-20.
4 Case Nos. IPC-E-24-12, IPC-E-24-16, and IPC-E-24-45.
5 Case Nos. IPC-E-24-42, IPC-E-25-10, and IPC-E-25-27.
6 Case No. IPC-E-25-29 and IPC-E-26-20.
IDAHO POWER COMPANY'S REPLY COMMENTS - 3

2038. The Company accepted energy or capacity incremental to its system beginning in
the summer 2028 timeframe and beyond, from market energy purchases or new or
existing resources.
2. The 2023 IRP Preferred Portfolio included the addition of large quantities of
cost-effective clean resources including solar, wind, battery storage, energy efficiency,
peaking hydrogen, incremental demand response and geothermal. Subsequently, the
Company's 2025 IRP identified increased incremental capacity needs of 192 MW in 2029
and 380 MW in 2030 with a total shortfall exceeding 1,000 MW by 2040. While the 2025
IRP Preferred Portfolio included solar, storage, wind, energy efficiency, and incremental
demand response, it also included 550 MW of incremental natural gas as cost-effective
resource additions.
3. The evaluation of the RFP bids was bifurcated, with prioritization of the 2028
bids in order to meet summer demand in 2028, followed by evaluation of the bids with a
commercial operation date after April 1, 2028 ("Beyond April 2028 Bids"). Idaho Power's
discussion in this case is specific to the evaluation of the Beyond April 2028 Bids for which
the Company ultimately received approval by the OPUC7 of the final shortlist of bids with
a commercial operation date no later than June 1, 2029 ("2029 Bids") to meet the
identified capacity deficits. Once the most cost-effective projects were identified, the
Company's Internal Bid Team was provided Notice to Proceed with the Bennett Gas
Expansion Project for which the Commission granted a CPCN in Case No. IPC-E-25-29.
In addition, Idaho Power began negotiations with the second-ranked project, the Bluebird
Project, for a 200 MW solar photovoltaic facility that supplies energy to the Company's
OPUC Order No. 25-327, Docket UM 2317, Aug. 30, 2025.
IDAHO POWER COMPANY'S REPLY COMMENTS -4

system and a battery storage facility supplying 100 MW of capacity to Idaho Power, for
which the Company has requested approval of the associated Power Purchase
Agreement and Energy Storage System Tolling Agreement in Case No. IPC-E-26-20.
4. To meet the remaining identified capacity deficiencies beginning in 2029,
the Company further evaluated the 2029 Bids final shortlist, noting that only the remaining
battery storage projects would have the potential to fill the capacity deficiencies. However,
due to concerns with the economics of the battery storage projects, as well as the then
recently published 2025 IRP that identified continued increased peak load and the need
for flexible generation resources, Idaho Power investigated additional alternative
resources, including the benchmark bid on the 2029 final shortlist that identified a
transition from the planned battery storage to a natural gas resource in 2029, the South
Hills plant, as well as an alternative gas resource solution in 2030, the Peregrine plant.
The South Hills plant will consist of twelve, fast-ramping, natural gas-fueled reciprocating
engines that are flexible enough to provide up to 222 MW of generation with a commercial
operation date of June 1, 2029. The Peregrine plant will use the H Frame simple cycle
combustion turbine technology, providing 430 MW of nameplate generation, and will have
a commercial operation date of June 1, 2030.
5. Idaho Power records the accumulation of all costs associated with the
construction of an asset, including the cost of financing the construction expenditures, or
Allowance for Funds Used During Construction ("AFUDC"), in Federal Energy Regulatory
Commission ("FERC")Account 107 — Construction Work in Progress ("CWIP"). When the
plant is completed and placed in service, the total cost of the plant, including AFUDC, is
moved to FERC Account 101 — Electric Plant-in-Service, placing the asset in rate base.
IDAHO POWER COMPANY'S REPLY COMMENTS - 5

The Company typically commences accrual of AFUDC as soon as funds are expended
and committed to a construction project, which, for generation resources, has typically
occurred subsequent to the request for a CPCN.
6. Based on industry demand for long-lead materials, and to ensure
commercial operation dates are met, the Company has been incurring capital
expenditures associated with resource procurements prior to filing a request for a CPCN.
In order to secure a position in the queue to purchase the turbine for Peregrine, Idaho
Power was required to make a down payment in June 2025. In addition, a payment for
the reciprocating engines for South Hills was made in June 2026. These down payments
are necessary to ensure the plants will be operational in time to meet the identified
capacity needs. Because Idaho is incurring costs associated with resource procurements
prior to receiving a CPCN, the Company is requesting the Commission acknowledge it is
appropriate to begin the accrual of AFUDC once South Hills and Peregrine had been
deemed viable and expenditures associated with the resource procurements have been
incurred.
7. On March 10, 2026, Idaho Power submitted an Application to the
Commission for an order: (1) granting a CPCN for South Hills, a cost-effective natural
gas-fueled facility providing up to 222 MW of nameplate generation to meet an identified
capacity deficit in 2029, (2) granting a CPCN for Peregrine, a cost-effective natural gas-
fueled facility providing 430 MW of nameplate generation to meet an identified capacity
deficit in 2030, and (3) confirmation of the Company's application of accrual of AFUDC
for the South Hills and Peregrine plants to coincide with initial procurement activities for
the natural gas-fueled facilities.
IDAHO POWER COMPANY'S REPLY COMMENTS - 6

8. On July 31, 2026, Comments were filed by Staff, IIPA and the Joint
Advocates. In addition, as of August 4, 2026, Idaho Power had received 186 public
comments, the majority of which include similar form language ("Public Commentors"). In
their Comments, Staff recommends the Commission (1) issue CPCNs for both South Hills
and Peregrine, (2) deny AFUDC accrual until issuance of a final order granting a CPCN
for each facility occurs, (3) establish separate caps on the cost recovery of South Hills
and Peregrine, (4) direct the Company to provide a detailed plan to resolve any system
capacity deficit, and (5) direct Idaho Power to ensure all costs associated with South Hills
and Peregrine, inclusive of related or enabling investments, are fully captured and tracked
in the Company's records.$ The IIPA does not contest the issuance of CPCNs for South
Hills or Peregrine but highlights how the record in this proceeding may affect future rate
design, cost-of-service allocation, and cost recovery in the event CPCNs are issued.9 The
Joint Advocates recommend the Commission deny the CPCNs for South Hills and
Peregrine.10 Finally, the Public Commentors proposed the Commission reject the
Company's request for CPCNs.
9. In these Reply Comments, Idaho Power responds to the recommendations
offered by Staff, addresses IIPA's concerns regarding the effect the procurement of the
resources has on future rate design, cost-of-service allocation, and cost recovery, and
responds to the Joint Advocates' support for rejection of the CPCNs. The Company
respectfully requests the Commission (1) accept Staff's recommendation to issue CPCNs
for the South Hills and Peregrine plants, (2) accept the Company's request to approve
8 Staff Comments, page 22.
9 IIPA Comments, page 1.
10 Joint Advocates, pages 2-3.
IDAHO POWER COMPANY'S REPLY COMMENTS - 7

