20250513Comments - Redacted.pdf

RECEIVED
Eric L. Olsen(ISB#4811) May 13, 2025
ECHO HAWK& OLSEN, PLLC IDAHO PUBLIC
505 Pershing Ave., Ste. 100 UTILITIES COMMISSION
P.O. Box 6119
Pocatello, Idaho 83205
Telephone: [phone]
Facsimile: [phone]
Email: elo(a)echohawk.com
Attorney for Intervenor Idaho Irrigation Pumpers Association, Inc.
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER CASE NO. IPC-E-24-46
COMPANY'S APPLICATION FOR
APPROVAL OF A POWER PURCHASE IDAHO IRRIGATION PUMPERS
AGREEMENT WITH JAKALOPE WIND, ASSOCIATION, INC.'S WRITTEN
LLC,AND A CERTIFICATE OF PUBLIC COMMENTS
CONVENIENCE AND NECESSITY FOR
THE JAKALOPE WIND PROJECT
1 Idaho Irrigation Pumpers, Inc., by and through counsel, hereby submits its Written
2 Comments to Idaho Power Company,pursuant to Commission Rule 225, as follows:
3 Q. PLEASE STATE YOUR NAME,ADDRESS,AND EMPLOYMENT.
4 A. My name is Deborah Glosser. I am serving as a consultant for Lance Kaufman/Western
5 Economics, LLC, 2623 NW Bluebell Dr, Corvallis, Oregon, 97330.
6 Q. WOULD YOU BRIEFLY DESCRIBE YOUR EDUCATIONAL BACKGROUND
7 AND PROFESSIONAL EXPERIENCE?
8 A. I earned a PhD in Civil Engineering with a focus in Materials from Oregon State
9 University in 2020, an MS in Geophysics from the University of Pittsburgh in 2013, and
10 a JD from Duquesne University in 2005. Since 2020, 1 have been an Assistant Professor
11 at Western Washington University in Bellingham, with appointments in the Institute for
12 Energy Studies, Engineering and Design, and the Advanced Materials Science and
13 Engineering Center. I was recently awarded tenure and will return next year as an
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.WRITTEN COMMENTS—Page I
CASE NO.IPC-E-24-46

I Associate Professor. My research group develops thermal energy storage materials for
2 solar thermal energy power. I teach courses at Western in the areas of energy storage
3 materials, mechanics of materials, energy policy, and thermodynamics of materials.
4 Previously, I was a member of the Staff of the Oregon Public Utilities Commission
5 (2016-2019), where I worked in both resource planning and rates. As a Senior Energy
6 Analyst at OPUC I analyzed utility integrated resource plans (IRP) and related filings to
7 ensure regulatory requirements were met, represented OPUC staff in hearings and public
8 meetings, and engaged with stakeholders to ensure the Commission's mission of
9 protecting ratepayers was met. Prior to my role at OPUC, I worked as a researcher at the
10 US Department of Energy's National Energy Technology Laboratory(2011-2016). At
I I NETL I worked on multiple research portfolios related to natural gas, coal, carbon
12 storage, and rare earth elements.
13 Q. ON WHOSE BEHALF ARE YOU COMMENTING?
14 A. I am commenting on behalf of the Idaho Irrigation Pumpers Association, Inc. ("IIPA").
15 Q. WHAT IS THE PURPOSE OF YOUR COMMENTS IN THIS PROCEEDING?
16 A. My comments are in response to Idaho Power's (the Company")proposal for the
17 Commission to approve a 35-year Power Purchase Agreement("PPA") with Jackalope
18 Wind for the purchase of 300 MW of wind energy, and authorization for a certificate of
19 public convenience and necessity("CPCN")to acquire ownership of an additional 300
20 MW of wind generation capacity vis-a-vis a Build Transfer Agreement(`BTA"). The
21 combined 600 MW wind generation capacity projects are referred to collectively as "The
22 Jackalope Project" and are asserted by the Company as necessary, and the least-cost
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.WRITTEN COMMENTS—Page 2
CASE NO.IPC-E-24-46

I least-risk means to meet an identified capacity deficit of 298 MW to 320 MW in 20271.
2 The Company appears to be requesting that the Commission declare all future PPA
3 payments as prudently incurred expenses for ratemaking purposes, My comments will
4 address the risks and benefits of the Jackalope Project as outlined by the Company, and
5 as based on my own independent reviews of Company models, assumptions, and
6 comments.
7 Q. IS PRUDENCY THE FORMAL STANDARD FOR GRANTING A CPCN?
8 A. No, prudency is not the formal standard for granting a CPCN. The primary criteria are
9 typically whether the proposed project is necessary to meet customer demand and
10 whether it represents a reasonable investment in light of the utility's long-term resource
11 planning. However, prudency remains an implicit consideration in many CPCN cases,
12 particularly where the Commission elects to impose soft caps or other cost-containment
13 measures.
14 Q. WHY WOULD THE COMMISSION IMPOSE COST CONTAINMENT
15 MEASURES IN CPCN CASES IF PRUDENCY IS NOT THE FORMAL
16 STANDARD?
17 A. When the Commission imposes cost containment measures on proposed projects at the
18 CPCN stage, it is implicitly signaling concern about the prudency of the proposed
19 investment, indicating that it is unwilling to expose ratepayers to unlimited financial risk,
20 and that it wants to ensure that the project remains cost competitive over its lifecycle.
1 Company filing in case number IPC-E-24-26,p.2,"The procurement process resulted in the identification
of least-cost,least-risk resources necessary to fill the identified 2027 capacity deficiency of 298 MW to 320 MW."
2 The Company application states that the PPA will not become effective until the Commission"declares
that all payments the Company makes for purchases of energy will be allowed as prudently incurred expenses for
ratemaking purposes."application at paragraph 10.This appears to either require a prudence determination in this
case,or requires that the Company file a rate case with a test year of 2027 prior to the contract beginning.
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I This approach reflects a recognition that ratepayer protection requires more than just a
2 demonstration of need. Ratepayer protection, and therefore a finding of public
3 convenience and necessity, also requires a reasonable assessment of long-term costs and
4 risks.
5 Q. HOW SHOULD THE COMMISSION CONSIDER PRUDENCY IN THIS CASE?
6 A. In the present case, the Commission should ensure that the Company's cost assumptions
7 for the Jackalope Wind Project are realistic and that they fully reflect the risks associated
8 with permitting, transmission, imputed debt, lifecycle costs, and capacity contribution.
9 Without this scrutiny, the Commission risks granting a CPCN for a project that may later
10 prove to be economically unviable or significantly more expensive than modeled,
11 potentially requiring ratepayers to absorb the cost of alternative capacity or emergency
12 market purchases.
13 Q. FROM YOUR REVIEW OF THE FILING AND OTHER SOURCES,WHAT ARE
14 YOUR CONCLUSIONS AND RECOMMENDATION?
15 A. Based on my review of Company filings, models, and comments, I have concluded that
16 several clear risk factors exist with respect to the proposed Jackalope Project, and—
17 without a Commission ruling for cost containment—the impact of these risks may be
18 carried by ratepayers, with no guarantees from the Company either structurally or
19 affirmatively, that it will not pass along additional, future, or excess costs to ratepayers. I
20 will describe how the Jackalope Wind Project is neither necessary nor prudent on the
21 basis of externalities such as changes in federal policy and macroeconomic terrain, as
22 well as how inconsistencies in Company modeling both overestimate capacity need as
23 well as underestimate costs associated with the project. In short, I will describe how the
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CASE NO.IPC-E-24-46

