20250611Comments.pdf

RECEIVED
June 11, 2025
Eric L. Olsen(ISB#4811) IDAHO PUBLIC
ECHO HAWK& OLSEN, PLLC UTILITIES COMMISSION
505 Pershing Ave., Ste. 100
P.O. Box 6119
Pocatello, Idaho 83205
Telephone: [phone]
Facsimile: [phone]
Email: [e-mail]
Attorney for Intervenor Idaho Irrigation Pumpers Association, Inc.
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER CASE NO. IPC-E-24-45
COMPANY'S APPLICATION FOR A
CERTIFICATE OF PUBLIC IDAHO IRRIGATION PUMPERS
CONVENIENCE AND NECESSITY FOR ASSOCIATION,INC.'S WRITTEN
TWO BATTERY STORAGE FACILITIES COMMENTS
I 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 Western Economics, LLC
5 at 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
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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
11 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 TESTIFYING?
14 A. I am testifying on behalf of the Idaho Irrigation Pumpers Association ("IIPA").
15 Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS PROCEEDING?
16 A. My testimony is in response to Idaho Power's (the Company")proposal to construct,
17 own, and operate two battery energy storage system(`BESS") facilities of 50 MW each,
18 totaling 100 MW of capacity. The two facilities proposed by the Company are the Boise
19 Bench BESS expansion, and the Hemingway BESS incremental. The two BESS projects
20 are intended to address a predicted capacity shortfall for 2026, which follows the
21 cancellation of a previously planned 200 MW solar PV and 100 MW BESS project
22 owned by Savion, an independent producer. The Company is seeking from the
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I Commission a certificate of public convenience and necessity("CPCN") for these
2 projects.
3 My testimony will address the risks and benefits of the BESS projects as outlined by the
4 Company. I will base my risk/benefit analysis on my own independent reviews of
5 Company models, assumptions, and testimony.
6 Q. FROM YOUR REVIEW OF THE FILING AND OTHER SOURCES,WHAT ARE
7 YOUR CONCLUSIONS AND RECOMMENDATION?
8 A. Based on my review of Company filings, models, and testimony, I have concluded that
9 several clear risk factors exist with respect to the proposed BESS projects, and the impact
10 of these risks may be carried by ratepayers, with no guarantees from the Company either
11 structurally or affirmatively, that it will not pass along additional, future, or excess costs
12 to ratepayers. I will describe how the BESS projects were not selected through a
13 competitive bidding process, and are instead Company selected,utility owned assets
14 chosen outside of a transparent market mechanism, and therefore cannot meet a prudence
15 review for least-cost, least-risk. I will also discuss battery thermochemistry, and how the
16 Company's failure to account for real-world factors related to battery usage affects the
17 BESS lifecycle and dispatchability estimates averred by the Company. I will further
18 describe how assumptions baked into the Company's modeling of wildfire risk are fatally
19 flawed, and how the flaws in the wildfire risk models may propagate to the Company's
20 RCAT model, which is used to inform capacity planning and procurement. Finally, I will
21 address how tariffs risks affect the prudency of the project. In light of these factors, my
22 conclusion and recommendation is that the Commission deny the issuance of the CPCN.
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I If the CPCN is granted, then I recommend that the Commission impose cost containment
2 measures to protect ratepayers.
3 Q. WHAT IS THE PURPOSE OF THE COMPANY'S APPLICATION IN THIS
4 CASE?
5 A. Idaho Power is requesting that the Commission issue an order granting the Company a
6 CPCN to acquire new dispatchable energy storage with 100 MW of operating capacity.
7 The 100 MW of operating capacity would be realized through two utility scale BESS
8 systems: 1) the Boise Bench BESS expansion,which would add 50 MW to the existing
9 150 MW Boise Bench BESS facility; and 2)the Hemingway BESS increment, which
10 adds 50 MW, for a total combined capacity of 100 MW The Company is not seeking
1 1 binding ratemaking treatment at this time.
12 Q. HAS THE COMPANY DEMONSTRATED THE NECESSITY FOR THE
13 PROPOSED BESS PROJECTS?
14 A. No, the Company has not demonstrated that the BESS projects are necessary or prudent.
15 The Company's filings acknowledge that the BESS projects would mainly help with
16 future deficits rather than the immediate 2026 claimed shortfall, hence the batteries
17 cannot be necessary to solve the 2026 issue'. This conclusion is drawn from the
18 Company's projected 2027 deficit ranges from 298-320 MW, which appears to be the
1 Ellsworth Direct p. 15:"Q.How does the Company propose to address the 026 capacity deficit presented in this
case?A.First,in August 2024,an opportunity arose for Idaho Power to purchase 50 MW of firm energy delivered to
its border,for the months of June 2026 through August 2026,around the clock,seven days a week.While this short-
term purchase will reduce the projected capacity deficit identified for 2026,it only has the effect of deferring,not
eliminating,Idaho Power's resource needs in future years."Q.Is the Company procuring any additional resources
to address the remaining deficit?Yes.As described in the Direct Testimony of Mr.Hackett,Idaho Power was not
able to execute an agreement for a third project submittal with a June 1, 2026,commercial operation date resulting
from the 2026 RFP,and therefore has procured alternative resources,two Company-owned battery storage
facilities that will each provide 50 MW of operating capacity.The additional 100 MW of operating capacity
provided by the battery storage facilities will ensure Idaho Power continues to provide safe,reliable electric service
in 2026 and beyond
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I real driver for battery procurement, coupled with future cost increases due to tariffs2.
2 Furthermore, the capacity need claimed by the Company is driven by models with
3 speculative and/or erroneous assumptions regarding factors such as forced outage rates
4 and wildfire risks which feed into the Company's resource model.
