20250513Staff Comments - Redacted.pdf

RECEIVED
Tuesday, May 13, 2025
CHRIS BURDIN IDAHO PUBLIC
DEPUTY ATTORNEY GENERAL UTILITIES COMMISSION
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
IDAHO BAR NO. 9810
Street Address for Express Mail:
11331 W CHINDEN BLVD, BLDG 8, SUITE 201-A
BOISE, ID 83714
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER )
COMPANY'S APPLICATION FOR ) CASE NO. IPC-E-24-46
APPROVAL OF A POWER PURCHASE )
AGREEMENT WITH JACKALOPE WIND, )
LLC,AND A CERTIFICATE OF PUBLIC ) COMMENTS OF THE
CONVENIENCE AND NECESSITY FOR THE ) COMMISSION STAFF (REDACTED)
JACKALOPE WIND PROJECT )
COMMISSION STAFF ("STAFF") OF the Idaho Public Utilities Commission
("Commission"), by and through its Attorney of record, Chris Burdin, Deputy Attorney General,
submits the following comments.
BACKGROUND
On December 27, 2024, Idaho Power Company ("Company") applied to the Commission
requesting an order: (1) approving a 35-year Power Purchase Agreement("PPA")between the
Company and Jackalope Wind, LLC ("Jackalope"); and(2) granting the Company a Certificate
of Public Convenience and Necessity("CPCN") to acquire 300-megawatt("MW") of generation
to meet an identified capacity deficiency in 2027. Application at 1-2.
On January 30, 2025, the Commission issued a Notice of Application and Notice of
Intervention Deadline. Order No. 36450. The Commission granted intervention to the Industrial
STAFF COMMENTS 1 MAY 13, 2025

Customers of Idaho Power, Micron Technology, Inc., and the Idaho Irrigation Pumpers
Association, Inc. Order Nos. 36486 and 36493.
STAFF ANALYSIS
I. Initial Summary
Staff has significant concerns about this project. The Company projects a large capacity
deficit in 2027 and must procure additional resources to cover it. This project is part of the
Company's proposed solution.
Although the Company's analysis shows that this project is the least-cost resource, it
contributes relatively little toward the capacity deficit despite a large capital investment. Staff
believes this is because the project provides inexpensive, tax-subsidized energy, which provides
the advantage it needs to be lower cost than other potential alternatives even though the
contribution to capacity is relatively small.
In a related development, the new presidential administration has taken actions that
jeopardize the federal permits for the project and jeopardize the tax credits that make the project
least-cost. This makes the project riskier for both reliability and economic reasons. Under more
normal circumstances, Staff would recommend against this project. However, the circumstances
are not normal. The Company faces a rapidly increasing system load, delays with other new
resources, and compressed timelines, so it has few, if any, other options besides this project.
Given this dilemma, Staff recommends that the Commission approve the Company's Application
requests but shift the financial risk of the Production Tax Credits ("PTC"s) to the Company.
Finally, in Section V, Staff discusses the larger implications of the Company's perpetual
capacity deficit and proposes recommendations for the Commission to consider.
11. The System Need
Staff believes that the Company's system reliability modeling was sound and agrees with
the Company's analysis showing that there will be a 298 MW capacity deficit in 2027.
A. Modeling Inputs
Staff evaluated the inputs and assumptions used by the Company for its modelling
analyses. The major inputs are the forecasted load and the forecasted resources, which the
Company testified were up to date as of the time the case was filed. Ellsworth Direct at 8-9.
STAFF COMMENTS 2 MAY 13, 2025

Staff agrees that the forecasted resources were up to date and accepts the Company's assertion of
the latest load forecast.
Another important input is the assumed cost for each resource, which is determined by
many factors such as initial capital costs, life-cycle costs, fuel costs, renewable energy credits,
investment tax credits ("ITC"s), PTCs, imputed debt, interconnection costs, and others. Staff
found the cost inputs to be reasonably justified.
B. Modeling Assumptions
Staff examined the modeling assumptions used by the Company, which included
environmental constraints, transmission constraints, and the charging and discharging principles
used for Battery Energy Storage Systems. The Company also testified that it included a wildfire
risk factor and an updated generation unit outage schedule. Ellsworth Direct at 9.
Staff found all the Company's inputs and assumptions to be reasonable for its calculation
of a system capacity deficit. Therefore, Staff accepts the result of the Company's analysis, and
Staff believes that the system will have a 298 MW capacity deficit in 2027 unless additional
actions are taken.
III. The Request for Proposal("RFP") Process
Overall, Staff considered that the RFP process was acceptable, but Staff identified several
concerns that it hopes the Company will consider for future RFPs.
A. The RFP Eligible Products
One of Staff s primary concerns was the limited set of resources that the Company would
accept in its solicitation. Section 3.1 of the 2026-2027 All-Source RFP listed eligible products,
and the Company identified eight resource types.1 Only one of these eight resource types was
based on gas, despite the affordability, dispatchability, and reliability offered by gas plants.
Furthermore, the Company conditioned the sole gas-based option to be "Gas-fired Convertible to
Hydrogen."
' Case No.IPC-E-24-12,Exhibit No.4 at 12-15.
STAFF COMMENTS 3 MAY 13, 2025