I proposed PPA and BTA are neither necessary nor prudent. For these reasons, I am
2 proposing that the Commission impose cost containment measures, which I will justify
3 and describe in this testimony, on the proposed Jackalope Project.
4 Q. WHAT IS THE PURPOSE OF THE COMPANY'S APPLICATION IN THIS
5 CASE?
6 A. The Company is requesting that the Commission issue an order: 1)to approve the 35-year
7 PPA between Jackalope Wind, LLC and Idaho Power Company to supply approximately
8 300 MW to the Company' s system; and 2)to grant the Company a CPCN to acquire
9 ownership in a wind turbine generator power plant providing approximately 300 MW of
10 generation through a BTA.
11 Q. WOULD IT BE APPROPRIATE TO AWARD THE COMPANY A
12 CERTIFICATE
13 OF PUBLIC CONVENIENCE AND NECESSITY OR A PPA FOR THIS
14 PROJECT?
15 A. No, it would not be appropriate to award the Company a CPCN for this project, or to
16 approve the PPA. For reasons I will elaborate on in this comments, the proposed projects
17 does not serve the public interest or represent the least-cost, least-risk means of meeting
18 capacity needs for customers
19 Q. WHAT ARE SOME OF THE RISKS THAT THE RATEPAYERS WILL HAVE
20 TO BEAR IF A CPCN IS ISSUED AT THIS TIME?
21 - The PTC may not be available
22 - Permitting and execution risks remain outstanding for the project
23 - Seasonal variability is improperly modeled and may inflate actual resource need
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.WRITTEN COMMENTS—Page 5
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I - The Jackalope Project paradoxically overbuilds but underdelivers effective peak
2 capacity
3 -Dispatch conflicts due to transmission constraints are not adequately considered
4 which results in hidden risks and costs
5 - The lifecycle risk of the project is understated
6 - The cost of the project is substantially higher than the marginal cost of energy
7 Q. WHAT ARE THE CONSEQUENCES OF THESE RISKS?
8 A. Taken together, these factors inflate the project's perceived economic value while
9 understating its true cost,potentially resulting in significant ratepayer exposure. The
10 actual levelized cost could be substantially higher than claimed by the Company if these
11 risks materialize. Similarly, Idaho Power's Integrated Resource Plan (IRP) assumed that
12 wind resources would contribute capacity at 36% of nameplate 3'but if the Jackalope
13 Project can only deliver 10-20% of firm capacity, its effective LCOC may exceed
14 Company estimates, making it less competitive than other firm capacity options such as
15 gas combustion turbines. To ensure a least-cost, least-risk outcome, Idaho Power should
16 rerun its resource selection modeling with updated, risk-adjusted cost estimates for the
17 Jackalope Project and directly compare those results to other potential capacity resources.
18
19 The PTC credits may not be available for the proiect
20 Q. PLEASE EXPLAIN WHY PTC CREDITS MAY NOT BE AVAILABLE FOR THE
21 PROJECT AS FORECASTED BY THE COMPANY.
3 Appendix C of Idaho Power's 2023 IRP.
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.WRITTEN COMMENTS—Page 6
CASE NO.IPC-E-24-46

I A. Section 7(a) of Presidential Executive Order No. 14154 (Unleashing American Energy)
2 pauses "the disbursement of funds appropriated through the Inflation Reduction Act of
3 2022." The Company interprets Executive Order No. 14154 as not affecting the ITCs,
4 PTCs, or any transferrable tax credits established under Internal Revenue Code Section
5 64184. While the US Constitution grants Congress the authority to levy taxes and create
6 and modify tax credits, there is a clear shift in federal policy away from renewable energy
7 resources, and there is uncertainty regarding whether the ITC and PTC will continue to
8 be administered by the IRS, either as a consequence of EO 14154, forthcoming
9 Congressional action, or administrative delays that may occur as the IRS reviews their
10 processes and how they align with the new administration's policies.
11 Q. COULD PERMITTING OR CONSTRUCTION DELAYS AFFECT THE PTC
12 FOR THE JACKALOPE PROJECT?
13 A. Yes. The PTC provides $28/MWh only after the project begins generating electricity. If
14 permitting delays push the project's COD past mid-2027 or later, the 10-year window for
15 claiming the PTC will be delayed, reduced, or missed entirely. I will describe permitting
16 delay risks in the next section of comments in more detail, but if permitting delays
17 require a project re-scoping or trigger a supplemental NEPA review, the ability to meet
18 the criteria for PTC conditions might be lost entirely.
19 Q. IF THE PTC IS NOT RECOGNIZED,WILL THIS AFFECT THE LEVELIZED
20 COST OF THE 300 MW WIND GENERATION PLANT FOR WHICH THE
21 COMPANY IS SEEKING A CPCN?
a Response to Staff Request for Production#15 the Company states"Because Section 7(a)of the
Presidential Executive Order does not specifically address tax credits,and any revocation to tax credits would
require congressional action,Idaho Power's interpretation is that Investment Tax Credits and PTCs do not fall under
the Executive Order and will remain unchanged".
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.WRITTEN COMMENTS—Page 7
CASE NO.IPC-E-24-46