the commencement of the accrual of AFUDC on capital expenditures associated with the
South Hills and Peregrine plants upon initial procurement activities, and (3) reject Staff's
proposed cost cap and the Joint Advocates' unwarranted reevaluation of resource
options.
II. REPLY COMMENTS
A. The Commission should adopt Staff's recommendation to issue CPCNs for
the South Hills and Peregrine plants.
10. In order to comply with its continuing obligation to serve all customers
located in its certificated service territory, the Company must at times acquire additional
resources to meet the identified capacity deficits on its system when the need arises. On
February 29, 2024, Idaho Power commenced a competitive bidding process, filing a
request with the OPUC to (1) approve the selection of London Economics International
LLC ("LEI") as the Independent Evaluator ("IE") for the RFP, (2) approve the proposed
RFP scoring and modeling methodology, (3) approve the draft RFP, and (4) waive certain
competitive bidding rules to allow for expedited review and approval of the RFP. On April
30, 2024, the OPUC approved the selection of LEI as the IE for Idaho Power's RFP and
evaluation of RFP resources. The OPUC also approved the concurrent review of both the
scoring and modeling methodologies and preparation of the draft RFP.
11. Idaho Power performed a quantitative and qualitative evaluation with an
objective scoring methodology to reasonably evaluate the price and non-price attributes
of the Beyond April 2028 Bids submitted through the RFP process, which included 83
proposals from 18 different bidders, with a total of 117 resource bids, ultimately identifying
the 2029 Bids final shortlist of projects with commercial operation by June 1, 2029. As
required under the OPUC competitive bidding rules, the final shortlist was submitted for
IDAHO POWER COMPANY'S REPLY COMMENTS - 8

OPUC review and on August 19, 2025, the OPUC acknowledged the 2029 Bids final
shortlist.
12. Following procurement of the two most-cost effective projects on the 2029
Bids final shortlist, Idaho Power evaluated the feasibility of the remaining projects,
determining that, due to the decrease in the Effective Load Carrying Capability ("ELCC")
of new solar projects on Idaho Power's system, and the limited ELCC of wind resources,
the remaining BESS projects, two additional standalone BESS projects, and the
combined solar plus BESS project, would be necessary additions to help fill the 2029
capacity deficiency, and requested updated pricing or general project updates to further
assess the cost-effectiveness of each BESS project. In addition, based on the
identification in the recently published 2025 IRP of the need for dispatchable, flexible
resources to meet increasing system demand and maintain reliability while providing a
significant capacity benefit, Idaho Power investigated additional alternative resources,
including the viability of dispatchable resources. Ultimately, the results of the evaluation
indicated the South Hills and Peregrine plants combined could more economically meet
the Company's resource needs by $- over the 20-year planning period, as
compared to the remaining viable 2029 Bids final shortlist projects.
13. Idaho Power appreciates Staff's review of the Company's request in this
case and their recommended issuance of CPCNs for both the South Hills and Peregrine
plants. Staff performed a comprehensive review and analysis in this proceeding, finding
that the updated load and resource assumptions utilized by Idaho Power, and the
resulting 236 MW deficit in 2029 and 352 MW deficit in 2030, are reasonable, confirming
that "large and growing capacity deficits exist in 2029 and 2030 and therefore additional
IDAHO POWER COMPANY'S REPLY COMMENTS - 9

system resources are necessary."" Next, Staff carefully assessed the Company's
remaining feasible projects from the 2029 Bids final shortlist and agreed that the projects
were "not capable of serving the new load without the assistance of at least one new gas
resource" and noting that they agree Idaho Power"had insufficient time to solicit new bids
for additional resources" as well.12
14. Further, "Staff carefully reviewed the Company's economic analyses,"
agreeing that "the Company properly performed an economic analysis . . . based on
reasonable assumptions," scrutinizing the cost of the resources, the portfolio cost
calculations, and adjustments made for gas pipeline costs, tax credit repeals, and import
tariffs, finding that the South Hills and Peregrine plants "are more cost-effective than the
best feasible alternative.1113 Staff concluded that based on the identified 2029 and 2030
capacity deficits, "the only feasible solution involve[s] South Hills or Peregrine, and the
most economical solution include[s] both," agreeing that the proposed projects are part
of a least-cost, least-risk solution.14 Following the thorough review, Staff determined that
the "Company has met the necessary regulatory requirements for a CPCN1115 for both the
South Hills and Peregrine plants.
B. Idaho Power's diligent efforts monitoring timelines in a very restrictive
procurement environment, amidst several dynamic and evolving factors, led
to the identification of two least-cost, least-risk natural gas-fueled resource
alternatives.
15. Idaho Power is in a period of unprecedented demand growth that is
expected to continue over the next several years. Since 2021, Idaho Power has been
11 Staff Comments, page 3.
12 Id., page 6.
13 Id., pages 6-7.
14 Id., page 7.
1s Id.
IDAHO POWER COMPANY'S REPLY COMMENTS - 10

promptly initiating the competitive solicitation process upon identification of annual
capacity deficiencies, first following the 2021 IRP for 2023 through 2027 resources, and
subsequently with the 2023 IRP for 2028 and 2029 resources, and most recently with the
2025 IRP for 2030 and beyond resources.16 Despite considerable investment and
expansion in generation resources in recent years, Idaho Power's system today is fully
utilized by current customers.
16. Although competitive solicitations are occurring right after identification of
capacity deficiencies, many of the resources selected through the extensive RFP process
are not able to come online as expected due to several converging factors outside Idaho
Power's control. The Company's load growth across multiple customer sectors, combined
with rising costs, permitting obstacles, supply chain constraints, and constrained system
capacity, is posing significant challenges for Idaho Power and third-party developers in
bringing resources online in time to meet identified capacity deficiencies.
17. More specifically, since the Company commenced the competitive
solicitation process for new resources, changes in federal legislation and executive action
have occurred impacting commercial operation dates and/or the economics of the bid
submittals. Uncertainties related to the federal permitting process associated with new
wind development delayed the Jackalope Wind Project past Idaho Power's 2027 need for
the resource, terminating the approved agreements associated with the resource. A
Conditional Use Permit for a solar photovoltaic facility in Ada County, Idaho, was denied,
limiting the locations for siting of new resources. In addition, over the past two years, lead
times for critical materials have nearly doubled. Delivery of generator step-up ("GSU")
16 See Case No. I PC-E-26-03, In the Matter of Idaho Power Company's Application for Approval of the
2032 All-Source Request for Proposals, approved with Order No. 37018.
IDAHO POWER COMPANY'S REPLY COMMENTS - 11