5 Q. ASSUMING A NEED EXISTS,DO THE PROPOSED PROJECTS MEET THE
6 NEED?
7 A. Not necessarily, batteries are energy-limited, meaning that they can discharge for 4 hours,
8 so they cannot help during prolonged outages. In addition, the Company has not
9 addressed the potential temperature related curtailment or derating of batteries in high
10 temperatures, which would render them unavailable for dispatch during high energy need
11 summer events. The Company's ELCC calculations fail to account for these factors.
12 Q. HAS THE COMPANY PROCURED THE RESOURCES IN A COST EFFECTIVE
13 MANNER?
14 A. No, the two 50 MW BESS resources were not selected through a competitive bidding
15 process, and are instead Company selected,utility owned assets chosen outside of a
16 transparent market mechanism.As a result,there is no contractual pressure to enforce
17 least-cost pricing or cost-effectiveness, and no third-party accountability to contain costs.
18 Q. WOULD IT BE APPROPRIATE TO AWARD THE COMPANY A CERTIFICATE
19 OF PUBLIC CONVENIENCE AND NECESSITY FOR THIS PROJECT?
20 A. No, it would not be appropriate to award the Company a CPCN for this project.As noted
21 above and expanded on in this testimony, the Company has neither demonstrated a need
22 nor shown that the projects will meet the claimed need, and has not acquired the projects
2 Ellsworth direct,p. 17
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I in a sound and cost effective manner. For these reasons, the proposed BESS projects do
2 not serve the public interest or represent the least-cost, least-risk means of meeting
3 capacity needs for its customers.
4 Q. WHAT ARE SOME OF THE RISKS THAT THE RATEPAYERS WILL HAVE TO
5 BEAR IF A CPCN IS ISSUED AT THIS TIME?
6 -The BESS projects were not selected as part of a competitive bidding process and would
7 meet a speculative need
8 -The ITC and PTC credits may not be available for the project
9 -Batteries may not provide as much dispatchable energy as forecast
10 -Fire risk not robustly modeled, and the resulting inputs to the RCAT model are
11 misleading
12 - Seasonal reliability of the batteries is not uniform, so cost to ratepayers is not uniform
13 and ELCC model is misleading
14 -The prudence issues raised by Commission Staff for the initial Boise Bench project
15 exist in the present docket
16 -BESS projects have significant tariff risk exposure
17
18 The BESS projects were not selected as part of a competitive bidding process and would
19 meet a speculative need
20 Q. WERE THE TWO PROPOSED BATTERY STORAGE PROJECTS SELECTED
21 VIA COMPETITIVE BIDDING PROCESS?
22 A. No. The Boise Bench 50 MW Expansion and Hemingway Incremental 50 MW BESS
23 projects were not selected through a new competitive bidding process. Instead, they were
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I chosen as Company developed alternatives after the previously shortlisted third-parry
2 projects failed because of permitting issues. Further, the two battery resources are
3 Company owned assets, rather than being procured through power purchase agreements
4 or third-party contracts. Consequently, there is no contractual price protection without
5 competitive bidding or binding cost caps, the risk to ratepayers of cost escalation is
6 materially higher.
7 Q. IS THERE EVIDENCE THAT THE COMPANY IS BUILDING THESE
8 PROJECTS TO MEET A SPECULATIVE FUTURE NEED, RATHER THAN A
9 CURRENT ONE?
10 A. Yes. the Company acknowledges that even if both 50 MW BESS projects are completed,
11 the 2026 deficit would shift from 41-61 MW deficit to a 7-44 MW capacity length
12 position assuming perfect battery performance 3. This is additive to the 134 MW of
13 capacity the Company is requesting in IPC-E-25-03 via the conversion of North Valmy to
14 gas for 2026. The Company further states that its 2027 projected deficit ranges from 298-
15 320 MW, which appears to be the real driver for battery procurement, as the Company
16 furthermore note that battery costs will rise in the future due to tariffs4. These
17 justifications point not to a discrete 2026 reliability need, but rather to a forward looking
18 strategy to meet a speculative and evolving resource gap.
19 Q. DOES THE SPECULATIVE NATURE OF THE CAPACITY DEFICIT AFFECT A
20 FINDING OF PRUDENCY?
21 A. Yes. The prudency standard requires that infrastructure investments be based on a
22 discrete and demonstrable need, and supported by analysis and modeling. The record
s Company response to IIPA Request for Production 1-10
a Ellsworth direct,p. 17
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I indicates that the Company's deficit forecast has fluctuated materially with changes in
2 modeling assumptions and that the BESS projects are being pursued primarily to guard
3 against possible future capacity needs. In the absence of a firm, clearly defined deficit
4 and a competitive selection process, the proposed BESS projects do not meet the burden
5 of proof for prudency under the Commission's public interest and least-cost, least-risk
6 framework.
7
8 The ITC and PTC credits may not be available for the proiect
9 Q. PLEASE EXPLAIN WHY THE ITC CREDIT MAY NOT BE AVAILABLE FOR
10 THE PROJECT AS FORECASTED BY THE COMPANY.
11 A. Section 7(a) of Presidential Executive Order No. 14154 (Unleashing American Energy)
12 pauses "the disbursement of funds appropriated through the Inflation Reduction Act of
13 2022 ("IRA"). The Company interprets Executive Order No. 14154 as not affecting the
14 ITCs, PTCs, or any transferrable tax credits established under Internal Revenue Code
15 Section 64185. While the US Constitution grants Congress the authority to levy taxes and
16 create and modify tax credits, there is a clear shift in federal policy away from renewable
17 energy resources, and there is uncertainty regarding whether the ITC and PTC will
18 continue to be administered by the IRS, either as a consequence of EO 14154,
19 forthcoming Congressional action, or administrative delays that may occur as the IRS
20 reviews their processes and how they align with the new administration's policies.