I A. Yes. The Company's levelized cost calculation includes recognition of the PTC. I have
2 reviewed the Company's financial models and without the PTC,the project's levelized
3 cost would increase by roughly$25-$30/MWh. The Company's model shows
4 -MWh6 levelized now,but without the PTC this value would be around M/Niw'h
5 based on a 30-year life, which represents a cost increase of up to 50%. This would also
6 increase the revenue requirement.
7 Q. WHAT WOULD BE IMPACT OF LOSING THE PTC ON THE REVENUE
8 REQUIREM[ENT?
9 A. If the project fails to qualify for the PTC either due to administrative revocation of the
10 credit for wind projects, or due to permitting delays, the entire value of the credit will be
11 lost. The present value of that 10-year stream of tax credits, discounted at a 7%rate, is
12 approximately$199.5 million. In other words, if the project loses PTC eligibility,the
13 total cost that must be recovered from ratepayers increases by nearly $200 million,or
14 about 25%more than the original capital cost alone.
15 Q. IF THE PTC OR ITC IS NOT RECOGNIZED,WILL THIS AFFECT THE
16 LEVELIZED COST OF OTHER SHORTLISTED PROJECTS?
17 A. Possibly,although per the Companyg only three shortlisted projects remained viable for
18 both the 2025 and 2027. This level of attrition suggests that the Company's portfolio
19 analysis was not based on a truly robust or competitive set of options. And,the new
5 Confidential attachment to Staffs Request for Production#7.
e Confidential Response to Staff Request for Production#15.
7 Using the Company's model with a 38.6%capacity factor,300 MW plant size, 1,014,000 XlWyr,the
annual PTC value=28.4 million/year.That 10 year steam value discounted at a standard 7% WACC gives a NPV
of$199.5 million.
a Response to Staff Request for Production#2,the Company states"there are only three remaining projects
from both the 2026 and 2027 bids that remain viable,the request for additional AURORA modeling is not
necessary"
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.WRITTEN COMMENTS—Page 8
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I administration's stated goal of transitioning away from renewable energy(and in
2 particular wind energy), it would be speculative to assume that the PTC or ITC would be
3 evenly honored for wind and other renewable based projects over fossil fuel based ones.
4 Q. IF THE PTC IS NOT RECOGNIZED,WILL RATEPAYERS BEAR ANY OF
5 THE RISK?
6 A. Yes, if the PTC is not recognized, ratepayers will bear risk. Without the PTC, the
7 levelized costs will increase, revenue requirement would be raised, and the Company
8 may seek to increase retail rates for ratepayers. The Company is gambling against the
9 loss of the PTC, and in the process violating the principles of least-risk and prudency.
10 Q. GIVEN THE UNCERTAINTY SURROUNDING THE COMPANY'S ABILITY
11 TO CLAIM THE PTC,IS THE JACKALOPE PROJECT LEAST COST/LEAST
12 RISK?
13 A. No. Given the material uncertainty of the PTC being honored for wind and other
14 renewable energy projects—and given the uncertainty surrounding potential permitting
15 delays—a finding of prudency for the Jackalope project is seriously undermined. A
16 finding of prudency would require the Company show that Jackalope's performance
17 (including cost, deliverability, and capacity) remains superior to all other reasonable
18 alternatives, and this has not been demonstrated. Therefore, the Jackalope project cannot
19 be considered least-cost, least-risk.
20 Q. DO YOU RECOMMEND ANY COST CONTAINMENT MEASURES IN LIGHT
21 OF THE UNCERTAINTIES WITH THE PTC?
22 A. Yes. The Commission should require that Company shareholders bear the risk of the PTC
23 uncertainty. If the project fails to qualify for PTC or otherwise loses eligibility, the
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.WRITTEN COMMENTS—Page 9
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I difference in cost should be absorbed by the shareholders of the Company and not passed
2 onto ratepayers. This can be accomplished by reducing the Company's power cost
3 revenue requirement in rate proceedings by the value of the lost PTCs. Without this risk
4 sharing mechanism, the Jackalope Project could shift hundreds of millions of dollars in
5 cost to ratepayers if the PTC eligibility is delayed or lost.
6
7 Permitting and execution risks remain outstanding for the Project
8 Q. WHAT IS THE CURRENT STATE OF PERMITTING FOR THE JACKALOPE
9 PROJECT?
10 A. The Jackalope Project requires a BLM right of way grant for the portion of the project
11 that crosses federal land9. At present, per the Company, only the environmental surveys
12 are complete. The EIS won't be published until August of 2025, and the ROD to approve
13 the project isn't expected until March of 2026.
14 Q. CAN PERMITTING RISKS FOR THE PROJECT IMPACT ITS EXECUTION?
15 A. Yes. And several risks exist regarding permitting and execution. The Jackalope Project is
16 required to be commercially operable by June 1, 2027. Thus, the Company has little more
17 than one year after the ROD to complete the final design, construction, interconnection,
18 testing, and commissioning of the project. If at any point the ROD is delayed(or denied),
19 the Jackalope Project cannot meet its commercial operating date, and the Company will
20 face a capacity shortfall.
9 Response to Staff Request for Production 2,number 24,per the Company: "The Jackalope Project has
made substantial federal permitting progress.The Bureau of Land Management(`BLM")in Wyoming continues to
make progress on environmental surveys and has a scheduled release of the Environmental Impact Statement in
August 2025 and a Record of Decision in March 2026"
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.WRITTEN COMMENTS—Page 10
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I Q. CAN YOU DESCRIBE SPECIFIC RISKS THAT HAVEN'T BEEN
2 ADEQUATELY ADDRESSED BY THE COMPANY?
3 A. The main specific risk categories surrounding the project include shifts in the regulatory
4 landscape; supply chain issues; developer default risks; and as stated above, an overly
5 tight execution timeline that the Company hasn't fully demonstrated they can meet.
6 Regarding the regulatory landscape, federal permitting is increasingly subject to political
7 delays, with the Trump administration shifting policy and regulatory implementation
8 away from wind power. While the Company claims that the project will not be impacted
9 by the shifting regulatory and political landscape, this is very much a bet on a regulatory
10 outcome that the Company doesn't control. Similarly, externalities like supply chain
11 issues and cost increases due to tariffs have not been addressed by the Company.
12 Regarding developer default risks, the Company claims that it has contractual remedies in
13 the event of default. However, if the remedies are liquidated damages, the Company may
14 recover some money, but the risk of capacity deficit for ratepayers remains.
15 Q. HAS THE COMPANY PROVIDED A ROBUST RISK ANALYSIS TO
16 DEMONSTRATE FEASIBILITY OF THEIR TIMELINE?
17 A. No, the Company has not provided a robust risk analysis to demonstrate the feasibility of
18 their timeline. It has not provided any critical path method schedules or construction risk
19 analyses to demonstrate how it can meet the tight timeline required. Furthermore, the
20 Company has not demonstrated that it has any feasible contingency plans in place in the
21 event of a delay. Approving a CPCN under these conditions would expose ratepayers to
22 unquantified reliability, financial, and procurement risks.
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.WRITTEN COMMENTS—Page 11
CASE NO.IPC-E-24-46