transformer equipment now occurs approximately three years after a slot reservation is
made. Reciprocating engines need to be secured nearly three years in advance of
delivery, and advanced frame gas turbines need to be secured at least four to five years
in advance of delivery. Globally, the shift to more dispatchable energy sources, increased
demand for energy intensive data centers, increased demand for onshoring of
manufacturing, and the rise in electricity demand in general across the world, has
increased the need for turbines significantly, negatively impacting lead times.
18. Finally, the rapid addition of solar projects on Idaho Power's system has led
to a decrease in the ELCC of new solar resources, diminishing their effectiveness. These
dynamic and evolving factors, not load from a singular customer," have exacerbated the
need for continuous resource procurement activities and were not "foreseeable and
avoidable"'$ as suggested by Staff. Rather, in light of the lack of feasible and economic
2029 and beyond bids received following solicitation in the RFP, as well as the limited
diversity of bid-in dispatchable resources, it is the result of Idaho Power's diligent efforts
monitoring timelines in a very restrictive procurement environment that the Company was
able to identify two, least-cost, least-risk natural gas-fueled resource alternatives that are
necessary to ensure Idaho Power can continue to provide safe, reliable electricity
beginning in 2029 and into the future.
C. The Company's resource procurements have been timely and driven by load
growth across multiple customer sectors.
19. In their Comments, Staff accurately highlights the continuous baseline
growth the Company has experienced since completion of the 2021 IRP, creating
" Staff Comments, page 13.
1s Id.
IDAHO POWER COMPANY'S REPLY COMMENTS - 12

capacity needs in each subsequent year. Idaho Power agrees with Staff that it has been
facing capacity deficits continuously since 2021 and was appropriately "pursu[ing]
solutions that could be implemented within the lead-time available."19 The Company has
been repeatedly matching near-term resource procurements with the capacity need
identified at a point in time, attempting to align procurement of resources with a fluctuating
need, in accordance with the Commission's directive that they "expect the Company to
closely monitor its project capacity needs.1120 The Company disagrees however with
Staff's assessment that the need for new resources in consecutive years was foreseeable
and avoidable. As detailed in Case No. IPC-E-22-13, the load and resource balance from
the Second Amended 2019 IRP did not show a capacity deficiency until the summer of
2028. It was not until the 2021 IRP that the rapid change in the capacity deficiency was
identified, highlighting a near-term capacity need starting in 2023, which was the result of
several converging factors outside the Company's control, including limited third-party
transmission capacity, load growth, and a decline in the peak effectiveness of certain
supply-side and demand-side resources.
20. As part of its review in this case, Staff inappropriately concludes that Idaho
Power's commitment to serve a single, large load customer, Micron FAB, has led to an
inability to bring new resources online timely.21 Neither the Company nor any specific
customer have hindered Idaho Power's ability to bring resources online. The Company's
capacity deficiency determinations are based on system reliability assessments
performed between planning periods, and use the most up-to-date assumptions, including
19 Id., page 14.
20 Order No. 35643.
21 Id., pages 14-15.
IDAHO POWER COMPANY'S REPLY COMMENTS - 13

the most recent load forecast for all customer classes, incorporating Idaho Power's
largest customers and other committed large load customers who have entered into
procurement or construction agreements or ESAs with the Company, not uncertain
energy demand forecasts as suggested by the Public Commentors. The resulting annual
capacity position is based on a snapshot in time and is reflective of the Company's annual
capacity position at the time a resource is procured. The Micron FAB load was first
identified in the load forecast utilized in preparation of the 2023 IRP, which was the basis
for the commencement of the competitive bidding solicitation discussed in this case, again
in the 2025 IRP, and finally when determining the annual capacity position to support the
South Hills and Peregrine plants. The Company does not dispute that large loads are
contributing to the capacity needs. But Idaho Power strongly disagrees that by committing
to serve these large loads, Idaho Power "compounded its inability to get resources online
in time."22
D. Idaho Power completed a robust rule-compliant competitive resource
procurement process ultimately identifying the South Hills and Peregrine
plants as least-cost, least-risk alternative resources.
21. The Company conducted an extensive competitive bidding process
following the resource procurement rules of the OPUC, as required by the Idaho
Commission at that time, employing a fair and competitive RFP process that spanned
nearly 18 months, in an effort to acquire resources necessary to meet capacity
deficiencies beginning in 2029. The RFP process began with the engagement of an IE,
with participation from OPUC Staff and stakeholders throughout, and involved a
comprehensive eligibility screening process, the meticulous assessment and scoring of
22 Id., page 15.
IDAHO POWER COMPANY'S REPLY COMMENTS - 14

the resource bids, including benchmark resources, and a rigorous scenario analysis
followed by a portfolio sensitivity analysis and an additional qualitative factor analysis of
the final shortlist projects. Staff's suggestion that the Company misused and bypassed
the RFP process is incorrect and factually not supported.23
22. Staff first criticizes the selection of the South Hills plant, a benchmark bid
that was originally envisioned as a 60 MW BESS project, indicating the substitution
bypassed the entire RFP selection process.24 In October 2025, when Idaho Power
identified a 2029 capacity deficiency remained, and it was determined only the remaining
BESS projects and the combined solar plus BESS project had the potential for meeting
Company's capacity needs, Idaho Power requested the developers of the remaining
viable projects provide updated pricing or general project updates, if applicable, to further
assess the cost-effectiveness of each BESS project. The Company received unsolicited
information from two BESS resources outside the 2029 Bids final shortlist: from a 2026
RFP final shortlist BESS project and a 2028 Bids final shortlist project. In addition, Idaho
Power itself evaluated the feasibility of all remaining 2029 final shortlist projects to offer a
dispatchable resource instead of the solar, wind or BESS resource bid into the RFP.
However, due to either the status of the permitting of the project, generator
interconnection status, or the ability to procure the technology, it was determined that
South Hills was the only project that could offer a dispatchable resource by June 1, 2029.
The timing of the transition of the benchmark bid is irrelevant as all remaining viable
projects were afforded the same opportunity coincident with the Internal Bid Team.
23 Id., page 8.
24 Id.
IDAHO POWER COMPANY'S REPLY COMMENTS - 15

