20251003REDACTED IIPA Updated Written Comments.pdf

RECEIVED
OCTOBER 3, 2025
IDAHO PUBLIC
UTILITIES COMMISSION
Eric L. Olsen(ISB#4811)
ECHO HAWK& OLSEN, PLLC
505 Pershing Ave., Ste. 100
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-25-10
COMPANY'S APPLICATION FOR
APPROVAL OF A POWER PURCHASE IDAHO IRRIGATION PUMPERS
AGREEMENT AND AN ENERGY ASSOCIATION,INC.'S UPDATED
STORAGE AGREEMENT WITH WRITTEN COMMENTS
CRIMSON ORCHARD SOLAR LLC.
Idaho Irrigation Pumpers, Inc.,by and through counsel,hereby submits its updated written
comments to Idaho Power Company's Application for Approval of a Power Purchase Agreement
and an Energy Storage Agreement with Crimson Orchard Solar, LLC., pursuant to Commission
Rule 225, as follows:
1 Q. PLEASE STATE YOUR NAME,ADDRESS,AND EMPLOYMENT.
2 A. My name is Deborah Glosser. I am serving as a consultant for Western Economics, LLC
3 at 2623 NW Bluebell Dr, Corvallis, Oregon, 97330.
4 Q. WOULD YOU BRIEFLY DESCRIBE YOUR EDUCATIONAL BACKGROUND
5 AND PROFESSIONAL EXPERIENCE?
6 A. I earned a PhD in Civil Engineering with a focus in Materials from Oregon State
7 University in 2020, an MS in Geophysics from the University of Pittsburgh in 2013, and
8 a JD from Duquesne University in 2005. Since 2020, I have been an Assistant Professor
9 at Western Washington University in Bellingham, with appointments in the Institute for
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.'S WRITTEN COMMENTS—Page I
CASE NO.IPC-E-25-10

I Energy Studies, Engineering and Design, and the Advanced Materials Science and
2 Engineering Center. I was recently awarded tenure and will return next year as an
3 Associate Professor. My research group develops thermal energy storage materials for
4 solar thermal energy power. I teach courses at Western in the areas of energy storage
5 materials, mechanics of materials, energy policy, and thermodynamics of materials.
6 Previously, I was a member of the Staff of the Oregon Public Utilities Commission
7 (2016-2019), where I worked in both resource planning and rates.As a Senior Energy
8 Analyst at OPUC I analyzed utility integrated resource plans (IRP) and related filings to
9 ensure regulatory requirements were met, represented OPUC staff in hearings and public
10 meetings, and engaged with stakeholders to ensure the Commission's mission of
11 protecting ratepayers was met. Prior to my role at OPUC, I worked as a researcher at the
12 US Department of Energy's National Energy Technology Laboratory(2011-2016).At
13 NETL I worked on multiple research portfolios related to natural gas, coal, carbon
14 storage, and rare earth elements.
15 Q. ON WHOSE BEHALF ARE YOU COMMENTING?
16 A. I am commenting on behalf of the Idaho Irrigation Pumpers Association ("IIPA").
17 Q. WHAT IS THE PURPOSE OF YOUR COMMENTS IN THIS PROCEEDING?
18 A. The purpose of my testimony is to address Idaho Power Company's ("the Company")
19 request for approval of a Power Purchase Agreement("PPA") and Energy Storage
20 Agreement ("ESA")with Crimson Orchard Solar LLC. I will explain why this proposed
21 investment is not prudent, lacks sufficient cost containment mechanisms, and poses
22 significant financial and operational risks to ratepayers.
23
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CASE NO.IPC-E-25-10

I Q. WHAT IS THE PURPOSE OF THE COMPANY'S APPLICATION IN THIS
2 CASE?
3 A. The Company is requesting that the Commission issue an order: 1) approving the 20-
4 year PPA between Crimson Orchard Solar,LLC and Idaho Power Company supplying
5 the 100 megawatts ("MW) output to the Company("Crimson Orchard PPA"); 2)
6 approving the 20-year ESA between Crimson Orchard Solar,LLC and Idaho Power for
7 100 MW of dispatchable energy storage capacity; and 3)acknowledging the lease
8 accounting necessary to facilitate the transaction and that the resulting expenses