Staff believes the inclusion of a convertibility requirement to commercially unproven
hydrogen fuel may have been a deterrent to gas-fired proposals. In fact, only one of the initial
192 RFP bids was this resource-type.2 Staff is addressing this issue in a separate case (GNR-E-
25-01)but includes it here because it is also relevant to this case.
B. The RFP Multi-Year Format
Staff believes that the Company's decision to issue a two-year RFP solicitation (2026 and
2027) was problematic for two reasons.
First, the two-year window allowed the early cost-effectiveness analysis to become stale.
The RFP was issued in 2022. The cost-effectiveness of the resources was analyzed by modelling
runs conducted in 2023 using system load and resource assumptions available at that time. The
Company filed this case at the very end of 2024, even though numerous load and resource
assumptions had changed significantly in the interim. Staff suggests that the cost-effectiveness
analysis for future projects be updated with more current modelling assumptions before the
Company files a case.
Second, the multi-year solicitation magnified the problem of unknown resources. The
Company has filed multiple cases asking the Commission to determine the prudence of
individual resources without knowing all the resources that would ultimately be selected to meet
the capacity deficit. This prevents the interactive effects of each resource from being assessed.
Ideally, the full set of resources should be submitted together as the most cost-effective solution.
Staff recognizes this may not always be possible due to time constraints but suggests that a
multi-year RFP exacerbates the problem.
C. The Selection Process
Staff believes that the Company's process of reducing the RFP proposals from 192 to the
preliminary Final Shortlist("FSL") was fair and reasonable with one exception. Exhibit No. 3 is
the Closing Report from the Independent Evaluator, and it documents the step-by-step
elimination process applied by the Company. Staff spot-checked the scoring algorithm, the
scoring itself, the levelized costs of each resource, and the AURORA modeling inputs. Staff
agrees that the Company's process was reasonable and that it applied the process fairly.
2 Application,Exhibit No. 3 at 15-16.
STAFF COMMENTS 4 MAY 13, 2025

However, Staff disagrees with the Company's decision to divide the projects into those
with a 2026 commercial operation date ("COD") and those with a 2027 COD and to compare
them separately. This makes sense for 2026 projects, but Staff believes that all the unselected
2026 projects should have been carried forward to compare with the 2027 projects. Instead, the
Company compared the 2027 COD projects by themselves. It is conceivable that some of the
unselected 2026 projects could have been better alternatives than the best 2027 projects, but this
was not examined. Staff suggests that the Company revise its process accordingly if it attempts
another multi-year solicitation. Alternatively, a return to a single-year RFP will avoid the
problem entirely.
This issue has become moot for this case, because many projects have been withdrawn
due to a variety of delays. The Company has been forced to reconsider all the preliminary FSL
projects, regardless of the initial COD.
IV. The Proposed Solution: Jackalope
The Company asserts that the Jackalope Project is necessary to provide safe and reliable
service to its customers. Application at 2. The Jackalope Project consists of a 300 MW PPA and
a 300 MW build-transfer agreement ("BTA") for a combined total of approximately 600 MW of
wind turbine generation. The project is sited in Wyoming, near the Company's Jim Bridger Coal
Plants, and it proposes to share the same transmission line to deliver power to the Company's
service territory.
Staff agrees that the Company urgently needs additional capacity to provide reliable
service to its customers, but Staff has significant concerns that the Jackalope Project is not the
least-cost, least-risk("LC-LR") solution, as explained below.
A. Jackalope's Contribution to the Need
The Company states that the 600 MW Jackalope Project will reduce the 2027 capacity
deficit from 298 MW to 203 MW, a reduction of 95 MW. Ellsworth Direct at 11. This capacity
deficit reduction is only 16 percent of Jackalope's nominal capacity(95 MW/ 600 MW).
STAFF COMMENTS 5 MAY 13, 2025