21 Q. IF THE ITCs ARE NOT RECOGNIZED,WILL THIS AFFECT THE REVENUE
22 REQUIREMENT CALCULATED BY THE COMPANY?
5 Response to Staff Request for Production#15,Feb 12,2025
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I A. Yes. The Company's levelized cost calculation includes recognition of the ITC. I have
2 reviewed the Company's financial mode16 and the annual revenue requirement is offset
3 by the ITC amortization over the 20-year project period. Payments are levelized and the
4 capacity cost is computed. Without the ITC amortization, the LCOC increases—
5 _ ($/kW/mouth) for the Hemingway project to_, and from
6 for Boise Bench Expansion. These costs are higher than those of several other standalone
7 BESS projects evaluated by the Company. On top of these amounts, a cost increase of
8 is anticipated due to tariffs, fiirther raising the project costs$. Stated in terms
9 of$/kw-month, this is equal to $3.33 on a nameplate basis, and$8.89 on an ELCC basis9.
10 Although the legality of the 145%tariff is pending litigation, even without this added
11 cost, the LCOC is significantly affected by assumptions about the ITC being available.
12 BESS projects are particularly vulnerable to changes in ITC and PTC eligibility. Unlike
13 fossil-fiiel resources,which have long-standing cost recovery frameworks and are not
14 dependent on federal clean energy tax incentives, battery storage relies heavily on the
15 continuation of the ITC and related provisions under the IRA. Recent legislative
16 proposals in the House10 have included accelerated phaseouts and stricter deadlines for
17 clean energy tax credits like BESS projects, which disproportionately impacts new or
18 delayed battery projects. If federal policy continues shifting away from these incentives,
e Confidential attachment to Staff's Request for Production#16.Feb 12.2025
Figure 15 of Confidential Exhibit 3 in response to Staff Request for Production.Feb 12,2025
8 Company's response to Staffs request for production 26
9 Calculated using: 160 null cost increase;200 MW nameplate capacity;20 yr project life.75 MW ELCC
(calculated by 46 MW surplus with BESS—(-29)MW deficit without BESS...these figures from company response
to staff's request 24)).Nameplate$/kw-month= 160.000.000/200.000",=800$/kw; 800$/kw/240 months=3.33
$/kvv-montli.Based on ELCC: 160.000.000/75.000 kw=2.133 $/kw:2133/240 months=8.89$/k-",*month
io H.R. 1 "One big beautiful bill act''
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I the financial viability of the BESS projects could deteriorate rapidly, leaving ratepayers
2 to cover the cost gap.
3 Q. IF THE ITCs ARE NOT RECOGNIZED,WILL RATEPAYERS BEAR ANY OF
4 THE RISK?
5 A. Yes, if the ITCs are not recognized, ratepayers will bear risk. Without the ITC, the
6 revenue requirement would be raised, and the Company may seek to increase retail rates
7 for ratepayers.
8 Q. DOES THE FAILURE TO CONSIDER A POTENTIAL REVOCATION OF THE
9 ITC AFFECT A FINDING OF PRUDENCY FOR THE PROPOSED PROJECT?
10 A. Yes, the Company's failure to account for the potential revocation of the ITC for the
11 proposed BESS project materially undermines a finding of prudency.As discussed above,
12 without the ITC, additional costs will be passed along to ratepayers by the Company in
13 the form of increased retail rates.
14
15 The 100 MW BESS proiect may not provide as much dispatchable energy as forecast
16 Q. DOES THE COMPANY ASSUME THAT THE FULL 100 MW OF OPERATING
17 CAPACITY WILL BE AVAILABLE TO MEET CAPACITY DEFICITS?
18 A. Yes. The Company asserts that the two 50 MW BESS units will provide 100 MW of
19 operating capacity to help close the 2026 and future capacity deficits. The Company
20 assumes that the batteries will provide firm capacity based on effective load carrying
21 capacity(ELCC)values which were derived from the Company's RCAT/LOLE models"
ii Direct testimony of Mr.Ellsworth on Company response to Staff Request#1.
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I The Company states that the batteries can be used to support energy emergency
2 operations, such as two recent events that occurred in September 2022 and January 2024.
3 Q. WHY DO YOU SAY THAT THE COMPANY'S ASSUMPTION THAT THE FULL
4 100 MW OF OPERATING CAPACITY WILL BE AVAILABLE IS ERRONEOUS?
5 A. There are several reasons that the Company's treatment of the batteries as being fully
6 available to meet capacity deficits is in error. The Company is largely treating the
7 batteries as firm capacity. However,practical thermophysical and thermochemical
8 processes impact actual battery performance and dispatchability. Batteries are energy and
9 power limited resources. By this, I mean that each 50 MW battery does not indefinitely
10 provide 50 MW of dispatchable energy. It provides 50 MW of instantaneous power,but
11 only for as long as the stored energy allows.As these are 4-hour batteries, the batteries
12 will not support extended outage events, such as the emergency events noted by the
13 Company, even if fully charged. The Company's ELCC modeling is not transparent in
14 how it accounts for the 4-hour battery life period, and does not fully adjust for
15 degradation over time. Furthermore, the Company does not rigorously test whether the 4
16 hour limit on battery life is sufficient during peak events and long duration events.
17 Q. YOU MENTIONED THAT PRACTICAL THERMOCHEMICAL AND
18 THERMOPHYSICAL PROCESSES CAN IMPACT BATTERY PERFORMANCE
19 AND DISPATCHABILITY. CAN YOU SAY MORE ABOUT THIS?
20 A. Batteries must charge before they can discharge. So, if conditions for charging are
21 suboptimal (such as transmission constraints, cloudy weather conditions impacting solar
22 availability, or system conditions like congestion pricing), the state of charge of the
23 batteries may not be adequate to provide dispatchable energy. It is important to point out
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I that batteries degrade with every charge/discharge cycle, and the rate of degradation is
2 faster with deep discharges; in extreme hot or cold temperatures; and with high power-to-
3 energy rates. Since these batteries would be used by the Company in part to meet demand
4 during high demand periods such as extreme hot and cold conditions,or during energy
5 emergencies, it follows that the Company's assumptions about both the dispatchable
6 energy the batteries can provide—as well as the anticipated life span of the batteries—are
7 overly optimistic.