9 associated with both the PPA and the ESA are prudently incurred for ratemaking
10 purposes
11 Q. FROM YOUR REVIEW OF THE FILING AND OTHER SOURCES,WHAT ARE
12 YOUR CONCLUSIONS AND RECOMMENDATION?
13 A. Based on my uidependent analysis and review of the Company's filing,models and
14 workpapers, it is my conclusion and recommendation that the Commission: 1) deny the
15 20-year 100 MW output Crimson Orchard PPA; 2) deny the 20-yearCrimson Orchard
16 ESA; and 3)decline to acknowledge the lease accounting necessary to facilitate the
17 transaction and that the resulting expenses associated with both the PPA and the ESA as
18 prudently incurred for ratemaking purposes. Alternatively, if the ESA and PPA are
19 approved,the Commission should not authorize recovery above the Company's pre-
20 supplemental modeled costs. The newly proposed tariff adjustment mechanisms, which
21 cap potential increases at for the PPA and--month for the ESA2,
22 introduce additional costs but do not resolve fundamental prudency concerns. These
'Company's application in IPC-E-25-10 p. 1 and 2.
2 Company's supplemental application in IPC-E-25-10 p.10.
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I amendments increase customer exposure without addressing performance risk,escalation
2 risk, financing inconsistencies, or wildfire/system risk. I will explain the rationale for
3 these conclusions and recommendations in the forthcoming testimony.
4 Q. WHAT ARE SOME OF THE RISKS THAT THE RATEPAYERS WILL HAVE
5 TO BEAR IF THE COMPANY'S APPLICATION FOR THE PPA,ESA,AND
6 RATEMAKINNG TREATMENT IS APPROVED AT THIS TRUE?
7 - The lack of performance guarantees in the ESA contract may subject ratepayers to
8 substantial costs in the event of underperformance;
9 - The Company's unrealistic assumptions regarding ESA escalation rate over the 20-year
10 term misleadingly downplays long term financial risk;
11 - The incremental borrowing rate and WACC used in the Company's models are
12 inconsistent and thus misrepresent the true project cost;
13 - Supply chain and permitting delays exist;
14 -Fire risk is not robustly modeled, and the resuultina inputs to the RCAT model are
15 misleading;
16 - The Company is proposing to acquire a considerable amount of debt through its use of
17 PPAs,which may obscure true project costs for future rate cases.
18 The Company's supplemental tariff amendments further elevate costs by allowing capped
19 increases of up to (PPA) and--month(ESA)3. These capped
20 adjustments compound, rather than mitigate,the underlying financial and operational
21 risks to ratepayers.
22 Q. WHAT ARE THE CONSEQUENCES OF THESE RISKS?
3 Company's supplemental application p. 10.
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I A. Taken together, these factors inflate the project's perceived economic value while
2 understating its true cost,potentially resulting in significant ratepayer exposure. The
3 actual levelized cost could be substantially higher than claimed by the Company if these
4 risks materialize.
5 Q. WHAT ARE THE CONSEQUENCES OF THESE RISKS?
6 A. Taken together, these factors inflate the project's perceived economic value while
7 understating its true cost,potentially resulting in significant ratepayer exposure. The
8 actual levelized cost could be substantially higher than claimed by the Company if these
9 risks materialize.
10
11 The lack of performance guarantees in the ESA contract may subject ratepayers to
12 substantial costs in the event of underperformance
13 Q. DO YOU HAVE CONCERNS ABOUT THE LACK OF MEANINGFUL
14 PERFORMANCE GUARANTEES IN THE CRIMSON ORCHARD ENERGY
15 STORAGE AGREEMENT (ESA)?
16 A. Yes, I have significant concerns about the lack of meaningful performance guarantees in
17 the ESA4, which appears to shield the Company from financial consequences if the
18 project underperforms or misses its COD. The structure of the contract exposes
19 ratepayers to significant financial risk without providing sufficient assurance that the
20 project will deliver the promised capacity and energy over its 20 year term.
21 Q. WHAT SPECIFIC CONTRACT TERMS ARE PROBLEMATIC IN THE ESA?
4 Company's response to staff's request for production 14:In the event the battery energy storage system is
unable to reach the Contract Capacity of 100MW by the COD,the Contract Capacity will become equal to the
Effective Capacity as of the date construction is completed.Confidential Exhibit No. 5,page 29... The Guaranteed
Availability of the system is not dependent on the Effective Capacity and thus will not be adjusted.