I Q. WHAT IS THE IMPLICATION OF POTENTIAL PERMITTING DELAYS OR
2 FAILURES FOR A FINDING OF PRUDENCY?
3 A. A least-cost, least-risk finding requires that the Company select resources that are both
4 economically favorable and financially feasible. Here, the Company is relying on a
5 project with unresolved permitting and transmission risks—without a contingency plan—
6 which effectively shifts execution and reliability risks directly on to ratepayers. These
7 risks could force higher costs,necessity for replacement resource procurement, and
8 reliability violations. Therefore, the Jackalope project does not meet the standard for
9 least-cost, least-risk.
10 Q. DO YOU RECOMMEND ANY COST CONTAINMENT MEASURES IN LIGHT
11 OF PERMITTING RISK?
12 A. Yes. Because permitting delays or failures can increase the total cost of the project
13 beyond the Company's estimate, the Commission should impose a soft cap on total
14 project capital expenditures. Any overages should require Commission approval or
15 alternatively, shareholder absorption. This mechanism prevents cost overruns from being
16 passed onto ratepayers. The cost estimate for the BTA10 provided by the Company is
17 _nullion.
18
19 Seasonal variability is improperly modeled and may inflate actual resource need
20 Q. DO YOU HAVE ANY CONCERNS REGARDING THE COMPANY'S
21 TREATMENT OF SEASONAL PEAK LOADS IN ITS EVALUATION OF THE
22 JACKALOPE PROJECT?
10 Company responses to Staff Request for Production#10.
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.N%RITTEN COMWENTS—Page 12
CASE NO.IPC-E-2446

I A. Yes. The Company's modeling of capacity shortfalls and resource performance does not
2 adequately account for the seasonal nature of both demand and renewable energy
3 generation. This deficiency is important when evaluating a wind resource such as the
4 Jackalope Project, which has an output profile that does not match the Company's
5 summer peak load conditions.
6 Q. WHAT SPECIFIC FLAWS EXIST IN THE COMPANY'S SEASONAL
7 CAPACITY ANALYSIS?
8 A. The Company models annual capacity deficits instead of seasonal capacity positions"
9 This allows them to mask summer-specific shortfalls despite known issues wind
10 resources underperforming during hot stagnant weather conditions. By averaging system
11 needs across the year, the Company can claim adequacy even when Jackalope may
12 contribute little to no capacity during summer peak hours. Additionally, the Company
13 applies an overly aggressive 95th percentile winter peak assumption 12 yet keeps summer
14 at the 75th percentile. This introduces considerable asymmetry into the forecast profile. It
15 also inflates the perceived winter risks which consequently allows the Company to justify
16 wind procurement(since wind tends to perform better during winter months). The
17 Company does not provide a clear justification for this treatment, and no sensitivity
18 analysis was performed to test the impact of using 851h or 90th percentiles instead.
19 Furthermore, the Company has not demonstrated that Jackalope's wind profile algins
20 with peak load timing in summer afternoons, particularly since wind capacity factors can
" Company response to Staff Request for Production n. 3. The Company states"Please
note,for resource acquisition purposes...seasonal capacity positions are not utilized."
12 Company response to Staff Request for Production n. 3,The Company states"The high end of the range
was calculated utilizing the 70th percentile peak load for March through October and the 95th percentile peak load
for November through February."
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.WRITTEN COMMENTS—Page 13
CASE NO.IPC-E-24-46