Relatedly, when the Company calculated the Jackalope levelized cost of capacity it used
a capacity factor of 39 percent,3 which means that Jackalope is expected to have an average
output over time of 234 MW (600 MW x 0.39).
Staff interprets these two facts to mean that a majority of Jackalope's output is not
contributing to the capacity deficit during peak hours. Rather the majority of Jackalope's output
(234 MW—95 MW= 139 MW) is merely providing cost-effective energy. In effect, the
Company is overpaying for the capacity deficit benefit it will receive but the overpayment is
offset by cost-effective energy.
This concept may become more clear by considering an alternative resource: a gas-
powered peaking plant. The availability of a gas plant to meet load is approximately 97.5
percent4 so a 100 MW peaking gas plant would provide 97.5 MW of capacity deficit reduction.
The capital expenditure for a 100 MW gas plant is much less than the expenditure for the 600
MW Jackalope project, yet each provides approximately the same amount of capacity deficit
reduction.
The reason that Jackalope is selected as the LC-LR option is because its tax-subsidized
energy costs drive its overall price down over 20 years, while the gas plant's fuel costs drive its
overall price up. The LC-LR determination for Jackalope hinges on its tax-subsidized energy
costs.
Staff agrees that the cost-effective energy from Jackalope is a valid benefit to customers
but also believes that because the project justification is based on the need for capacity, the
benefits should be more directly tied to that need.
B. Production Tax Credit Risk
With the economic justification in mind, Staff observes that this project faces a large
cost-related risk: the provision of federal PTCs. PTCs are currently authorized by the Inflation
Reduction Act ("2022 IRA"), and assignable to the resource owner for each megawatt-hour
("MWh")the renewable resource generates. Because PTCs are tax credits, their true value is
determined by the equivalent income that will not be taxed. This income-to-tax gross-up factor
sets the PTC effective value at approximately $45/MWh.
3 Response to Staff s Request No.7—Confidential Attachment,PPA Input and Ownership Input tabs.
4 Id.
STAFF COMMENTS 6 MAY 13, 2025

1. The Jackalope PPA Risk
Concerning the Jackalope PPA, the developer is the resource owner and will receive the
PTC benefit. Staff believes the developer has accounted for the PTCs in his pricing to the
Company. However, due to the nature of the PPA, the developer bears the financial risk if the
PTCs are not realized; thus, Staff does not object to this part of the overall Jackalope project.
2. The Jackalope BTA Risk
Concerning the Jackalope BTA, the Company will become the resource owner and will
receive the PTC benefit. Therefore, if the PTCs are not realized, the financial impact to the
Company will be substantial.
According to the Company's cost workbook, the Company assumed the PTCs will reduce
the net present value ("NPV") cost of the project from to , a reduction
of 5
3. Payment of PTCs is Uncertain
Although the 2022 IRA is established law, the Trump Administration has been
advocating for an end to most of its provisions, including tax credits. In Executive Order 14154,
Unleashing American Energy, the President articulated in Section 7 his intent to terminate the
Green New Deal, which includes the 2022 IRA.
In addition, the Republican-controlled Congress is considering a repeal of the 2022 IRA.
House Resolution 191 was introduced in January 2025, and it calls for the full repeal of the 2022
IRA.6 Recently, a group of 38 Republicans issued a letter calling for a"full repeal" of the
energy tax credits.7 The President is pushing Congress to resolve this issue this summer.
4. Rescission of Tax Credits Will Change the LC-LR Solution
If the 2022 IRA tax credits are rescinded, Staff believes the Jackalope Project will no
longer be the LC-LR solution.
5 Response to Staff s Request No.7—Confidential Attachment,IPC74WNPP30030027.0 tab.
6 https://www.congress.gov/bill/119th-congress/house-bill/191
7 https://thehill.comZpolic./e�g_y-environment/5278304-38-republicans-call-for-full-repeal-of-democrats-energy-
tax-credits/
STAFF COMMENTS 7 MAY 13, 2025