23. Further, the timing of the transition to a natural gas resource did not impact
the 2029 final shortlist evaluation results as the economics of the South Hills plant was
evaluated alongside all remaining feasible 2029 final shortlist projects received through
the RFP solicitation, including wind, solar and battery storage projects. This evaluation
was performed in a manner consistent with the analyses performed to evaluate the 2028
bids, commencing with Aurora's Long-Term Capacity Expansion ("LTCE") modeling.
Through this process, portfolios were developed to meet the identified capacity needs
through the selection of resource options that are least-cost for a variety of alternative
future scenarios while meeting reliability criteria. Once the portfolios were created, Idaho
Power used Aurora to determine the operating costs of the portfolios for the 20-year
planning timeframe. The results indicated that the portfolio inclusive of the South Hills
plant is $- more cost-effective than the best feasible alternative. Bypassing of
the RFP selection process did not occur; the South Hills project was evaluated consistent
with, and alongside, the 2029 final shortlist bids and identified as a least-cost, least-risk
resource, as acknowledged by Staff.25
24. Similarly, the Company disagrees with Staff's assertion that it "did not
comply with any ordered RFP process"26 when selecting the Peregrine plant. The RFP
solicited resources beyond 2029, however, the bids with a commercial operation date by
June 1, 2030, included on the initial shortlist were all battery storage or renewable
resources, or a combination thereof.27 Similar to the process for which South Hills was
25 Id., page 3.
21 Id., page 9.
27 With the exception of one standalone gas resource, the Bennett Gas Expansion Project, originally bid
in as a 2030 resource but ultimately accelerated the commercial operation date to June 1, 2028, for which
the Commission granted a CPCN.
IDAHO POWER COMPANY'S REPLY COMMENTS - 16

identified, because of the decrease in the ELCC of new solar projects and the limited
ELCC of wind resources, only the remaining BESS projects would have the potential to
fill the 2030 capacity deficiency. But due to concerns with the economics of the BESS
projects, their ability to meet the identified capacity deficiency, the identification of the
need for flexible generation resources in the 2025 IRP, and the lack of time to initiate a
second, 18-month long competitive solicitation process, Idaho Power began investigating
an alternative gas resource solution that could more economically meet the Company's
resource needs. The rule-compliant RFP solicited resources with commercial operation
dates beyond June 1 , 2028, but did not result in the identification of a feasible alternative
that could meet Idaho Power's identified 352 MW capacity deficit in 2030. The Peregrine
plant was evaluated alongside all remaining feasible 2029 final shortlist projects, along
with the cost-effectiveness analysis for South Hills, and the results indicated a portfolio
inclusive of Peregrine is $ more cost-effective than the best feasible
alternative.
25. Idaho Power commenced the competitive solicitation process on August 16,
2024, in accordance with the OPUC competitive bidding rules the Company was required
to follow at the time. Through this rule-compliant process, the South Hills and Peregrine
plants were identified as least-cost, least-risk resources. Under the OPUC competitive
bidding rules, an electric utility such as Idaho Power must issue an RFP that complies
with the competitive bidding rules for the acquisition of a generation resource or contract
80 MW and larger and five years or longer in length, subject to certain exceptions. An
exception to this requirement is where "[t]here is a time-limited opportunity to acquire a
IDAHO POWER COMPANY'S REPLY COMMENTS - 17

resource of unique value to the electric company's customers.1128 When this exception to
the competitive bidding rules applies, the electric company must file a report with the
Commission explaining the relevant circumstances of the acquisition.29 Because the
resources were not specifically identified on an OPUC-approved final shortlist, in
accordance with the Oregon Administrative Rule ("OAR") 860-089-0100(3) and (4), Idaho
Power filed a Notice of Exception on April 9, 2026, detailing the circumstances related to
the time-limited opportunity to acquire the South Hills and Peregrine plants.
26. The Company's competitive solicitation process was not in "direct
contravention of the Commission's orders"30 as suggested by Staff. In their Comments,
Staff implies that the selection of the Peregrine plant as a least-cost, least-risk resource
should have been made in accordance with Order No. 36898. Issued on January 2, 2026,
Order No. 36898 rescinded the requirement that the Company following the OPUC
competitive bidding rules and instead establishes new procedures for soliciting large
supply-side resources for which Idaho Power is required to follow, applying to each new
RFP to acquire large supply-side resources prior to issuance. Staff's argument fails to
recognize that Idaho Power commenced the competitive solicitation process on August
16, 2024, in accordance with the OPUC competitive bidding rules the Company was
required to follow at the time, nearly 16-months prior to issuance of Order No. 36898.
i. There were no other feasible resource alternatives that were lower
cost than the South Hills and Peregrine plants.
27. Staff acknowledges a combined cycle combustion turbine ("CCCT") natural
gas resource could not be operational by June 1, 2030, but indicated they believe that a
28 OAR 860-089-0100(3)(b).
29 OAR 860-089-0100(4).
30 Staff Comments, page 10.
IDAHO POWER COMPANY'S REPLY COMMENTS - 18

CCCT plant could provide long-term potential cost savings and therefore the Company
should have considered one as a resource alternative, "delaying load growth or bridging
the time gap with market purchases.1131 Staff's analysis is flawed. First, Staff fails to
highlight that its proposed, hypothetical scenario would fail to meet Idaho Power's
identified need in this case, the capacity deficits in the summer of 2029 and 2030.
Determination of a 2031 resource, or a resource with a commercial operation date after
June 1, 2030, is an open question that will be determined as part of the evaluation of bids
received as a result of the 2032 RFP, approved by the Commission.32 That being said,
the Company has a statutory and contractual obligation to serve the load growth
contributing to the capacity deficiencies presented in this case in accordance with the
Idaho law, including loads associated with Commission-approved ESAs. Delaying service
to these customers would be unlawful.
28. With respect to market purchases, in addition to not receiving any bids as
part of the RFP solicitation, any market purchase that could contribute to the capacity
deficiencies would need to be delivered on incremental transmission not already assumed
in the capacity deficiency analysis. Idaho Power will make purchases to be delivered on
transmission that was assumed and may make additional purchases on additional
incremental transmission. However, having not received any market purchase bids in this
RFP solicitation, it would not be realistic to assume that Idaho Power will be able to make
such purchases on additional incremental transmission in the amounts necessary to fill
the capacity deficiencies of 236 MW in 2029 and 352 MW in 2030, on top of the
transmission already assumed in the analysis — 600 MW in summer and 700 MW in
31 Id.
32 Case No. IPC-E-26-03, Order No. 37018.
IDAHO POWER COMPANY'S REPLY COMMENTS - 19