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.'S WRITTEN COMMENTS—Page 5
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I A. There does not appear to be any penalty associated with a reduction in capacity. The ESA
2 allows for contract capacity to be reduced if the BESS fails to achieve its full 100 MW
3 nameplate capacity by the COD. Instead of imposing financial penalties,the contract
4 adjusts the effective capacity to reflect the actual performance at the time of
5 commissioning. This means that the Company can reduce its capacity commitment
6 without financial consequence, potentially resulting in lower grid reliability and higher
7 replacement costs for ratepayers. Related to this is that the ESA specifies fixed monthly
8 capacity payments that are not adjusted based on actual performance, further reducing the
9 financial risk to the company if the BESS system degrades over time or fails to deliver
10 the expected capacity. This approach is particularly problematic given the known
11 degradation risks associated with lithium-ion batteries, which can lose 20-30% of their
12 capacity over a 10-year period if not properly maintained.
13 Q. HOW COULD THESE CONTRACT TERMS AFFECT RATEPAYERS?
14 A. These contract terms may expose ratepayers to a number of risks. First there is the risk of
15 underperformance. If the BESS system underperforms, ratepayers may be forced to carry
16 the costs of capacity shortfalls (or any replacement or repairs). Second, there is the issue
17 of reduced grid reliability. Any reduced capacity could compromise grid reliability,
18 especially during periods of peak demand, which could increase the risk of blackouts as
19 well as generate emergency power costs for ratepayers.
20 Q. DO THE CONTRACT TERMS AFFECT A FINDING OF PRUDENCY?
5 Id and"Nothing in the Agreement requires the Design/Baseline Values for Certain TestMetrics be updated to reflect the Effective
Capacity.The Effective Capacity,by definition,"means the maximum power value at which the Project can continuously discharge Energy for
four(4)hours,as measured in MW AC at the Delivery Point Meter and determined pursuant to the most recent Test."Because the Effective
Capacity is determined at each test,revising the Design/Baseline values is not necessary.Rather,the Monthly Capacity Payment,as described in
section 2.2 and 2.3 of the ESA,is paid based on the then current Effective Capacity."Company's response to Staff s request for production 14.
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I A. Yes, the issues I've identified with respect to the problematic contract terms materially
2 undermines a finding of prudency in that the true risk of underperformance of capacity
3 falls on the ratepayers.
4 Q. WHAT SHOULD THE COMMISSION DO TO ADDRESS THESE CONCERNS?
5 A. The Commission should not approve the ESA in light of the significant gap in financial
6 risk protection for ratepayers. Alternatively, if the ESA is approved, the Commission
7 should disallow cost recovery in the event of underperformance of the BESS.
8
9 The Company's unrealistic assumptions regarding escalation rate over the 20-year term
10 misleadingly downplays long term financial risk;
11 Q. DO YOU HAVE CONCERNS ABOUT THE ESCALATION RATE
12 ASSUMPTIONS USED IN IDAHO POWER'S FINANCIAL MODELING FOR
13 THE CRIMSON ORCHARD PROJECT?
14 A. Yes, I have concerns about the models provided by the Company,which assume a zero
15 percent escalation rate over the 20-year term of the ESA 6. This assumption is unrealistic
16 and misleading in that it fails to account for the long-term financial risks associated with
17 rising costs over the life of the project.
18 Q. WHY IS ASSUMING A ZERO PERCENT ESCALATION RATE
19 PROBLEMATIC?
20 A. The Company's use of a 0% escalation rate in evaluating the ESA fails to reflect the
21 economic reality of a long-duration infrastructure agreement. Although the monthly
6 Company's financial models,Response to Staffs Request for Production 1,confidential attachment 2026
RFP financial models.
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.'S WRITTEN COMMENTS—Page 7
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1 capacity payment under the ESA is nominally fixed, the Company is treating the
2 agreement as a capital lease for accounting purposes and amortizing associated costs over
3 a 20-year term$. In this context, the ESA functions similarly to a utility-owned asset, and
4 it is unreasonable to assume that associated costs such as performance degradation,
5 maintenance obligations, and lifecycle management,will remain flat over two decades.