I fall significantly during critical heatwave events,which is when the Company is most
2 vulnerable to shortfalls.
3 Q. IF WIND DELIVERS LITTLE TO NO CAPACITY DURING SUMMER PEAK
4 HOURS,HOW WILL THAT AFFECT LEVELIZED COST OF CAPACITY?
A. If the wind projects deliver minimal to no capacity during summer peak hours, the LCOC
6 will increase substantially, and the claimed 2027 summer capacity shortfall cannot be
7 met. The Company's model shows the LCOC as_/kW-month 13. But,the model
8 assumes some contribution to firm capacity from the wind,which as described above, is
9 not the case. If the ELCC is closer to 20-30%,LCOC skyrockets,potentially to_
10 M/kW-monthly
11 Q. HO«'DO THESE MODELING FAILURES AFFECT A PRUDENCY
12 ANALYSIS?
13 A. These flaws prevent a determination of whether the Jackalope Wind Project provides
14 reliable, seasonally aligned capacity to meet the Company's system needs. Inadequate
15 accounting for summer peak risk,particularly in a portfolio with a heavy share of
16 variable renewables,results in system reliability gaps that may later require emergency
17 market purchases or costly resource additions. That outcome is contrary to the principles
18 of least-cost, least-risk procurement, and therefore a fmding of prudency cannot be
19 supported.
20 Q. DO YOU RECOMMEND THAT THE COMMISSION IMPOSE ANY COST
21 CONTAINMENT MEASURES IN LIGHT OF SEASONAL MODELING ISSUES?
13 Confidential Attachment to the company's Response to Staffs Request No.7.
14 LCOC=annual cost/effective capacity(kW)* 12.Assume fixed annual cost(capital and O and M).but
10%ELCC(i.e.30 MW instead of 300 MW).Cost is spread over far fewer kW,and the per kW cost goes up
dramatically.
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.WRITTEN COMMENTS—Page 14
CASE NO.IPC-E-24-46

I A. Yes. The Commission should only allow capacity payments for actual capacity delivered
2 during peak summer and winter months. The Company should be required to true up
3 annual capacity payments based on actual ELCC during these peak periods. The true-up
4 payment would be calculated as equal to (modeled ELCC —Actual ELCC) times the
5 nameplate capacity times the capacity payment. Additionally or alternatively, the
6 Commission should set a seasonal cost recovery cap, and cap the total annual recoverable
7 capacity cost based on a seasonally adjusted capacity factor. The cap should be based on
8 historical wind performance in the region. These mechanisms would prevent the
9 Company from over-recovering capacity cost in low-wind periods.
10
11 The Jackalope Project paradoxically overbuilds but underdelivers effective peak capacity
12 Q. HOW CAN A 600 MW RESOURCE NOT MEET A 300 MW CAPACITY NEED?
13 A. The Company is procuring the 600 MW nameplate Jackalope Project resource to solve a
14 300 MW capacity shortfall. However, the Effective Load Carrying Capacity of wind is
15 substantially lower than nameplate capacity, so it doesn't actually close the stated gap.
16 On paper, the Company is overbuilding by 300 MW, but underdelivering on the effective
17 peak load capacity. If Jackalope only adds 228 MW annually15, and possibly much less
18 during system peak, its ELCC is probably much less than the claimed 38%, and possibly
19 closer to 10-25%. Indeed, within Western Resource Adequacy Program, the ELCC
20 values of variable renewable resources have often been lower than estimated. The reasons
15 Company's response to Staff Request for Production 2,20:"With a 600 MW nameplate capacity and a
38 percent annual capacity factor,the Jackalope Project accounts for 228 average-MW("aMW")on the 800 MW
transmission line.Bridger Units 1 and 2,with a 357 MW nameplate capacity and a 42 percent annual capacity factor
cap,account for approximately 150 aMW on the 800 MW transmission line,for a combined 378 aMW. The
remaining 422 aMW of transmission can be utilized by Bridger Units 3 and 4."
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.WRITTEN COMMENTS—Page 15
CASE NO.IPC-E-24-46

I for this are articulated in PSE's 2023 resource adequacy analysis 16.The Company's
2 proposal simultaneously overbuilds nameplate resources while failing to prudently
3 address the specific nature of the capacity deficiency it seeks to resolve.
4 Q. THE JACKALOPE PROJECT IS PART OF A SUITE OF PROJECTS
5 PROPOSED BY THE COMPANY, SO IS IT NECESSARY FOR IT TO ADDRESS
6 THE FULL CAPACITY DEFICIENCY?
7 A. The Company claims that the Jackalope Wind Project is part of a broader resource
8 strategy 17, but it has not provided modeling that quantifies its firm capacity contribution,
9 demonstrates its indispensability within the selected portfolio, or shows that alternative
10 portfolios, which are potentially cheaper, more reliable, or better aligned with seasonal
11 demand, were ever fully considered. Without that evidence, a finding of least-cost, least-
12 risk or prudency is unsupported.
13 Q. DOES A FAILURE OF THE JACKALOPE PROJECT TO MEET THE FULL
14 CAPACITY DEFICIENCY AFFECT A FINDING OF PRUDENCY?
15 A. Yes. The Company is procuring a large, inflexible resource that may not resolve the very
16 problem it is being proposed to address. Without clear evidence that Jackalope's output
17 reliably aligns with the Company's peak demand profile, the project introduces both
18 financial and reliability risk to ratepayers , and a finding of prudency cannot be
19 supported.
20
16 https://www.pse.com/-/media/PDFs/IRP/2023/electric/chapters/07—EPR23_Ch7_Final.pdf
17 Direct testimony of Mr.Hackett,p. I I lines 18-22""Assuming all 2026 projects,the Jackalope Project,
and the Crimson Orchard Project reach commercial operation on time,the addition of the Crimson Orchard PPA and
the Crimson Orchard ESA would reduce the 2027 capacity deficit of 123 MW to a capacity deficit of 57 MW."
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.WRITTEN COMMENTS—Page 16
CASE NO.IPC-E-24-46