In its response to Production Request No. 1, the Company stated that "whether or not ITC
and PTC assumptions are analyzed, all projects would likely remain in their relative ranking as
all final shortlist projects are subject to an ITC or PTC."
First, Staff believes that the 20-year NPV impact of ITCs and PTCs are different because
PTCs provide more value than ITCs. Therefore, ITC-based projects would become more
competitive relative to PTC-based projects.
Second, Staff analyzed the sole gas-based proposal, which does not benefit from tax
credits, and believes that it could become the LC-LR solution. The Company's cost worksheets
show that the NPV of the gas resource would be , assuming operation at 100%
capacity(maximum fuel costs). The NPV of the Jackalope BTA (with no PTC) is
The NPV of the Jackalope PPA is . Together, the NPV of the Jackalope Project is
. Staff does not believe that the additional cost-free energy that the Jackalope
solution would provide over 20 years will offset the cost differential. Furthermore,
the gas-based proposal was for a 120 MW plant; therefore, it would offset the capacity deficit by
117 MW (120 x 0.975).
In summary, if the PTCs are rescinded, Staff believes the gas-based proposal would
become the least-cost solution and it would provide a larger capacity deficit reduction, which is
tied more directly to the need.
C. Federal Permit Risk
The Jackalope Project faces an additional risk: the risk that it will not receive the
necessary federal permits. On January 20, 2025, a Presidential Memorandum paused federal
permits for wind projects, which includes the Jackalope Project.8 Section 2 (a) of the President's
Memorandum states that the relevant Secretaries and Administrators "shall not issue new or
renewed approvals, rights of way, permits, leases, or loans for onshore or offshore wind projects
pending the completion of a comprehensive assessment...."
Staff inquired about how the Company plans to proceed and mitigate potential delays,
given the Presidential Memorandum. The Company cited the BTA, which establishes June 30,
2026, as the deadline for the developer to obtain the necessary permits. The Company also
8 Temporary Withdrawal of All Areas on the Outer Continental Shelf from Offshore Wind Leasing and Review of
the Federal Government's Leasing and Permitting Practices for Wind Projects—The White House
STAFF COMMENTS 8 MAY 13, 2025

stated that the National Environmental Policy Act ("NEPA")process can continue during this
time,because the President's Memorandum only suspends final decisions. Accordingly, the next
NEPA milestone is to publish the Environmental Impact Statement that is scheduled to occur in
August 2025. See Company's response to Production Request No. 6. Additionally, the
Company stated, "the final grant cannot be authorized under the current Memorandum,but the
Company believes the ability to approve authorizations will be reinstated in time to meet the
contractual firm date obligations." Company's response to Production Request No. 13. The
Company believes that the project has made "substantial"progress for federal permitting so far.
Staff is not convinced by the Company's optimism about the timely approval of permits
based on the uncertain timeline of when the President's Memorandum will be lifted. Staff
believes there will be significant operational risks if the Company relies on this project and the
necessary permits are delayed or denied.
Relatedly, the Company has been adversely impacted by delayed permitting for its
Boardman to Hemingway(`132H") transmission line.9 As discussed later in this document, the
complications from that delay are part of the reason this case and these resources have become so
critical.
D. Other Cost Risks
Import tariffs are another cost risk faced by any potential project. The Trump
Administration has been revising tariffs on a frequent basis, with little or no notice. Depending
on the country of origin for each major component of a project(or the underlying sub-
components), the project price could vary wildly.
Staff believes that this is an unknowable cost risk, and the risk is applicable to all
projects, regardless of type. Until the tariff situation stabilizes, Staff believes the most
reasonable approach is to deal with any tariff issue as they arise.
E. No Timely Alternatives
Finally, Staff is aware that at this late point in the acquisition process, there are probably
few, if any alternative projects that can meet the Company's 2027 capacity deficit. In IPC-E-25-
9 https://www.newsdata.com/clearing Lip/supply and demand/idaho-power-hopes-b2h-construction-can-start-in-
2025-but-one-hurdle-remains/article d2319ldc-ca27-llef-9616-4fa980cc2blc.html
STAFF COMMENTS 9 MAY 13, 2025