winter. Such an assumption could exceed Idaho Power's actual rights for imports and
would not reflect realistic or prudent resource planning, creating risk to the Company's
ability to meet reliability thresholds.
29. Next, Staff performed a simple comparison of a CCCT resource versus a
simple cycle combustion turbine ("SCCT") based on assumptions relied on from the 2025
IRP. When considering those IRP proxy resources, 300 MW and 150 MW, respectively,
Staff determined a CCCT was more cost-effective than the SCCT based on the validation
and verification scenario performed as part of the 2025 IRP. Staff then suggests, without
additional analysis, that a CCCT would be more cost-effective than the proposed 430 MW
Peregrine SCCT. However, Staff's analysis did not consider that the 430 MW SCCT H-
class turbine selected for Peregrine is much more efficient than the smaller class 150 MW
SCCT turbine analyzed as part of the 2025 IRP in terms of fuel usage, and likely more
cost-effective in terms of fixed and variable operations and maintenance expense, and
therefore the capital cost on a per kilowatt basis would be lower. In addition, Staff did not
account for any cost changes that would have occurred since the analysis was performed
for the 2025 IRP, in late 2024. With significant cost increases for both SCCT and CCCTs
since late 2024, it cannot be assumed that a CCCT would have been preferred over a
SCCT as the cost-effectiveness of a CCCT versus a SCCT is typically based on improved
operational and fuel efficiencies of the CCCT, compared to lower capital costs of the
SCCT. The greater the cost differential the more you need in fuel and operational
efficiencies for a CCCT to be preferred over a SCCT. Staff's foundational argument that
a CCCT would be lower cost than a SCCT does not have merit in this proceeding.33
33 Id.
IDAHO POWER COMPANY'S REPLY COMMENTS - 20

30. Finally, Staff does not acknowledge the analysis the Company performed
at Staff's request that considered a scenario with a CCCT resource selectable in 2031.
Because no refined cost estimates were available for a 2031 CCCT, Idaho Power
estimated costs of a new CCCT by applying a ratio to the Peregrine cost estimates while
preserving the CCCT to SCCT cost ratio from the 2025 IRP. With incremental capacity
needs of at least 200 MW in 2031 and 2032, as identified in the 2032 RFP, a 300 MW
CCCT resource was modeled and Aurora's LTCE algorithm optimized around the forced
selection. The result is a portfolio with a 20-year net present value cost that is $-
more than the portfolio including the South Hills and Peregrine projects. Staff's suggestion
that the Company "traded the certainty of a long-term more cost-effective resource for the
possibility of having a more expensive resource online one summer earlier"34 is simply
not true. In fact, following identification in the 2025 IRP of the need for dispatchable,
flexible resources, Idaho Power took a risk executing reservation agreements for
reciprocating engines and turbines, to ensure the Company could continue to provide
customers safe, reliable electric service in 2029 and beyond, and in this case has
ultimately demonstrated that the South Hills and Peregrine plants are least-cost, least-
risk resources.
E. Staff's proposed financial consequences are unfair and unwarranted.
31. Although they acknowledge Idaho Power has met the necessary regulatory
requirements for a CPCN and identified the most cost-effective, feasible alternatives, Staff
believes that the "Company ought to bear some of the financial consequences of its
choices," unjustly proposing the Commission (1) reject early AFUDC accrual, (2) impose
34 Id., page 11.
IDAHO POWER COMPANY'S REPLY COMMENTS - 21

a cap on the South Hills and Peregrine plant costs, (3) delay the timeline for new large
loads until the capacity deficit is remedied, and (4) ensure the South Hills and Peregrine
plant costs are associated with the new large load allocation case. In response, Idaho
Power provides the following support addressing Staff's unreasonable and onerous
proposed penalties.
i. AFUDC accrual for the South Hills and Pere_prine plants when
procurement activities be_pin is appropriate.
32. Recently, Idaho Power began incurring capital expenditures associated with
resource procurements earlier than in the past in order to secure a position in the queue
to purchase reciprocating engines for the South Hills plant and a turbine for the Peregrine
plant and ensure commercial operation dates can be met. As a result, the Company is
requesting the Commission confirm Idaho Power's treatment of the accrual of AFUDC for
both projects is appropriate when expenditures are first incurred, which is prior to the
request for the CPCNs. With respect to the Peregrine plant, Staff agreed that "the
Company selected the only vendor with a lead time that aligned with the required in-
service date" of the plant and does not dispute the Company's procurement activities or
the timing of those activities.'135
33. Staff, however, does not support the Company's request to begin accrual
of AFUDC upon initial procurement activities in this case, erroneously claiming that Idaho
Power did not complete the RFP process nor the waiver process under the framework
established in Order No. 36898,36 and instead recommends accrual begin upon issuance
of a CPCN. As discussed earlier, the competitive bidding rules Idaho Power was required
35 Staff Comments, page 17.
36 Id., page 18.
IDAHO POWER COMPANY'S REPLY COMMENTS - 22

to follow precede Order No. 36898; Idaho Power commenced the competitive solicitation
process on August 16, 2024, through a request for approval of an RFP seeking proposals
for a combination of capacity and energy resources in 2028 and beyond, in accordance
with the OPUC competitive bidding rules the Company was required to follow at the time,
nearly 16-months prior to issuance of Order No. 36898. Further, in accordance with the
OPUC competitive bidding rules,37 Idaho Power filed a Notice of Exception detailing the
circumstances related to the time-limited opportunity to acquire the South Hills and
Peregrine plants. Staff's suggestion that the Company should be penalized for not
following Order No. 36898 is inappropriate. Idaho Power conducted an extensive
competitive bidding process following the resource procurement rules of the OPUC, as
required by the Idaho Commission at the time, employing a fair and competitive RFP
process in an effort to acquire resources necessary to meet capacity deficiencies
beginning in 2029.
34. The Company's investigation into alternative resources led to the
identification of the South Hills and Peregrine natural gas-fueled plants as least-cost,
least-risk resource that ultimately required Idaho Power to take immediate action to
initiate procurement activities, which shareowners are currently funding, in order to
ensure commercial operation dates could be achieved. In support of Staff's suggestion
that Idaho Power be penalized and not allowed to commence AFUDC accrual until
issuance of a CPCN, Staff indicates the Company failed to consider procuring a CCCT
37 Oregon Administrative Rule 860-089-0100(3) and (4). An exception to this requirement is where "[t]here
is a time-limited opportunity to acquire a resource of unique value to the electric company's customers.
When this exception to the competitive bidding rules applies, the electric company must file a report with
the Commission explaining the relevant circumstances of the acquisition.
IDAHO POWER COMPANY'S REPLY COMMENTS - 23