6 Q. CAN YOU PROVIDE EXAMPLES OF TYPICAL ESCALATION FACTORS
7 THAT SHOULD HAVE BEEN CONSIDERED?
8 A. Yes, utilities commonly apply escalation rates in the range of 1.5%to 3%9 annually for
9 operating expenses, based on historical trends and inflation projections. The Company
10 has failed to account for projected increases in costs of things like labor, parts
11 replacement and maintenance, and insurance premiums. This is especially problematic
12 given that the ESA is treated as a capital lease, with the utility incurring long-term
13 financial obligations akin to ownership. Under that structure, the utility and not the
14 developer bears the long-term risk of performance and financial exposure. Therefore,
15 using a 0% escalation rate understates the economic burden to ratepayers, and fails to
16 capture the true lifecycle costs of the asset.
17 Q. HOW WOULD THE LCOC CHANGE IF THE COMPANY HAD INCLUDED A
18 2.5% ESCALATION RATE OVER THE 20 YEAR TERM OF THE ESA ?
Company's Application in 25-10,page 10.
s Id: "Although similar to a PPA,the ESA differs such that the Company controls the dispatch of capacity
of the battery storage facility.As such,under Generally Accepted Accounting Principles("GAAP"),any contract
that provides the right to control an identified asset over a period of time is considered a capital lease".
9 hlWs:Hsolarbuildermag.com/news/utility-rate-escalation-is-trending-up-according-to-new-stud
"Analysis of retail commercial and industrial electricity price data from 2001 to 2023 concludes that the average
escalation rate is closer to 2.5%for top solar states,with variation by state.For example,California—a key outlier—
has seen rates climb higher,sometimes exceeding 3%annually.".
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I A. With a 2.5%annual escalation rate over the 20-year term the LCOC of the BESS ESA
2 would increase from without imputed debt to- Mmonth
3 without imputed debt(or from-with imputed debt imputed debt).
4 Q. WHAT IAAPACT COULD THESE UNREALISTIC ASSUMPTIONS HAVE ON
5 RATEPAYERS?
6 A. If the actual costs escalate,even modestly,the project could become financially
7 unsustainable,requiring ratepayers to absorb the difference. This misrepresentation of
8 long-term costs could also undermine the project's competitiveness relative to other
9 resource options,potentially locking ratepayers into an unfavorable long-term financial
10 commitment.
11 Q. HOW DO THESE RISKS AFFECT THE PRUDENCY OF THE PROJECT?
12 A. The risk of cost escalation exceeding the 0%claimed by the Company materially
13 undermines a finding of prudency for the Crimson Orchard ESA, in that long term costs
14 may be seriously underestimated, and exposes ratepayers to financial risk.
15 Q. SHOULD THE COMMISSION MPOSE A CAP ON RECOVERY IN LIGHT OF
16 COST ESCALATION?
17 A. Yes. The Commission should consider capping the recovery of costs for the Crimson
18 Orchard ESA to the values computed by the Company's models which assume a 0%
19 escalation rate over the 20-year term. Allowing cost recovery above this level would
20 effectively reward the company for underestimating its long-term financial risk, creating
21 a disconnect between the assumptions presented to the Commission and the actual costs
22 carried by ratepayers.
23
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I The incremental borrow*,ina rate and NVACC used in the Company's models are
2 inconsistent and therefore misrepresent the true nroiect cost
3 Q. DO YOU HAVE CONCERNS ABOUT THE INCREMENTAL BORRO`VING
4 RATE ("IBR")USED IN THE FINANCIAL MODEL FOR THE CRIMSON
5 ORCHARD ENERGY STORAGE AGREEMENT(ESA)?
6 A. Yes. WACC for the overall project used in the Company's financial model is_"but
7 the IBR used in the ESA financial model is estimated by the Company as_11 This
8 inconsistency suggests that the true cost of financing the project may be understated,
9 potentially exposing ratepayers to unforeseen financial risks.
10 Q. WHY IS THIS INCONSISTENCY BETWEEN WACC AND IBR
11 PROBLEMATIC?
12 A. This inconsistency is problematic for a number of reasons. First, The IBR reflects the
13 effective interest rate used to discount the future lease payments for the Right-of-Use
14 ("ROU") asset and lease liability. By using a_ rate, the Company effectively
15 understates the cost of financing the BESS portion,which makes the project appear more
16 financially attractive than it actually is.- WACC is likely more realistic since it
17 includes the blended debt and equity cost. The Company's model that uses the_
18 IBR in the lease accounting is likely reducing the present value of the lease liability,
19 which masks financial risk.