10, a related case filed almost three months after this one, the Company revealed that five of the
ten FSL projects are no longer feasible, and four of the five feasible projects (including this one)
are being put forward as part of the Company's solution. Staff surmises that the tenth and last
FSL project is also necessary to help meet the 2027 capacity deficit,because the Company
asserts its current four projects are insufficient.
Staff also presumes that projects that did not make the FSL are now infeasible due to
their likely demobilization and the relatively late date. This would include the single gas-based
proposal discussed earlier in this section. Staff is unsure if the Company has investigated any of
these alternatives.
This puts the Commission in the predicament of choosing between(1) approving a
project that could be prohibitively expensive to ratepayers (due to cancelled PTCs) and/or fail to
obtain the necessary permits, or(2) denying the project, which could result in potential delays in
serving new load or incurring an increased system reliability risk.
Staff recommends that the Commission approve the Jackalope Project (both the PPA and
the BTA)but prohibit the Company from seeking additional revenue recovery from ratepayers if
the PTCs are canceled. This shifts the PTC cost risk to the Company, which is in a better
position to know of existing alternatives and to weigh the risks accordingly.
F. CPCN for the BTA
Staff evaluated the Company's Application with Idaho Code § 61-526 and Idaho Public
Utilities Commission Rule of Procedure 112. Staff believes the Company has met the
requirements of Idaho Code § 61-526 showing: (1) financial ability, (2) good faith of the
Applicant, and(3)public need. Additionally, the Company provided documents through its
Application and through discovery that Staff believes satisfies Rule 112.
Therefore, Staff recommends that the Commission grant a CPCN for the approximately
300 MW of wind turbine generators that the Company will acquire through the BTA.
G. Final Details
Staff reviewed many other aspects of the Jackalope Project and has no objections to most
of the terms of the PPA and BTA, including COD guarantees,performance guarantees, and
"Green Tag" ownership. There were, however, two final topics that merit additional discussion.
STAFF COMMENTS 10 MAY 13, 2025

1. FERC Waiver and Transmission Constraint Modeling
Staff reviewed the BTA and noticed within the agreement that the Company needed a
waiver from Federal Energy Regulatory Commission("FERC")to change the Point of
Interconnection. The purpose of the FERC waiver was to relocate the point of interconnection
identified in the applicable Large Generator Interconnection Agreements supporting the
Jackalope PPA and Jackalope BTA from the existing Bridger Substation to a newly identified
Jackalope Switching Station. Staff verified that the FERC waiver was granted by order on
December 18, 2024. Company's response to Production Request No. 15. This waiver is critical
to the Company's plans to connect the wind facilities to the Company's transmission facilities.
Additionally, the project will be using the Bridger-West 800 MW transmission path to
deliver the energy to the Company's balancing authority. This transmission path has historically
been constrained due to the volume of energy moving east to west. When the Company
evaluated the Jackalope bid, the modeling accommodated the wind generation by flexing the
output from the Jim Bridger units. The Company states that the Jackalope project will utilize
228 average MW on the transmission path and the remaining transmission can be utilized by
Bridger output.10 Given these responses, Staff is satisfied with the availability of transmission
capacity.
2. 35 year Wind Turbine Life Expectancy
The industry-standard life expectancy of wind turbines only recently increased from 25
years to 30 years, and this increase remains unproven." The Company is requesting the
approval of a 35-year term for the PPA and approval of a CPCN for a 35-year resource the
Company will own.
The bidder for the PPA identified the design life of its 300 MW PPA as 35 years;
therefore, the Company evaluated the economics of the project using 35 years as the asset life.12
However to ensure all wind assets were cost-modeled on the same basis, the Company evaluated
all wind asset purchases with a 30-year asset life. Therefore the BTA was modeled and
evaluated with a 30-year asset life. Following its evaluation and selection of the BTA in the final
10 Company's response to Production Request Nos. 14 and 20.
"https://www.nrel.gov/docs/fy25osti/92256.pdf
'Z Company's Response to Production Request No. 12.
STAFF COMMENTS 11 MAY 13, 2025

shortlist and after negotiations began, the Company updated the BTA asset life to be consistent
with the PPA term. In the Company's response to Production Request No. 18, the Company
offered no justification for accepting the extended life expectancy other than that the Developer
proposed it.
Staff is not concerned about the 35-year asset life for the PPA. The developer bears all
the risk for the PPA term, as it will have to supply the energy. However, Staff is concerned
about the 35-year asset life for the BTA, because the ratepayers bear the risk. There is no
extended warranty and there is no justification for a 35-year term. Additionally, this longer asset
life matters for depreciation, AFUDC accumulation, and IRP modeling assumptions. If a CPCN
is approved, Staff recommends a 30-year life expectancy for accounting purposes and for future
IRP modeling.
V. A Larger Problem—Insufficient Acquisition Lead Time
Staff believes that the contextual circumstances of this case is the latest manifestation of a
larger underlying problem—insufficient acquisition lead time. Insufficient acquisition lead time
manifests itself in different ways:
a. It pre-empts long lead-time resources from being considered or proposed;
b. It creates accelerated COD deadlines that eliminate otherwise competitive proposals;
and
c. It forces riskier and/or more expensive proposals to be selected, such as this one.
Staff believes that this situation is getting worse, and attributes it to: (1)rapidly rising new large-
load growth; (2) delays to B2H; and(3) an inordinately long acquisition process cycle time of the
Company's procurement and resource selection process. Each of these three factors are
discussed below.
A. New Large Load Growth
The 2021 Integrated Resource Plan ("IRP") identified that the Company would encounter
a capacity deficit in 2023, its first in a decade. Since then, the Company has struggled to procure
sufficient resources to meet its growing load and has resorted to filling yearly deficits
incrementally each year.
STAFF COMMENTS 12 MAY 13, 2025