potentially dismissing a lower-cost resource.38 Yet, Staff minimizes the fact that lead-
times for equipment necessary to construct a combined cycle plant would not have
allowed for the plant to become operational in time to meet the identified capacity need.
Staff's proposal in this regard is unreasonable and seeks to unfairly penalize the
Company for not pursuing an infeasible option. Idaho Power incurred financing costs for
the timely procurement of long-lead equipment associated with least-cost/least-risk,
feasible resources, and therefore should have an opportunity to recover those prudently
incurred costs.
ii. The Company will justify all South Hills and Peregrine plant costs as
part of a future proceedin_p.
35. Due to their concerns regarding the selection of the alternative natural gas
resources, and because they will be Idaho Power-owned projects, Staff recommends the
Commission establish cost containment measures, setting a cap on recovery equal to the
most recent cost estimate of each project, noting that "the Company may seek recovery
of the additional costs. . . in a future rate proceeding.1139 Idaho Power does not believe
cost caps are necessary as the Company is requesting a decisional prudence
determination regarding the selection of the South Hills and Peregrine plants; an
operational prudence decision would be requested in a cost recovery proceeding. As
explained in the Company's Application, Idaho Power is not requesting binding
ratemaking treatment in this case, rather the Company's request in this case is that the
Commission find Idaho Power has met the requirements of Idaho Code § 61-526 and
38 Staff Comments, page 10.
39 Id. page 19.
IDAHO POWER COMPANY'S REPLY COMMENTS - 24

issue an order granting CPCNs for the South Hills and Peregrine plants necessary to
meet the identified capacity deficiencies beginning in 2029.
36. Staff's assumption that the Company will "lack adequate cost
accountability" because the projects will be Idaho Power-owned and therefore a
component of rate base earning a return is unfounded. The Company's capital budgeting
process encompasses an approval process of capital projects that includes review and
approval by senior management, executive management, and the Idaho Power Board of
Directors. Once approved, throughout the year, projects are evaluated and re-forecasted
as necessary to increase or reduce forecasted spend during the remaining life of the
project as more information about the project becomes known. In addition, the capital
budget is monitored through monthly variance analysis reporting and through quarterly
budget update analysis and reporting. Additionally, the Company continuously manages
and scrutinizes changes in scope, budget, or schedule on a monthly basis. Idaho Power
has and will continue to utilize best practices to manage project costs throughout project
execution. In addition, construction of the South Hills and Peregrine plants will be
executed primarily through supplier contracts, including the supply agreements and the
Engineering, Procurement and Construction agreements, all of which do include
contractual cost overrun protections, contrary to Staff's belief,40 incorporating typical
protective provisions such as change order validation, delay damages, and schedule
obligations.
37. The Company will make a future filing to address the cost recovery
associated with these projects and does not believe cost caps are necessary. It is in this
ao Id. page 18.
IDAHO POWER COMPANY'S REPLY COMMENTS - 25

future proceeding that Idaho Power will justify all costs associated with South Hills and
Peregrine plants, not just those costs over the current cost estimate, if any. At this time,
any costs resulting from contractual cost escalation mechanisms or contractual risk if
incurred will be presented for review and determination as well, ensuring a complete
record for a prudence decision.41 As directed by the Commission, the Company will
"exercise the utmost due diligence in selecting resources, managing costs, and providing
service to its Idaho customers"42 and when Idaho Power requests recovery of the
resources in a future proceeding, the "Commission expects the Company to provide a full
and transparent accounting for all costs associated with the project.1143 At that time "the
Commission will consider all facets of the project including scope, cost justification, and
the Company's procurement process, to determine the prudence of the Company's
decisions."44
iii. A delay in the timelines for new large loads is unnecessary.
38. Because of Idaho Power's identified capacity deficits in future years, Staff
suggests that the Company delay signing Energy Service Agreements ("ESA") for new
large loads until Idaho Power has "sufficient capacity headroom and the Company has
adequate time to properly solicit and build new resources.1145 Idaho Power understands
Staff's concerns with the upcoming capacity deficiencies but does not believe a delay in
executing any new ESAs is necessary, particularly in light of new legislation. Pursuant to
Idaho Code § 61-335, effective July 1, 2026, service to new large loads may only be
41 IIPA Comments, page 6.
42 Case No. IPC-E-24-16, Order No. 36386, page 6.
43 Case No. IPC-E-25-29, Order No. 36958, page 9.
44 Case No. IPC-E-24-16, Order No. 36386, page 6.
45 Staff Comments, page 19.
IDAHO POWER COMPANY'S REPLY COMMENTS - 26

provided with a Commission-approved ESA and, when requesting approval, the
Company must include a no harm test, demonstrating the new large load will be
responsible for funding its full cost of service. As such, any proposed delay in procurement
of a resource due to a new large load would be more appropriately addressed in the
proceedings requesting approval of the associated ESA.
39. Also of importance, the need for the South Hills and Peregrine plants was
based on a load forecast for all customer classes, including Idaho Power's largest
customers, along with other committed large load customers who have entered into
procurement or construction agreements with the Company, the two largest having
executed and Commission-approved ESAs. The loads of both large customers were in
the load forecast utilized in preparation of the 2023 IRP, which was the basis for the
commencement of the competitive bidding solicitation discussed in this case, again in the
2025 IRP, and finally when determining the annual capacity position for this proceeding.
Idaho Power appropriately planned for, and procured the necessary resources, to serve
the loads for all customer classes, and can continue to do so with any future ESAs.
F. The Company's clarification of the South Hills and Peregrine plant
characteristics that led to the identification as least-cost, least-risk resource
additions.
40. The Joint Advocates suggest Idaho Power has failed to justify the South
Hills and Peregrine plants are needed and suggests the Company shifts undo cost and
risk onto its customers. Idaho Power believes the Joint Advocates conclusion is based on
a misunderstanding or mischaracterization of the process by which the projects were
identified as least-cost, least-risk resources necessary to reliably serve customer load
beginning in 2029. In response, the Company addresses and provides clarification on the
following: (1) Idaho Power had not over procured resources, (2) the Company has
IDAHO POWER COMPANY'S REPLY COMMENTS - 27