20 Q. WHAT IS THE POTENTIAL EFFECT ON RATEPAYERS OF THIS
21 INCONSISTENCY?
10 Company's response to Staffs Request for Production L.Confidential attachment,2026 RFP Financial
Models,BESS sheet cell C30.
11 Company's response to Staffs Request for Production 11.
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I A. This inconsistency can lead to inaccurate cost recovery calculations,potentially shifting
2 unexpected costs onto ratepayers if the project underperforms. If the true cost of capital is
3 closer to- the present value of the lease payments would be significantly higher,
4 leading to higher overall project costs and potentially higher rates for customers. As it is,
5 the Company's total contract value stated in their amortization schedule is
6 12. The difference in present value calculations using the WACC versus IBR
7 rates is substantial (Present Value at_ (IBR)versus Approximately
8 (Present Value at_WACC). This difference o
9 - an overstatement of the present value of costs,because they are discounted less
10 aggressively. As a result, ratepayers could end up covering more than what would be
11 reasonable if the Company had applied its true cost of capital.
12 Q. DOES THIS INCONSISTENCY RAISE PRUDENCY CONCERNS?
13 A. Yes, the mismatch between the IBR and WACC raises prudency concerns, as the true
14 cost of capital may be underestimated, and may lead to significant financial losses for
15 ratepayers.
16
17 Supply chain and Permitting delays exist:
18 Q. DO YOU HAVE ANY CONCERNS ABOUT THE ABILITY OF THE COMPANY
19 TO MEET THE CRIMSON ORCHARD PROJECT'S PLANNED COMMERCIAL
20 OPERATION DATE OF JUNE 1, 202711?
12 Company's response to Staffs Request for Production 11,confidential attachment,Capital Lease
expenditures cell E 11.
13 As stated in the Company's application in IPC-E-25-10,Section IV"Resource Descriptions"the
Crimson Orchard ESA and PPA have a COD of June 1 2027.
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.'S WRITTEN COMMENTS—Page 11
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I A. Yes, I have concerns about the project's ability to meet the claimed COD of June 1, 2027.
2 My review of the discovery materials uncovered potential points of delay, including
3 critical equipment procurement and battery supply chain challenges due to tariffs and
4 supply/demand. These factors, if not properly mitigated, could delay the project's COD
5 and may materially impact the cost and reliability of the project.
6 Q. WHAT SPECIFIC EQUIPMENT RELATED DELAYS COULD IMPACT THE
7 PROJECT'S SCHEDULE?
8 A. The main power transformer required for the project is critical, with a required order date
9 of September 26, 2024. The Company indicates that it has procured the transformer 14, but
10 it is unclear if it has taken actual possession of the transformer. The global supply chain
11 for large electrical components like transformers is currently under severe strain. Any
12 delay in ordering, manufacturing, or delivering this transformer could significantly
13 impact the project's timeline.
14 Q. ARE THERE ADDITIONAL POTENTIAL RISKS RELATED TO THE
15 BATTERY ENERGY STORAGE SYSTEM (BESS)?
16 A. Yes. The BESS component is particularly vulnerable to supply chain disruptions, and
17 cost/availability due to tariffs. The recently implemented tariffs under Trump's
18 administration could significantly impact the BESS component of the Crimson Orchard
19 project. The U.S. has imposed substantial tariffs on imported lithium-ion batteries and
20 related components, many of which are sourced from China. These tariffs have increased
21 the cost of imported batteries,potentially affecting project budgets and timelines. The
22 increased costs due to tariffs could lead to higher capital expenditure for the BESS
14 Company's response to Staff's request for Production#7: "The Main Power Transformer has been
procured by the developer on the schedule defined in Annex G."
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I component. This escalation in costs may affect the project's overall financial viability,
2 especially if the additional expenses cannot be offset through other means. Moreover, the
3 uncertainty surrounding tariff policies could deter investment and complicate long-term
4 planning for the project.
5 Q. HOW DO THESE RISKS AFFECT THE PRUDENCY OF THE PROJECT?
6 A. These supply chain and tariff risks raise serious prudency concerns because they directly
7 impact the project's ability to meet its scheduled COD and cost projections. If the project
8 is delayed or experiences cost overruns, these additional expenses will ultimately be
9 passed on to ratepayers.