8 Q. WHAT ASSUMPTIONS SPECIFICALLY HAS THE COMPANY MADE ABOUT
9 BATTERY DEGRADATION?
10 A. The Company" assumes for Boise Bench 50 MW expansion,a first year degradation of
11 in subsequent years, and for Hemingway 50 MW,
12 in subsequent years. These (particularly Boise Bench) estimates are overly optimistic.
13 According to NREL and peer reviewed studies, first year degradation of utility scale
14 BESS Li-ion batteries can be Hof greater in the first year,with rates of annual
15 degradation thereafter being almost W greater than forecasted at the highest
16 temperatures versus lower temperatures 13. Essentially, for the Boise Bench battery, the
17 Company is claiming M year one degradation,— thereafter,while real world data
18 shows that for utility scale,heavily cycled batteries operating in hot summer
19 temperatures, it's more typical to see 4%-6%degradation in year 1, and over 2%in
20 subsequent years. For the Hemingway battery, the Company's claim off year 1
21 degradation reasonably aligns with real world projects in California and Nevada,but the
22 claim off degradation in subsequent years is an underestimate compared to heavily
iz Exhibit 4 in Mr.Hackett's testimony
"hops://batteaarchive.org and DOI:10.1016/j.est.2021.103533
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I cycled utility scale batteries operating in hot climates. It is also worth pointing out again
2 that there is no evidence that the Company's ELCC models are adjusted downward over
3 time to account for the degradation.
4 Q. WHAT IS THE POTENTIAL CONSEQUENCE OF THE COMPANY'S
5 MISCHARACTERIZATION OF THE BATTERIES?
6 A. ELCC values that are based on assumptions that do not realistically reflect factors such as
7 charging constraints, >4h dispatch availability, or state of charge limitations will overstate
8 the real world reliability contribution of the batteries. This mischaracterization propagates
9 through the Company's RCAT and AURORA models. In the RCAT models, inflated
10 ELCC values can cause the model to under select other firm capacity resources and over-
11 rely on batteries to meet planning reserve margins (PRMs).And,because the models are
12 iteratively linked, errors in ELCC assumptions can be compounded, and result in
13 portfolios which appear to be least-cost least-risk on paper, but would not meet real world
14 requirements under stress conditions. Furthermore, as noted earlier, even if the two BESS
15 projects did provide perfect performance, the 2026 capacity deficit would only be
16 reduced to 7 MW to 44 MW. In reality, the contribution of the batteries to closing this
17 capacity deficit may be much lower.
18 Q. WILL RATEPAYERS BEAR ANY RISK ASSOCIATED WITH INCORRECT
19 ASSUMPTIONS ABOUT BATTERY DEGRADATION AND DISPATCHABLE
20 ENERGY?
21 A. Yes, ratepayers bear risk associated with any incorrect Company assumptions about
22 battery life and dispatchable energy. One such scenario is if the Company requires future
23 augmentation of either BESS project. The Company will not rule out future
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1 augmentation, or therefore future attempted cost recovery for augmentation14
2 Additionally, ratepayers bear the risk of potential overbuild(in the form of cost
3 recovery), or underbuild(in the form of a failure to meet demand).
4 Q. DOES THE COMPANY'S FAILURE TO ACCOUNT FOR REAL WORLD
5 DISPATCHABILITY FROM THE BESS PROJECTS AFFECT A FINDING OF
6 PRUDENCY?
7 A. Yes. The Company's assumptions regarding battery life and performance degradation are
8 overly optimistic and not supported by detailed operational analysis. The Company
9 assumes relatively modest degradation rates without modeling the cumulative impact of
10 declining capacity over the operational life of the BESS facilities. These unsupported
11 assumptions about long-term battery performance result in an inflated estimation of the
12 projects' capacity contributions and useful lives. Such misrepresentations materially
13 impair the ability to assess the long-term cost-effectiveness of the projects and weigh
14 heavily against a finding of prudency for ratepayer investment.
15
16 Fire risk is not adequately accounted for, and resulting inputs into the RCAT model are
17 misleading
18 Q. WHY IS FIRE RISK A CONSIDERATION WITH BESS FACILITIES?
19 A. The vulnerability of BESS to fire risk means BESS projects may have poorer operating
20 characteristics than assumed in models.As instantiated by the Idaho Power Melba
21 substation fire that occurred in 2023, BESS systems (and in particular Li-ion BESS
22 systems) are vulnerable to both initiating and being impacted by wildfires. Factors such
14 Response to Staff's Feb discovery
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I as high ambient temperatures,proximity to wildfire events, and even high loads of
2 airborne particulate matter, can impact BESS operability. Battery fires in general must be
3 left to burn, which affects wildfire risk and liability, as I further discuss below. In the case
4 of thermal runaway, once one cell ignites, a chain reaction can subsume neighboring
5 cells, and the reaction generates oxygen and flammable gasses which are resistant to
6 water and standard fire agents.
7 Q. IS THERE A RISK OF BATTERY CURTAILMENT OR DERATING DUE TO
8 HIGH TEMPERATURES AND OR WILDFIRE RISK?
9 A. Yes, there is a well-established risk that BESS systems experience curtailment or derating
10 during periods of extreme heat. It is widely recognized that high ambient temperatures
11 can limit a battery's ability to charge or discharge at full capacity in order to protect
12 system components. Most utility-scale BESS units are equipped with thermal protection
13 systems that automatically reduce or curtail power output when cell temperatures
14 approach critical thresholds. In addition, the associated power inverters often derate their
15 output during high-temperature conditions to prevent overheating. However, the
16 Company's testimony and modeling assume full availability of the BESS projects during
17 critical summer peak periods without accounting for potential heat-related performance
18 limitations. Given the high summer temperatures common in the project areas, this
19 omission materially undermines the Company's claims that the BESS projects will
20 reliably meet peak capacity needs when they are most needed.