established protections intended to mitigate the risk associated with delayed or reduced
load, (3) the concern regarding the continuation of the 30 percent investment tax credit
("ITC")for BESS projects was valid, and (4)the most recent system reliability assessment
combined with the cost-effectiveness analysis support Idaho Power's request in this case.
41. First, the Joint Advocates believe that Idaho Power has over procured
resources because the total nameplate generation associated with the combined South
Hills and Peregrine plants is 652 MW while the capacity deficiency identified a need of
236 MW in 2029 and 352 MW in 2030, expressing criticism of the load forecast.46 The
Joint Advocates fail to recognize that the identified capacity deficiencies are perfect
capacity, so they required Idaho Power to procure more megawatts of nameplate
capacity, depending on the ELCC of each resource.
42. In addition, the Joint Advocates suggest that because the Commission does
not have certainty projected new loads will materialize, there is a risk that Idaho Power
will overbuild its system.47 As such, they recommend the Commission deny the
Company's request until Idaho Power has demonstrated "the resources are needed to
meet a known and measurable load." Yet the Company has done just that, only including
load projections for large load customers who have entered into procurement or
construction agreements and by executing ESAs with new large loads that implement a
broad range of mechanisms and protections intended to mitigate the risk associated with
delayed or reduced load projections.
43. With respect to the 30 percent ITC, the Joint Advocates question Idaho
Power's concern regarding whether the Milner 60 MW BESS would remain eligible for the
46 Joint Advocates Comments, page 3.
47 Id., page 4.
IDAHO POWER COMPANY'S REPLY COMMENTS - 28

30 percent ITC. When the Company analyzed the impact of four qualitative factors on the
2029 final shortlist bids, including the potential for an IRA repeal and tariff impacts, the
legislation of the One, Big, Beautiful Bill proposed at the time, assumed an IRA repeal for
all solar, wind, and battery projects that would come online after December 31, 2028. This
was discussed in detail in the LEI Closing Report included as Confidential Exhibit No. 3.48
Idaho Power's concern at the time regarding the BESS resources eligibility for an ITC
was supported and valid.
44. The Company's request in this proceeding is supported by the most recent
system reliability assessment, performed subsequent to, and outside of, the development
of the 2025 IRP, which identified capacity deficiencies in 2029 and 2030, despite the Joint
Advocates conclusion that the 2025 IRP must support the procurement of the South Hills
and Peregrine plants.49 Rather, the system reliability assessment, which utilizes the most
up-to-date load and resource inputs and firm market purchase assumptions, combined
with the cost-effectiveness analysis, which utilizes the most up-to-date cost estimates for
48 Page 78, "Inflation Reduction Act considerations: At the time IPC prepared its analysis, existing tax law
under the IRA allowed ITC and PTC benefits for renewable projects; nonetheless, there were some
concerns about the impact of the then-proposed One Big Beautiful Bill, on the tax credits. At that time, it
was IPC's understanding that the then-proposed One Big Beautiful Bill would eliminate tax credit benefits
for renewable projects placed in service after December 31, 2028, assuming these projects were under
construction within 60 days of the enactment date of the bill. In addition, IPC was concerned by the
Foreign Entities of Concern ("FEOC") provision in the proposed bill that further restricted projects from
qualifying for the IRA tax credits. The FEOC restrictions at the project level were reportedly intended to
take effect on January 1, 2026. FEOC rules would deny ITC and PTC to projects that receive"material
assistance" (meaning projects that use components, subcomponents, or critical minerals)from, or have
ties to, companies in China, Russia, North Korea, and Iran. The fact that most BESS components
originated from companies in China (based on the IPC's experience) and nearly all solar components
were sourced from companies in China, the company was worried that all renewable projects evaluated
in this RFP would lose the benefit of the tax credits, which would substantially increase the cost of these
projects. At the time of the analysis, due to the complexity of the House Bill and the uncertainty of
potential changes occurring in the Senate, IPC took a simplified approach to analyzing a potential future
with a repealed IRA bill. IPC's IRA repeal scenario assumes that projects placed in-service in 2028 qualify
for the ITCs or PTCs and projects placed in-service in 2029 do not qualify for the tax credit benefits. In the
final version of the bill, tax credits for wind and solar projects are essentially not available after December
31, 2027."
49 Joint Advocates Comments, page 8.
IDAHO POWER COMPANY'S REPLY COMMENTS - 29

all resource bids,50 support the acquisition of the least-cost, least-risk resources, the
South Hills and Peregrine plants. When considering the cost of natural gas resources,
Idaho Power added natural gas pipeline costs and updated the cost of the firm transport
As such, concerns with the 2025 IRP analysis, including gas prices utilized
at the time,51 are not relevant to this proceeding.52
G. Idaho Power agrees that cost recovery associated with the South Hills and
Peregrine plants is more appropriately contemplated in a future rate
proceeding.
45. In their Comments, IIPA recognizes that Idaho Power's request in this
proceeding is specific to the procurement of resources to meet an identified capacity need
and not cost recovery associated with the South Hills and Peregrine plants. Staff too
acknowledged that "this case is not the appropriate venue for determining class cost-of-
service, rate design or cost allocation results.1153 IIPA explained that, instead, their
comments are intended to clarify on the record how "this proceeding may affect future
rate design, cost-of-service ("COS") allocation, and cost recovery"54 associated with the
proposed projects. The Company appreciates IIPA's recognition of the request in this
proceeding and responds to some issues raised by IIPA specific to costs, sensitivity
analyses, and new large loads.
46. Idaho Power would like to clarify that the costs associated with the
Company's reservation agreements, or import tariffs if imposed, are not "additional cost
50 Id., page 12.
51 Id., pages 12-14.
52 Id., page 9.
53 Staff Comments, page 20.
54 IIPA Comments, page 1.
IDAHO POWER COMPANY'S REPLY COMMENTS - 30