10
11 Fire risk not robustly modeled, and the resulting inputs to the RCAT model are misleading
12 Q. WHY IS FIRE RISK A CONSIDERATION WITH BESS FACILITIES?
13 A. Fire risk can cause BESS curtailment in actual operations, reducing the value of the
14 BESS. As instantiated by the Idaho Power Melba substation fire that occurred in 2023,
15 BESS systems (and in particular Li-ion BESS systems) are vulnerable to both initiating
16 and being impacted by wildfires. Factors such as high ambient temperatures,proximity to
17 wildfire events, and even high loads of airborne particulate matter, can impact BESS
18 operability. Battery fires in general must be left to burn, which affects wildfire risk and
19 liability, as I further discuss below. In the case of thermal runaway, once one cell ignites,
20 a chain reaction can subsume neighboring cells, and the reaction generates oxygen and
21 flammable gasses which are resistant to water and standard fire agents.
22 Q. IS THERE A RISK OF BATTERY CURTAILMENT OR DERATING DUE TO
23 HIGH TEMPERATURES AND OR WILDFIRE RISK?
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I A. Yes, there is a well-established risk that BESS systems experience curtailment or derating
2 during periods of extreme heat. It is widely recognized that high ambient temperatures
3 can limit a battery's ability to charge or discharge at full capacity in order to protect
4 system components. Most utility-scale BESS units are equipped with thermal protection
5 systems that automatically reduce or curtail power output when cell temperatures
6 approach critical thresholds. In addition, the associated power inverters often derate their
7 output during high-temperature conditions to prevent overheating. However, the
8 Company's testimony and modeling assume full availability of the BESS projects during
9 critical summer peak periods without accounting for potential heat-related performance
10 limitations. Given the high summer temperatures common in the project areas, this
11 omission materially undermines the Company's claims that the BESS projects will
12 reliably meet peak capacity needs when they are most needed.
13 Q. HOW DOES THE COMPANY MODEL FIRE RISK?
14 A. I have reviewed the Company's model 15 and base my answers to the questions in this
15 section on this model and associated testimony. The Company uses a"historical outage"
16 method within its RCAT model which feeds into the Company's long term capacity
17 model. The company considers only external transmission lines that import power into
18 Idaho Power's Balancing Authority(i.e. internal outages are not considered). For each of
19 the three paths modeled, Equivalent Forced Outage Rate during Demand("EFORd") is
20 calculated for 31 days of each summer in 2022, 2023, and 2024, and the average value
21 for these three is taken as a percent (#wildfire outage days/# summer days per path), and
15 Company's response to IIPA's Request for Production No. 1 -9 and associated confidential attachment
containing EFORD worksheet.
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I subtracted from 100%. The EFORd values are used as an input for RCAT which is used
2 to inform capacity planning and procurement.
3 Q. ARE THE ASSUMPTIONS USED BY THE COMPANY REFLECTIVE OF REAL
4 WORLD CONDITIONS?
5 A. No. The Company only uses three years of summer data(2022-2024); only considers 31
6 days in each summer; and does not include internal transmission wildfire risk, as which
7 85 of the—100 outage events reported by the Company were characterized16. Speaking
8 specifically to the time-limited nature of the data(3 summers of 31 days each), it is
9 highly unlikely that this limited duration captures long-term risk trends. A 10-15 year
10 window adjusted for climate acceleration would yield a more robust statistical result.
11 Additionally, the model is binary in the sense that it only counts "outage days", not
12 outage duration, or load impact severity from the outages. A more nuanced approach to
13 modeling the wildfire risk would need to consider MW lost, hours of outage, and
14 associated curtailment costs. Finally, as more BESS projects are added to the system, the
15 risk of wildfire absolutely increases. In short, the model does not accurately reflect or
16 predict real world wildfire risk. Additionally, reasons that I explain below, the resulting
17 EFORd calculations produced by the model are further misleading, and may propagate to
18 the Company's capacity planning models.
19 Q. IS THE COMPANY'S EFORd CALCULATION MISLEADING?
20 A. Yes. The Company's EFORd calculation is misleading. EFORd is a measure of the
21 probability that a generating unit will not be available due to forced outages or forced
22 deratings when there is demand. EFORd provides a percentage estimate of how likely a
16 Operator Log worksheet,column E in Company's response to IIPA's Request for Production No. 1 -9
and associated confidential attachment containing EFORD worksheet.