21 Q. HOW DOES THE COMPANY MODEL FIRE RISK?
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I A. I have reviewed the Company's model" and base my answers to the questions in this
2 section on this model and associated testimony. The Company uses a"historical outage"
3 method within its RCAT model which feeds into the Company's long term capacity
4 model. The company considers only external transmission lines that import power into
5 Idaho Power's Balancing Authority(i.e. internal outages are not considered). For each of
6 the three paths modeled, Equivalent Forced Outage Rate during Demand (EFORd) is
7 calculated for 31 days of each summer in 2022, 2023, and 2024, and the average value
8 for these three is taken as a percent (#wildfire outage days/# summer days per path), and
9 subtracted from 100%. The EFORd values are used as an input for RCAT which is used
10 to inform capacity planning and procurement.
11 Q. ARE THE ASSUMPTIONS USED BY THE COMPANY REFLECTIVE OF REAL
12 WORLD CONDITIONS?
13 A. No. The Company only uses three years of summer data(2022-2024); only considers 31
14 days in each summer; and does not include internal transmission wildfire risk, as which
15 91 of the—100 outage events reported by the Company were characterized. Speaking
16 specifically to the time-limited nature of the data(3 summers of 31 days each), it is
17 highly unlikely that this limited duration captures long-term risk trends.A 10-15 year
18 window adjusted for climate acceleration would yield a more robust statistical result.
19 Additionally, the model is binary in the sense that it only counts "outage days", not
20 outage duration, or load impact severity from the outages.A more nuanced approach to
21 modeling the wildfire risk would need to consider MW lost, hours of outage, and
22 associated curtailment costs. Finally, as more BESS projects are added to the system, the
15 Confidential response to Staff's Request for Production#1 and associated attachment,Feb 6,2025
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I risk of wildfire absolutely increases. In short, the model does not accurately reflect or
2 predict real world wildfire risk.Additionally, reasons that I explain below, the resulting
3 EFORd calculations produced by the model are further misleading, and may propagate to
4 the Company's capacity planning models.
5 Q. IS THE COMPANY'S EFORd CALCULATION MISLEADING?
6 A. Yes. The Company's EFORd calculation is misleading. EFORd is a measure of the
7 probability that a generating unit will not be available due to forced outages or forced
8 deratings when there is demand. EFORd provides a percentage estimate of how likely a
9 generator is to be unavailable due to unexpected issues when it's needed to provide
10 electricity to the grid.A lower EFORd indicates a more reliable and available unit16. In
11 the Company's model for calculating the EFORd, as described above, the EFORd is
12 calculated as 100%minus the average %unavailable days in 31 days of each summer
13 from 2022-2024. So, if the number of wildfire days modeled by the Company was
14 notionally increased, for example, in the Idaho NW region, to include 10 more outage
15 days across the three summers (I'm selecting these values randomly), the EFORd
16 calculated by the Company's model will actually drop from 96.4%to 94.2%17, suggesting
17 that the system is more reliable than it is. This highlights the presence of errors in the
18 Company's models because including more wildfire days into the model causes the
19 model to predict fewer future outage days, which is the opposite of how EFORd works. It
20 appears that the Company's EFORd calculation actually reflects system reliability, not
21 forced outage probability.At this time it is unclear whether the Company"corrects"the
16 https://www.cw-connect.com/sites/default/files/2020-
01/Reliability_Analysis_of Power_Plant_Unit_Outage_Problems_2013.pdf
17 Calculated using the Company's EFORd model:For each year in 2022-2024,EFORd=(number of summer days
with wildfire related outage/30 summer days)
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.WRITTEN COMMENTS—Page 17
CASE NO.IPC-E-24-45

I EFORd calculation in its RCAT/AURORA models, or if the error is continually
2 propagating as discussed below.
3 Q. HOW DOES THE EFORd CALCULATION IMPACT THE COMPANY'S RCAT
4 MODELS AND TRIGGER PROCUREMENT?
5 A. Incorporating these wildfire risk inputs into the RCAT model impacts the outage
6 generation table used to calculate the Loss of Load Expectation("LOLE"), thus
7 impacting the annual capacity position calculation. Since the EFORd values are used in
8 the LOLE and annual capacity calculations, these errors may propagate through the
9 models and show the units as offering more capacity than they do. In Idaho Power's
10 RCAT model, wildfire-related EFORd reduces available capacity, which may flip the
11 capacity position from surplus to deficit, triggering procurement in AURORA. If the
12 Company's EFORd values do actually reflect availability rather than forced outage
13 probability, but are used as if they're derate factors, the model could undercount risk. In
14 this case, the LOLE would be artificially low, causing the system to look more reliable
15 than it actually is, which could show a false surplus in capacity, and cause the RCAT to
16 underestimate background risk which would make new resources look more valuable
17 than they in fact, are.