I Dispatch conflicts due to transmission constraints are not adequately considered which
2 results in hidden risks and costs
3 Q. PLEASE DESCRIBE THE TRANSMISSION POSTURE OF THE JACKALOPE
4 PROJECT IN RELATION TO THE COMPANY'S OTHER RESOURCES.
5 A. The 600 MW Jackalope Project will share an 800 MW transmission path with the 706
6 MW coal and gas Jim Bridger units'$. The idea is that Jackalope has a low marginal cost,
7 so Bridger can flex around it to avoid exceeding transmission limits. As I describe below,
8 the assumption used to arrive at this claim are not fully transparent and may be unrealistic
9 in light of the non-dispatchable nature of wind resources.
10 Q. DOES IDAHO POWER HAVE EXCLUSIVE OWNERSHIP OF THE BRIDGER-
11 WEST TRANSMISSION PATH?
12 A. No, the 800 MW transmission path is not exclusively owned by Idaho Power. It is jointly
13 owned with PacifiCorp19, and this shared ownership introduces potential capacity double-
14 counting issues: Since both companies have rights to this transmission corridor, if both
15 utilities plan to utilize their respective shares simultaneously without proper coordination,
16 it could lead to over-subscription of the transmission path. If the same transmission
17 capacity is assumed to be available for multiple uses, it may lead to reliability and cost
18 issues, which undermines the Jackalope Project's reliability and cost effectiveness.
19 Q. PLEASE EXPLAIN WHETHER THE TRANSMISSION CONSTRAINTS
20 DESCRIBED BY THE COMPANY ARE REALISTIC.
"Company's response to Staff's request for production 14: "Idaho Power's transmission rights on the
Bridger-West path total 800 MW...The output from the Jim Bridger plant with four units with a total nameplate
capacity of approximately 706 MW and the combined Jackalope wind project with total nameplate capacity of 600
MW"
19https:Hdocs.idahopower.corn/pdfs/AboutUs/PlanningForFuture/irp/2023/2023-irp-final.pdf,total E to W
capacity is 2400 MW;Idaho Power's share is 800 MW,PacificCorp's share is 1600 MW.
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.WRITTEN COMMENTS—Page 17
CASE NO.IPC-E-24-46

I A. The Company's transmission constraint modeling assumptions lack the transparency
2 necessary to determine whether they are realistic, and therefore, the curtailment and
3 flexibility risks may be understated. Per the Company, transmission constraints20 are
4 inputs into AURORA models, so no workpapers exist. Without workpapers, it's not
5 possible to verify curtailment or congestion outcomes. It's possible that Bridger can't flex
6 around Jackalope in real system conditions,which undermines the idea that the proposed
7 project is actually cost-optimal and fully deliverable based on actual system constraints.
8 Q. PLEASE CONTEXTUALIZE TRANSMISSION CLAIMS FOR JACKALOPE
9 WITH KNOWN LIMITATIONS OF WIND DISPATCH.
10 A. Wind output is a variable and therefore non-firm resource. It's not possible to ramp up
11 wind power to match demand. Meanwhile, the Bridger units have ramp rate limits as well
12 as regional haze constraints. So in high demand periods with low wind, neither the
13 Jackalope nor the Bridger units may be dispatchable in the way the Company is claiming.
14 The Company can't demonstrate how much of the proposed 600 MW of power is actually
15 deliverable under the real world transmission constraints. The Company models the
16 nameplate capacity for the Project, not the actual deliverable MW, and no documentation
17 was provided to show that the hourly output for Jackalope +Bridger will remain under
18 800 MW. If Bridger repowers or dispatches aggressively due to other system needs, the
19 ability of Jackalope to deliver energy will drop. This means that Jackalope's value may
20 be overstated in capacity expansion and reliability models. Without firm transmission
21 availability during peak periods, Jackalope risks becoming a stranded asset with minimal
22 contribution to Idaho Power's reliability needs.
20 Company response to IIPA's request for production 1-6 and response to Staff s second request 20.
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.WRITTEN COMMENTS—Page 18
CASE NO.IPC-E-24-46

I Q. DO THESE TRANSMISSION UNCERTAINTIES AFFECT A FINDING OF
2 PRUDENCY?
3 A. Yes. Jackalope's reliance on constrained transmission infrastructure materially
4 undermines the Company's claim that the project is prudent or represents a least-cost,
5 least-risk investment. The absence of transmission deliverability modeling or contingency
6 planning exposes ratepayers to elevated financial and operational risk, and fails to meet
7 the standards of transparent, risk-informed resource planning.
8 Q. DO YOU RECOMMEND ANY COST CONTAINMENT MEASURES IN LIGHT
9 OF POTENTIAL TRANSMISSION CONSTRAINTS OR DELIVERABILITY
10 CURTAILMENT?
11 A. Yes. I recommend that penalties be imposed on the Company in the event that the project
12 cannot deliver the claimed output due to transmission or deliverability constraints.
13 Q. HOW SHOULD THESE PENALTIES BE STRUCTURED TO PROTECT
14 RATEPAYERS?
15 A. I propose that the Commission consider three penalty structures, which can be imposed
16 jointly or severally: lost energy penalties; a capacity adjustment mechanism tied to
17 ELCC; and tiered financial penalties tied to curtailment.
18 Q. PLEASE DESCRIBE THE LOST ENERGY PENALTY YOU PROPOSE.
19 A. The Commission should rule that if the Jackalope Project fails to deliver some substantial
20 percentage (say 95%) of its expected annual energy production, the Company should be
21 required forfeit the right to recover the undelivered portion of the project through its
22 revenue requirement. If the project produces a smaller fraction of its expected energy due
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.WRITTEN COMMENTS—Page 19
CASE NO.IPC-E-24-46

I to transmission constraints, the Company should absorb the resulting lost revenue, rather
2 than passing the loss onto ratepayers.
3 Q. PLEASE DESCRIBE THE CAPACITY ADJUSTMENT PENALTY YOU
4 PROPOSE.
5 A. Capacity contribution should be evaluated concurrently with Jim Bridger capacity and
6 transmission limitations. The effective LCOC should be recalculated based on the
7 reduced/actual firm capacity,which will raise the cost per kW-month and reduce the
8 overall capacity payment.
9 Q. PLEASE DESCRIBE THE TIERED CURTAILMENT PENALTY YOU
10 PROPOSE.
11 A. The Commission should rule that if curtailment exceeds certain predetermined
12 thresholds, the Company should be subject to direct financial penalties. For example, if
13 curtailment is between 10% and 20%, the penalty should be $10/MWh. If curtailment is
14 greater than 20%, the penalty should be $20/MWh, and so forth. The $10/MWh and
15 $20/MWh values are illustrative. Exact penalties should be determined in the context of a
16 general rate case once parties have had an opportunity to fully evaluate the cost of
17 curtailment.
18 Q. WHAT IS THE RATIONALE FOR THE PROPOSED PENALTIES?
19 A. The proposed penalties would ensure that ratepayers pay only for energy that is actually
20 delivered, which will tie the Company's financial incentives with actual system
21 reliability. Without such mechanisms, the cost of the Jackalope Project could be
22 recovered from ratepayers, despite it not delivering the capacity and energy to meet
23 system needs.
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.WRITTEN COMMENTS—Page 20
CASE NO.IPC-E-24-46