In the 2023 IRP, the Company projected that load growth would increase even faster
beginning in 2026 through 2031, which intensifies the problem. The preliminary results of the
2025 IRP suggest the load growth will increase by an even larger amount than amounts
forecasted in the 2023 IRP. This rapid growth creates new capacity deficits that perpetuate the
compressed acquisition timelines. Unfortunately, this could result in alternatives that cannot be
considered due to the lead times necessary to procure and construct longer lead-time projects and
to settle for projects that may not be optimal for the Company's system, the impact falling on the
Company's ratepayers.
Because of the sustained nature of this problem, Staff believes the Company should
consider the potential to delay or mitigate load ramps of large new customers. Although the
Company has a duty to serve load, Staff believes there is some flexibility in the timing of when
new load is served. Because of the cost implications articulated above, Staff believes the
Company should not rule out any supply or demand-related alternatives until the Company can
get ahead of its deficits.
The problems associated with data centers and new large load customers are affecting
utilities across the country. Some customers are bringing their own energy resources. Utility
companies and state legislatures are contemplating new requirements for large load customers to
obtain their own energy resources. Staff believes this type of policy could alleviate some of the
acquisition time pressure, and it would also shift much of the cost risk from existing customers to
the new large load customers.
B. B2H Delay
Another factor creating insufficient acquisition time is the delayed construction of the
B211 transmission line. Due to permit delays, the B2H COD has been delayed from June 2026 to
closer to the end of 2027. In the 2023 IRP, the Company modeled B2H as a 500 MW resource
that was the critical resource to meet the 2026 capacity deficit and beyond. .
The 13211 delay is compounding the capacity deficits in 2026 and 2027 and materially
contributing to the urgency for the Jackalope project(as well as others).
Also, in Case No. IPC-E-23-01 (CPCN for 132H), Staff expressed concerned about cost
overruns, approval of permits, and other likely delays, which led to a recommendation for a soft
cap of project costs. In Commission Order No. 35838, the Commission authorized a soft cap on
STAFF COMMENTS 13 MAY 13, 2025

the 132H project, which included the cost of delays. The Order also stated, "In the event of
schedule delays requiring mitigation to meet capacity requirements, the Company should expect
to provide comparisons between the cost of B2H with and without schedule delays from a total
cost perspective."Id. at 14.
Staff recommends that the Company prepare a preliminary cost comparison now, in
alignment with the Commission Order, to allow preliminary assessment of the potential
implications.
C. Long Acquisition Process Cycle Time
Finally, Staff reiterates a point it has raised in other recent cases. The current REP
acquisition process is inordinately long, which shortens the time available for the permitting,
design, and construction of the actual resource.
Staff suggests that the Company strive to issue its RFPs more in advance of the need and
strive to shorten the RFP acquisition timeline.
STAFF RECOMMENDATION
Staff makes the following recommendations:
1. Approve the PPA for 300 MW of wind generation;
2. Grant Idaho Power a CPCN for the Jackalope BTA;
3. Forbid the Company from recovering corresponding PTC revenue requirement for the
Jackalope BTA if the federal PTCs are rescinded;
4. Direct the Company to use a 30-year life expectancy for accounting purposes and for
future IRP modeling for the BTA;
5. Encourage the Company to consider different ways to delay or mitigate large load
growth; and
6. As a supplement to Case No. IPC-E-23-01, require the Company to provide a report
comparing the current cost of B2H with and without schedule delays from a total cost
perspective.
STAFF COMMENTS 14 MAY 13, 2025

Respectfully submitted this 13th day of May 2025.
- b,4kJ `.
Chris Burdin
Deputy Attorney General
Technical Staff.Matt Suess,Kimberly Loskot,Seungjae Lee
1:\Utiitity\UMISOCOMMEM'S\IPC-E-24-46 Comments-Redacteddocx
STAFF COMMENTS 15 MAY 13, 2025

CERTIFICATE OF SERVICE
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DONOVAN E. WALKER TIM TATUM
IDAHO POWER COMPANY IDAHO POWER COMPANY
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