18 Q. WILL RATEPAYERS BEAR ANY RISK OF INACCURACIES IN THE
19 WILDFIRE RISK CALCULATIONS?
20 A. Ratepayers will ultimately bear the risk of inaccuracies in the wildfire risk calculations.
21 According to the Company's, if a fire occurs in a Company owned BESS after the
22 warranty period, the Company will not rule out rebuilding the BESS and seeking
18 Response to Staff Request for Production 14,Feb 2025
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.WRITTEN COMMENTS—Page 18
CASE NO.IPC-E-24-45

I recovery from ratepayers. Therefore, if the Company's wildfire risk calculations are
2 inaccurate, more risk may be shifted to the customers than would be with other
3 procurements. Further risks to ratepayers exist as well. In wildfire-prone regions like
4 Idaho, a fire originating from a BESS facility or made worse by its failure could result in
5 substantial property damage, liability claims, regulatory fines, and uninsured losses. I am
6 aware that Idaho just enacted the Wildfire Standard of Care Act 19("WSCA"). The WSCA
7 creates the standard of care for IPC through the use of wildfire mitigation plans reviewed
8 and approved by the Commission. Only time will tell if the WSCA will provide the
9 intended limitation of liability for damages wildfires cause to third-party owners near the
10 BESS facilities. Without specific and enforceable protections, the proposed BESS
11 projects could expose ratepayers to significant unanticipated financial liabilities. This
12 cannot be considered to be a"least risk"proposition for ratepayers.
13 Q. DOES THE COMPANY'S MISCALCULATION OF WILDFIRE RISK AND
14 EFORD AFFECT A FINDING OF PRUDENCY?
15 A. Yes. Given the increasing severity of wildfire events in the western United States, the
16 failure to properly model wildfire-driven transmission and generation outages materially
17 understates system risk. This omission undermines the credibility of the Company's
18 claimed capacity needs and materially affects a finding of prudency for the proposed
19 battery projects.
20
21 Seasonal reliability of the batteries is not uniform, so cost to ratepayers is not uniform
19 I.C.§61-1801 thru I.C.§61-1808.
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.WRITTEN COMMENTS—Page 19
CASE NO.IPC-E-24-45

I Q. YOU DESCRIBED HOW BESS SYSTEMS MAY NOT BE CONSISTENTLY
2 DISPATCHABLE DUE TO THE IMPACT OF EXTERNALITIES SUCH AS
3 TEMPERATURE, CHARGING CONSTRAINTS, STATE OF CHARGE ETC. ON
4 BATTERY CHEMISTRY. DO YOU EXPECT THERE TO BE VARIATIONS IN
5 SEASONAL RELIABILITY OF THESE RESOURCES AS A RESULT?
6 A. Yes, I would expect there to be seasonal variability in the ability of the BESS systems to
7 meet both baseload and peak load. In the summer months, the batteries will be less
8 reliable at meeting demand. To elaborate,prolonged high temperatures can increase
9 what's known as impedance in the battery. Increases in impedance will cause more
10 energy loss as heat when the battery charges. High temperatures like those encountered in
11 summer in Idaho can also decompose to the battery electrolyte, and these decomp
12 reactions also waste energy and reduce the charge efficiency, such that the battery will
13 not be able to charge to its full state in time to meet demand. In short, round-trip
14 (charge/discharge) efficiency will drop several percentage points on a hot summer day,
15 and overheating risks will peak concurrently with resource demand. The practical
16 consequence of this is not only that charging efficiency hampered by hot temperatures,
17 but battery life as well is shortened.
18 Q. YOU HAVE DESCRIBED HOW BATTERY PERFORMANCE AND LIFE IS
19 MATERIALLY IMPACTED BY HOT TEMPERATURES. CAN COLD
20 TEMPERATURES ALSO AFFECT BATTERY PERFORMANCE AND LIFE?
21 A. Yes, cold weather conditions can affect BESS project performance and lifespan. Lithium-
22 ion batteries experience significant reductions in capacity and power output at low
23 temperatures, with charging restrictions typically necessary at or below 0°C (32°F) and
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.WRITTEN COMMENTS—Page 20
CASE NO.IPC-E-24-45

I discharge performance degrading significantly below -10°C (14°F)20. In cold temperature
2 conditions such as this, the chemical reactions inside the lithium-ion cells slows down,
3 which reduces capacity as well as power output(i.e. the ability to discharge quickly). If a
4 battery is charged when it's too cold, lithium plating can occur, which damages the cell
5 and leads to accelerated degradation. For this reason, many batteries are manufactured
6 with systems that automatically prevent charging below a given temperature, so the
7 battery is effectively curtailed or derated in extreme cold.
8 Q. HAS THE COMPANY ADDRESSED THE EFFECT OF EXTREME COLD ON
9 BATTERY DISPATCH OR ELCC?
10 A. No. The Company has not addressed the risks that cold weather conditions may impose
11 on the performance of the proposed BESS projects. If Idaho Power continues to
12 experience winter peaks, then the BESS projects will be less effective than assumed.
13 Furthermore, the Company's calculation of ELCC for the BESS resources is tied to
14 summer peak load expectations, not winter. In contrast, PGE shows a significant
15 difference between summer and winter ELCC21. This difference is not accounted for or
16 addressed at all by Idaho Power.
17 Q. DOES THE COMPANY'S FAILURE TO FULLY CONSIDER SEASONAL AND
18 TEMPERATURE DEPENDENT BATTERY PERFORMANCE IN THEIR
19 MODELS AFFECT A FINDING OF PRUDENCY?
21 https://www.redarcelectronics.com/us/resources/chargers-isolators-faqs/do-not-charge-lithium-battery-below-32-
degrees/
21 PGE 2023 IRP and CEIP Appendix J Figures 147 and 148.
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.WRITTEN COMMENTS—Page 21
CASE NO.IPC-E-24-45

I A. Yes. The Company's failure to incorporate temperature dependencies into its modeling for
2 meeting system demand undermines the reliability assumptions underpinning the
3 proposed projects and materially weakens a Ending of prudency for ratepayer investment.