I The lifecycle and imputed debt risks of the proiect are understated
2 Q. WHAT ARE YOUR CONCERNS REGARDING THE COMPANY'S MODELING
3 OF THE JACKALOPE PROJECT'S LIFECYCLE?
4 A. The Company selectively applied a 35 year asset life assumption to the Jackalope Wind
5 Project Power Purchase Agreement(PPA) and the Build Transfer Agreement(BTA)
6 components—after the project was shortlisted. All other wind projects in the same RFP
7 process were modeled using a 30 year lifespan. This inconsistency materially lowers the
8 levelized cost of the Jackalope Project and creates an uneven and potentially misleading
9 comparison to other final shortlist resources.
10 Q. DID THE PROJECT BIDDER PROVIDE DOCUMENTATION TO SUPPORT
11 THE 35 YEAR LIFESPAN?
12 A. No. The Company stated21 that although the bidder identified a 35 year term in its bid, it
13 did not receive or request documentation to substantiate this design life. In the absence of
14 independent engineering assessments, turbine degradation data, or historical evidence of
15 35 year performance from comparable wind projects, there is not clear justification for
16 deviating from the industry-standard 30 year modeling assumption.
17 Q. WHAT IS THE IMPACT OF THE 35 YEAR LIFESPAN ASSUMPTION ON THE
18 PROJECT'S LEVELIZED COST?
19 A. The Company acknowledged in discovery that reducing the project life back to 30 years
20 would increase the LCOC by approximately 1%. I have reviewed the Company's model
21 and found an issue with their calculations for LCOC for the PPA portion of the project.
22 Reducing the project life of the project from 35 years to 30 years changes the LCOC from
21 Response to Staff Request for Production 2,number 18.
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.WRITTEN COMMENTS—Page 21
CASE NO.IPC-E-24-46

I _/M/Month with imputed debt to_/kW/month with imputed debt, and the
2 LCOE levelized changes from /MWh with imputed debt.22 The
3 LCOC and LCOE should in fact increase if the project life is decreased(as
4 acknowledged by the Company), due to higher annual capital recovery costs and
5 compression of O&M costs. A reason for this error appears to be that the Company is
6 using a flat levelized payment of_kW-year for each project year,regardless of the
7 PPA lifetime term. Because the fined annual payment is used in the calculation of LCOE
8 and LCOC,it would need to be adjusted for calculating a shorter project life. The
9 Company's model error results in a total cost reduction with a 30-year life because you
10 effectively drop the last 5 years of fixed payments,which are being overweighted. This
11 artificially lowers both LCOE and LCOC in the Company's erroneous model when you
12 cut the project life. The model should not simply multiply the flat_/M-year value,
13 but instead spread capital recovery and O&M over the full project life. Furthermore, if
14 the O&M is modeled with a realistic 2%-3%annual escalation to reflect real world
15 inflation, the LCOC and LCOE will substantially increase in later model years. These
16 modeling error raises concerns about the accuracy of the Company's calculations. LCOC
17 and LCOE will increase,possibly substantially,when the project life is compressed to the
18 standard 30 years.
19 Q. DO ANY FINANCIAL RISKS ASSOCIATED WITH THE PPA EXIST THAT
20 THE COMPANY DID NOT ACCOUNT FOR?
"These values appear to represent scoring metrics and may not directly correlate to customer costs. The
workpaper calculating LCOE included transmission costs that were substantially lower than those indicated in
response to Staff RFP 15.
IDAIIO IRRIGATION PUMPERS ASSOCIATION,INC.WRITTEN COMMENTS—Page 22
CASE NO.IPC-E-24-46

I A. Yes. The Company did not incorporate the financial impact of imputed debt that arises
2 from the 35 year PPA. Long term PPAs are treated as debt-like obligations by credit
3 rating agencies,which means that they factor into the Company's credit rating in the
4 same way as on balance sheet debt. As of 2024 year end, the Company reported$7.1
5 billion in contractual PPA obligations compared to $3.1 billion in traditional debt23. The
6 Company is proposing to acquire a considerable amount of debt through its use of PPAs,
7 and I would like to flag a concern that this sort of"off balance sheet" financing may
8 obscure true project costs for future rate cases.
9 Q. DOES THE COMPANY'S FAILURE TO CONSIDER PROJECT LIFECYCLE
10 UNDERMINE THE PROJECT'S PRUDENCY?
11 A. Yes. The unsubstantiated 5-year extension of project life calls into question whether the
12 Jackalope Project was objectively evaluated. Without consistent lifecycle assumptions,
13 the Commission cannot reasonably determine that the Jackalope Project is a prudent
14 investment or that it represents the least-cost, least-risk option for ratepayers.
15
16 The cost of the proiect is substantially higher than the marginal cost of energy
17 Q. Is there a new large load that contributes to this project?
18 A. Yes, IPC's recently filed special contract with Micron indicates that Micron expects to
19 add 244 MW of demand by the end of 202724. This is more than 80 percent of the
20 capacity shortfall in 2027.
21 Q. Does the new Micron Contract purport to pay the marginal cost of energy?
23 Response to Staff Request for Production 2,number 23.
24IPC-E-24-44 Application Exhibit 3.
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.WRITTEN COMMENTS—Page 23
CASE NO.IPC-E-24-46