components beyond the underlying resource itself"55 as suggested by IIPA. Rather, the
costs associated with reservation agreements are now standard costs incurred when
procuring equipment in high demand, contribute to the supply agreement contract price,
and appropriately capitalized to the project. For example, due to the demand for GSU
equipment, as discussed earlier, reservation slots must be made approximately three
years in advance with payments occurring three to four years in advance to ensure
commercial operation dates can be met. Payments made for procurement of materials
necessary for the construction of a resource are often required prior to delivery. Similarly,
costs associated with import tariffs would not be imposed absent the resource
procurement. The classification as a component of the total cost of the project does not
however mean Idaho Power cannot quantify or isolate the costs specific to each. The
expenditures are appropriately considered when analyzing the total cost of the project
and are attributable to the "physical provision of capacity" and solely the result of the
system capacity need. All costs can be identified by cost category, including those
identified by Staff,56 for future "determinations of prudence, cost recovery and cost
allocation.1157
47. Idaho Power also disagrees with IIPA's assessment that the Company's
cost-effectiveness analysis of the South Hills and Peregrine plants is incomplete, creating
a gap in the record.58 IIPA highlights that Idaho Power"did not include a natural gas price
551d., page 2.
56 Staff Comments, page 20. Staff requests the Company ensure "all costs associated with the Proposed
Projects, inclusive of adding natural gas pipeline capacity, transportation, storage, fuel delivery
infrastructure, interconnection upgrades, and any other related or enabling investments, are fully
captured, clearly documented, and distinctly tagged in the Company's records so they can be readily
isolated, retrieved, and reported in future proceedings."
57 Id. page 4.
5s Id.
IDAHO POWER COMPANY'S REPLY COMMENTS - 31

scenario analysis for the project" and "[i]nstead, the Company relied on a separate
stochastic analysis using multiple gas price forecasts." IIPA believes the use of the
stochastic analysis does not provide "clarity regarding the robustness of the selected
resources under alternative plausible fuel price trajectories.1159 Yet, the stochastic analysis
does just that. Consistent with the methods used in the 2025 IRP, the stochastic analysis
assessed the effect on portfolio costs when select variables have values that change from
the planning-case levels and included 60 different gas price forecasts which varied
around the base gas forecast utilized in the cost-effectiveness analysis. Of those
variations, 20 of the 60 iterations showed gas price variances that were materially above
then-current market forwards. The results of the stochastic analysis showed that when
gas prices are more than 10 percent higher than current market forwards, inclusion of
both the South Hills and Peregrine plants is the least cost option 85 percent of the time,
or an average of $- and $- more cost-effective, respectively. Idaho
Power did perform an analysis of fuel price volatility when determining the least-cost,
least-risk resources presented in this case; there is no gap in the record.
48. In addition, the Company would like to clarify that the alternative resource
sensitivities, including the battery storage alternatives, were performed by Idaho Power
and all resources were "modeled within the same analytical framework" and the results
"presented on a consistent, side by side comparison basis.1160 An external analysis was
not relied upon as concluded by IIPA, rather the LEI Closing Report, included as
Confidential Exhibit No. 3 and submitted in the record in this case, describes the extensive
59 Id., page 5.
60 Id.
IDAHO POWER COMPANY'S REPLY COMMENTS - 32

selection process undertaken by Idaho Power to identify the least-cost, least-risk
resources resulting from the RFP solicitation.
49. Finally, IIPA was critical of the Company for not having performed the
analysis to determine the percentage of the capacity deficiencies that were directly
attributed to load growth from new large loads. IIPA's criticism is misplaced in this docket.
The purpose of a CPCN proceeding is to present a system resource need and identify
the least-cost, least-risk resource to meet that identified system need. While the Company
agrees with IIPA that new resource costs will have "direct implications for cost allocation",
issues relating to cost causation and cost assignment should be addressed in ESA-
approval proceedings, general rate cases or other ratemaking proceedings.
III. CONCLUSION
50. Idaho Power acknowledges and appreciates IIPA, the Joint Advocates, and
Staff's review of the Company's application and respectfully requests that the
Commission (1) accept Staff's recommendation to issue CPCNs for the South Hills and
Peregrine plants, (2) accept the Company's request to approve the commencement of
the accrual of AFUDC on capital expenditures associated with the South Hills and
Peregrine plants upon initial procurement activities, and (3) reject Staff's proposed cost
cap and the Joint Advocates' unwarranted reevaluation of resource options. The
evidentiary record demonstrates that the South Hills and Peregrine plants meet the
statutory standard of public convenience and necessity because they enable the
Company to meet its reliability obligations for all customers the Company is required to
serve. Both plants are prudent and least-cost, least-risk system resources required to
help meet the identified capacity deficit beginning in 2029.
IDAHO POWER COMPANY'S REPLY COMMENTS - 33

DATED at Boise, Idaho this 14th day of August 2026.
DONOVAN E. WALKER
Attorney for Idaho Power Company
IDAHO POWER COMPANY'S REPLY COMMENTS - 34

CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on the 14th day of August, 2026, 1 served a true and
correct copy of Idaho Power Company's Reply Comments upon the following named
parties by the method indicated below, and addressed to the following:
Commission Staff Hand Delivered
Kelsea E. Ross U.S. Mail
Deputy Attorney General Overnight Mail
Idaho Public Utilities Commission FAX
11331 W. Chinden Blvd., Bldg No. 8 FTP Site
Suite 201-A (83714) X Email kelsea.ross(a)-puc.idaho.gov
PO Box 83720
Boise, ID 83720-0074
Micron Technology, Inc. Hand Delivered
Austin Rueschhoff U.S. Mail
Thorvald A. Nelson Overnight Mail
Richard A. Arnett FAX
Holland & Hart LLP X Email darueschhoffCc)_hol land hart.com
555 17th Street, Suite 3200 tnelson hol land ha rt.com
Denver, CO 80202 raarnett(o)_hollandhart.com
aclee hollandhart.com
tlfriel hol land hart.com
Idaho Irrigation Pumpers Association, Hand Delivered
Inc. U.S. Mail
Eric L. Olsen Overnight Mail
ECHO HAWK & OLSEN, PLLC FAX
505 Pershing Avenue, Suite 100 X EMAIL eloCc)_echohawk.com
P.O. Box 6119 taysha echo hawk.com
Pocatello, ID 83205
Lance Kaufman, Ph.D. Hand Delivered
Deborah Glosser, Ph.D. U.S. Mail
2623 NW Bluebell Place Overnight Mail
Corvallis, OR 97330 FAX
X EMAIL lance aegisinsight.com
Debora h.glosser _gmai1.com
IDAHO POWER COMPANY'S REPLY COMMENTS - 35

The Northwest Energy Coalition (NWEC) Hand Delivered
and Renewable Northwest (RNW) U.S. Mail
Benjamin J. Otto Overnight Mail
1407 W. Cottonwood Ct. FAX
Boise, ID 83702 EMAIL ben nwenergy.org
lauren(c)-nwenergy.orq
derek _nwenergy.org
Christy Davenport
Legal Administrative Assistant
IDAHO POWER COMPANY'S REPLY COMMENTS - 36