4
5 The cost of the initial Boise Bench proiect was not LC/LR
6 Q. HOW DOES THE BOISE BENCH EXPANSION PROPOSED IN THIS CPCN
7 RELATE TO THE BOISE BENCH BESS PROJECT IN IPC-E-24-16?
8 A. The Boise Bench 50 MW Expansion BESS would be located at the Boise Bench Station
9 in Ada County and would be directly incorporated into the 150 MW Boise Bench BESS
10 for which the Commission issued a CPCN in IPC-E-24-1622. The Boise Bench 50 MW
11 Expansion proposed in the current application is an expansion of the original 150 MW
12 Boise Bench BESS project that the Commission issued a CPCN for in IPC-E-24-16.
13 Combined, the original 150 MW Boise Bench project and the 50 MW Boise Bench
14 Expansion will be housed in a single 200 MW facility.
15 Q. WHAT WAS THE OUTCOME OF THE IPC PROCEEDING FOR THE INITIAL
16 BOISE BENCH BESS PROJECT IN IPC-E-24-16?
17 A. Although a CPCN was granted by the Commission for the original 150 MW Boise Bench
18 BESS facility in IPC-E-2416, Staff was concerned with: (1)the lack of comparable
19 alternative resources in the Company' s selected portfolios; (2)the lack of comparable
20 alternative resources in the final shortlist; (3) augmentation costs; and (4) future
21 recovery23. Staff believed the Company was not able to definitively show that the BESS
22 Project, in combination with the final set of resources needed to resolve the deficit was
22 Confidential Response to Staff Request for Production#2,Feb 6 2025
21 Case IPC-E-2416,November 8,2024,Commission Decision
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.WRITTEN COMMENTS—Page 22
CASE NO.IPC-E-24-45

I least-cost, least-risk. Furthermore, Staff raised concerns about augmentation costs being
2 under accounted for, and consequently, Staff had recommended that the Commission
3 impose soft and hard caps on estimated costs. While the Commission declined to impose
4 these caps, it indicated in its order that it would consider all facets of the project,
5 including scope, cost justification, and the Company's procurement process, to determine
6 prudence of the Company's decisions in future proceedings.
7 Q. ARE SIMILAR PRUDENCE ISSUES PRESENT IN THE BOISE BENCH 50 MW
8 EXPANSION?
9 A. Yes, similar issues with prudence as to those raised by Staff in IPC E-24-16 are present in
10 the current docket, and the same risks to ratepayers exist as a consequence. In its prior
11 order granting a CPCN in IPC E-24-16, the Commission indicated that future actions by
12 the Company such as procurement process, would be evaluated. In the present case, the
13 two BESS projects were not selected through a competitive bidding process, and were
14 developed as alterative after the original shortlisted projects failed to meet permitting
15 requirements. While both projects leverage procurement efficiencies from prior supply
16 agreements, their selection occurred outside of a RFP or open bid process. So, several
17 concerns raised by Staff in the prior docket are being realized in the present case.
18
19 BESS projects have significant tariff risk exposure
20 Q. DO THE PROPOSED BESS PROJECTS FACE MATERIAL COST RISKS FROM
21 IMPORT TARIFFS?
22 A. Yes. Per the Company, Boise Bench BESS expansion is exposed to a 145% tariff due to
23 the China-based origin of its battery components which are subject to import duties
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.WRITTEN COMMENTS—Page 23
CASE NO.IPC-E-24-45

I enacted under Trump24. These tariffs trigger a cost increase of approximately_
2 million for the 200 MW Boise Bench BESS facility. The Company's contract with its
3 battery vendor, Prevalon Energy, included a change-in-law clause allowing the vendor to
4 adjust the project price in response to such tariff increases.
5 Q. HAS THE COMPANY TAKEN ANY STEPS TO MITIGATE THESE COSTS?
6 A. The Company explored several alternatives, including termiatimg the contract;
7 sourcing batteries from Indonesia; applying for a tariff exemption; and delaying
8 delivery25. Each of these options either present extreme cost penalties or jeopardize the
9 project's delivery timeline making it infeasible for meeting the 2026 capacity need.
10 Ultimately, the Company opted to accelerate delivery of approximately 30%of the
11 battery systems during a temporary 90-day tariff relief window, reducing the applicable
12 tariff rate from 145%to 30%and saving an estimated _26.
13 Q. HAVE ANY DEVELOPMENTS IN THE TARIFFS OCCURRED SINCE THE
14 COMPANY'S DECISION TO ACCELERATE DELIVERY?
15 A. Yes.AMay 28 court ruling in the U.S. Court of International Trade ruled that the
16 "Liberation Day"tariffs are unlawfiil and issued a permanent injunction. The 145%tariff
17 on BESS systems is likely included in this injunction. This decision has already been
24 Company's response to Staff's request for production 26"Prevalon Energy LLC("Prevalon"),the supplier of the
200 MW BESS, 150 MW of which the Company received a Certificate of Public Convenience and Necessity
("CPCN')in Case No.IPCE-24-16,and 50 MW of which Idaho Power is requesting a CPCN in this case,informed
the Company that because all the batteries for the Boise Bench project are sourced from China,they would be
subject to the upcoming 145 percent tariff thereby increasing the cost of the project by approximately$160 million."
2s Company's response to Staff's request for production 26
26 Company's response to Staff's request for production 27:"As a result,the Company immediately requested that
Prevalon deliver as much of the product as possible during this 90-day timeframe to realize certain savings
compared to an uncertain tariff rate after August 12,2025.According to Prevalon,they are able to deliver
approximately 30 percent of the product prior to August 12,2025,saving an anticipated$33,000,000."
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.WRITTEN COMMENTS—Page 24
CASE NO.IPC-E-2445

I appealed by the Trump administration, and it is unclear what the eventual outcome will
2 be.
3 Q. IS THE COMPANY'S DECISION TO ACCELERATE DELIVERY STILL LEAST
4 COST IN LIGHT OF THE INJUNCTION ON THE 145% TARIFF?
5 A. While the Company pursued partial delivery under the 90-day tariff relief window in May
6 2025, the May 28, 2025 court ruling has rendered that strategy potentially unnecessary
7 and suboptimal. The remaining 70% of the non-accelerated BESS system may be tariff
8 free if the court ruling is upheld.