I A. Yes, IPC's claims that the energy portion of the contract is billed at the marginal cost".
2 The alleged marginal energy cost is $36.84 per MWh26. The special contract's cost of
3 energy is far less than the—/NM associated with the Jackelope Wind Project. If
4 one considers that the Jackelope wind project is non-dispatchable and requires shaping
5 and firming resources to meet energy needs, the marginal cost of energy likely exceeds
6 _/hm.
7 Q. CAN YOU PLEASE SUMMARIZE YOUR TESTIMONY AS IT RELATES TO
8 YOUR RECOMMENDATION THAT A CPCN AND APPROVAL OF A PPA
9 SHOULD --NOT BE GRANTED?
10 A. The Jackalope Wind Project fails to meet the standard for convenience,necessity,and
11 prudence for several critical reasons: The project's economic viability relies on PTC that
12 provide approximately$28/MWh for the first 10 years. However, this eligibility is
13 contingent on timely permitting, and achieving commercial operation by 2027. If the
14 project fails to qualify for the PTC credit, the present value of the lost tax benefits could
15 exceed$199 million, significantly raising the project's levelized cost. Furthermore,
16 permitting and execution risks are of concern: The project remains dependent on being
17 awarded federal permits, including a BLM Right-of-Way Grant, and the Record of
18 Decision not expected until March 2026. In addition, there is a seasonal variability and
19 capacity mismatch: with an ELCC potentially as low as 10-20%, the project's effective
20 capacity could be a small fraction of its nameplate 600 MW rating. Further, dispatch and
21 transmission constraints exist for the project, and therefore the project risks curtailment
22 and stranded energy,undermining its value and reliability. Taken together,these factors
25IPC-E_24-44 Application Par. 17.
261PC-E 24-44 Application Par.22.
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.WRITTEN COMMENTS-Page 24
CASE NO.IPC-E-24-46

I demonstrate that the Jackalope Wind Project introduces material financial and operational
2 risks that undermine its characterization as a least-cost, least-risk resource, or in the
3 public's best or convenient interest. If the Company had used realistic cost and
4 performance assumptions for the Jackalope Wind Project in its 2023 IRP, including a
5 higher LCOE to reflect potential PTC loss, lower capacity factors, and a more
6 conservative ELCC, it is unlikely the project would have ranked as a least-cost, least-risk
7 resource. The Company's decision to evaluate the PPA life over 35 years without
8 comparable adjustments for other bids, and its failure to account for imputed debt, further
9 skew the economic analysis in favor of Jackalope. Given these compounding risks, the
10 project may expose ratepayers to significantly higher costs than the Company has
11 presented. In light of these risks I have recommended that the Commission impose a suite
12 of cost containment measures, including: a soft cap on total capital cost recovery; a
13 seasonal cap on cost recovery; a true-up of annual payments to account for seasonal
14 variation; penalties for transmission and deliverability curtailment; and shareholder
15 absorbance of PTC risk of loss.
16 Q. DOES THIS CONCLUDE YOUR COMMENTS?
17 A. Yes.
18
DATED this 13'h day of May, 2025.
yk��
DEBORAH GLOSSER
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.WRITTEN COMMENTS—Page 25
CASE NO.IPC-E-24-46

CERTIFICATE OF SERVICE
I HEREBY CERTIFIY that on this 13th day of May, 2025, I served a true, correct and
complete copy of the Idaho Irrigation Pumpers Association, Inc.'s First Set of Data Requests to
each of the following, via the method indicated below:
Monica Barrios-Sanchez, Commission Secretary ❑ U.S. Mail
Chris Burdin, Deputy Attorney General ❑ Hand Delivered
Idaho Public Utilities Commission ❑ Overnight Mail
P.O. Box 83720 ❑ Telecopy(Fax)
Boise, ID 83720-0074 ® Electronic Mail (Email)
secretM(iDj2uc.idaho.gov
chris.burdingpuc.idaho.gov
Tim Tatum ❑ U.S. Mail
Donovan E. Walker ❑ Hand Delivered
Idaho Power Company ❑ Overnight Mail
1221 W. Idaho Street (83702) ❑ Telecopy(Fax)
P.O. Box 70 ® Electronic Mail (Email)
Boise, ID 83707
ttatumgidahopower.com
dwalkergidahopower.com
dockets gidahopower.com
Lance Kaufman, Ph.D. ❑ U.S. Mail
2623 NW Bluebell Place ❑ Hand Delivered
Corvallis, OR 97330 ❑ Overnight Mail
lancegae isg insi h� ❑ Telecopy(Fax)
® Electronic Mail (Email)
Peter J. Richardson ❑ U.S. Mail
Richardson, Adams, PLLC ❑ Hand Delivered
Industrial Customer of Idaho Power ❑ Overnight Mail
515 N. 27th St. ❑ Telecopy(Fax)
P.O. Box 7218 ® Electronic Mail (Email)
Boise, ID 83702
petergrichardsonadams.com
Dr. Don Reading ❑ U.S. Mail
Industrial Customer of Idaho Power ❑ Hand Delivered
280 S. Silverwood Way ❑ Overnight Mail
Eagle, ID 83616 ❑ Telecopy(Fax)
dreading(a,mindspring com ® Electronic Mail (Email)
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.WRITTEN COMMENTS—Page 26
CASE NO.IPC-E-24-46

Austin Rueschhoff ❑ U.S. Mail
Thorvald A. Nelson ❑ Hand Delivered
Austin W. Jensen ❑ Overnight Mail
Kristine A.K. Roach ❑ Telecopy(Fax)
Holland& Hart, LLP ® Electronic Mail (Email)
Micron Technology, Inc.
555 17th Street Suite 3200
Denver, CO 80202
darueschhoff(a hollandhart.com
tnelsonnhollandhart.com
[e-mail]
karoach(&hollandhart.com
acleeghollandhart.com
ERIC L. OLSEN
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.WRITTEN COMMENTS—Page 27
CASE NO.IPC-E-24-46