9 Q. DOES THE REMAINDER OF THE PROJECT STILL FACE TARIFF-INDUCED
10 COST ESCALATION?
11 A. Yes. While the accelerated delivery of a portion of the batteries was intended to reduce
12 some tariff exposure, the majority of the equipment remains subject to high and likely
13 volatile tariff rates. Moreover, there is no evidence that the Company's cost modeling
14 includes either binding cost caps to protect ratepayers from further escalation, or a
15 scenario analysis of tariff impacts on levelized cost of capacity.
16 Q. DOES THIS AFFECT A FINDING OF PRUDENCY FOR THE PROJECTS?
17 A. Yes. Prudent investment decisions should be robust against foreseeable cost risks. In this
18 case, the Company should have known that sourcing from China exposed the project to
19 substantial tariff risks under a long-standing and publicly known Section 301 policy.
20 Rather than pursuing alternative procurement options that could have mitigated this
21 exposure during initial project planning or competitive sourcing, the Company elected to
22 proceed under a framework that allowed for retroactive cost increases. Ratepayers are
23 now exposed to significant, non-contestable price escalation risks as a result. The absence
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.WRITTEN COMMENTS—Page 25
CASE NO.IPC-E-24-45

I of a competitive bidding process and the lack of cost containment provisions, combined
2 with reliance on a tariff-exposed vendor, undermines any claim that the proposed BESS
3 projects are least-cost or least-risk. Therefore, a finding of prudency cannot be supported.
4 Q. WHAT DO YOU RECOMMEND REGARDING COST CONTAINMENT?
5 A. I strongly recommend that the Commission impose cost containment measures as a
6 condition of the CPCN approval, should the Commission choose to grant one.
7 Specifically, I recommend a hard cap on the total capital cost for the Boise Bench and
8 Hemingway BESS facilities,beyond which no cost recovery from ratepayers would be
9 permitted. I also recommend a soft cap on total costs which require Commission review
10 and approval for cost recovery above a threshold of 10% over the original project budget.
11 I also recommend a stipulation that any tariff-related costs beyond those forecast in the
12 filing not be recoverable from ratepayers, due to the known and foreseeable nature of the
13 risk.
14 Q. CAN YOU PLEASE SUMMARIZE YOUR TESTIMONY?
15 A. In my testimony, I have raised several prudency concerns regarding the proposed BESS
16 projects. I have described how the Company has failed to demonstrate that the proposed
17 BESS projects meet the standards of necessity, least-cost, and prudency required for a
18 Certificate of Public Convenience and Necessity. The Company's modeling relies on
19 unverified assumptions regarding system needs, including speculative wildfire risk
20 factors and misleading EFORd calculations. The Company has further failed to account
21 for the temperature-dependent performance limitations of lithium-ion batteries, including
22 reduced capacity at low temperatures, charging restrictions below freezing, and
23 curtailment risks during extreme heat events, all of which could impair the ability of the
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.WRITTEN COMMENTS—Page 26
CASE NO.IPC-E-24-45

I batteries to perform during critical peak periods.Additionally, the Company's
2 assumptions about battery degradation and useful life are unreasonably optimistic, with
3 no binding augmentation plans to restore lost capacity, and no accounting for either
4 degradation or winter temperature constraints in ELCC calculations. I have also described
5 how significant foreseeable tariff risk exposure renders the project imprudent, and have
6 recommended the imposition of cost containment measures should a CPCN be granted.
7 Collectively, these modeling deficiencies materially understate the operational risks and
8 long-term costs of the BESS projects. Without correction of these critical flaws, the
9 Company has not met its burden to demonstrate that the proposed projects are prudent or
10 in the best interests of ratepayers.
11 Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY?
12 A. Yes.
DATED this 1 lth day of June, 2025.
f
DEBORAH GLOSSER
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.WRITTEN COMMENTS—Page 27
CASE NO.IPC-E-24-45

CERTIFICATE OF SERVICE
I HEREBY CERTIFIY that on this 1 Ith day of June, 2025, I served a true, correct and
complete copy of the Idaho Irrigation Pumpers Association, Inc.'s Written Comments to each of
the following, via the method indicated below:
Monica Barrios-Sanchez, Commission Secretary ❑ U.S. Mail
Adam Triplett, Deputy Attorney General ❑ Hand Delivered
Idaho Public Utilities Commission ❑ Overnight Mail
P.O. Box 83720 ❑ Telecopy(Fax)
Boise, ID 83720-0074 ® Electronic Mail (Email)
secretga@]2uc.idaho.gov
adam.triplettkpuc.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
ttatum djdahopower.com
[e-mail]
dockets(kidahopower.com
Lance Kaufman, Ph.D. ❑ U.S. Mail
2623 NW Bluebell Place ❑ Hand Delivered
Corvallis, OR 97330 ❑ Overnight Mail
lance(a�,ae isg insi hg t.com ❑ 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
peter(a�,richardsonadams.com
❑ U.S. Mail
❑ Hand Delivered
❑ Overnight Mail
❑ Telecopy(Fax)
❑ Electronic Mail (Email)
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.WRITTEN COMMENTS—Page 28
CASE NO.IPC-E-24-45

Dr. Don Reading ❑ U.S. Mail
Industrial Customer of Idaho Power ❑ Hand Delivered
280 S. Silverwood Way ❑ Overnight Mail
Eagle, ID 83616 ❑ Telecopy(Fax)
dreadinggmindspring com ® Electronic Mail (Email)
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
tnel son(a,hollandhart.com
awj ensen(&hollandhart.com
karoach&hollandhart.com
aclee(a,hollandhart.com
ERIC L. OLSEN
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.WRITTEN COMMENTS—Page 29
CASE NO.IPC-E-24-45