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1 generator is to be unavailable due to unexpected issues when it's needed to provide
2 electricity to the grid.A lower EFORd indicates a more reliable and available unity. In
3 the Company's model for calculating the EFORd, as described above, the EFORd is
4 calculated as 100%minus the average%unavailable days in 31 days of each summer
5 from 2022-2024. So, if the number of wildfire days modeled by the Company was
6 notionally increased, for example, in the Idaho NW region, to include 10 more outage
7 days across the three summers (I'm selecting these values randomly), the EFORd
8 calculated by the Company's model will actually drop from
9 suggesting that the system is more reliable than it is. In other words, if you force more
10 wildfire days into the model, the model predicts fewer fiuture outage days. An internally
11 consistent forced outage model would have more wildfires lead to higher outages .It
12 appears that the Company's EFORd calculation actually reflects system reliability, not
13 forced outage probability. At this time it is unclear whether the Company"corrects"the
14 EFORd calculation in its RCAT/AURORA models, or if the error is continually
15 propagating as discussed below.
16 Q. HOW DOES THE EFORd CALCULATION IMPACT THE COMPANY'S RCAT
17 MODELS AND TRIGGER PROCUREMENT`'
18 A. Incorporating these wildfire risk uuputs mto the RCAT model impacts the outage
19 generation table used to calculate the Loss of Load Expectation("LOLE"), thus
20 impacting the annual capacity position calculation. Since the EFORd values are used in
21 the LOLE and annual capacity calculations, these errors may propagate through the
17 https://www.cw-connect.coin/sites/default/files/2020-
01/Reliabihty_Analysis_of Power_Plant_Unit_Outage_Problems_2013.pdf.
18 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.'S WRITTEN COXINIENTS—Page 16
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I models and show the units as offering more capacity than they do. In Idaho Power's
2 RCAT model, wildfire-related EFORd reduces available capacity,which may flip the
3 capacity position from surplus to deficit, triggering procurement in AURORA. If the
4 Company's EFORd values do actually reflect availability rather than forced outage
5 probability, but are used as if they're derate factors, the model could undercount risk. In
6 this case, the LOLE would be artificially low, causing the system to look more reliable
7 than it actually is, which could show a false surplus in capacity, and cause the RCAT to
8 underestimate background risk which would make new resources look more valuable
9 than they in fact, are.
10 Q. WILL RATEPAYERS BEAR ANY RISK OF INACCURACIES IN THE
11 WILDFIRE RISK CALCULATIONS?
12 A. Ratepayers will ultimately bear the risk of inaccuracies in the wildfire risk calculations.
13 The force majeure provisions in the ESA (and PPA) appear to exempt the developer from
14 paying damages if the project is delayed or destroyed by a wildfire,potentially shifting
15 the financial burden to ratepayers if replacement capacity is required19. While tariffs have
16 been removed from the force majeure provisions in the Company's supplemental
17 application, wildfire events appear to remain qualifying. The contracts do not clearly
18 require the developer to rebuild the project if it is destroyed by wildfire, raising the risk
19 that the Company and its ratepayers could be left without the promised capacity and
20 energy for extended periods.
19 Company's response to IIPA's request for production 1-16:"The Seller is responsible for achieving the
commercial operation date and maintaining performance of the facility.Any financial risk associated with a delay or
performance shortfall that is not otherwise excused(e.g.,by a claim of force majeure)will be borne by the Seller."
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.'S WRITTEN COMMENTS—Page 17
CASE NO.IPC-E-25-10

I Q. DOES THE COMPANY'S MISCALCULATION OF WILDFIRE RISK AND
2 EFORD AFFECT A FINDING OF PRUDENCY?
3 A. Yes. Given the increasing severity of wildfire events in the western United States, the
4 failure to properly model wildfire-driven transmission and generation outages materially
5 understates system risk. For example, a resource like combined-cycle combustion
6 turbines (CCCTs) are generally less prone to wildfire-related disruptions because they are
7 often located near load centers, behind substation protection, and connected via hardened
8 infrastructure. In contrast, renewable projects like solar and wind are frequently sited in
9 remote, high-fire-risk areas, and rely on long transmission corridors vulnerable to
10 proactive de-energization or fire-related derates. Yet the Company does not appear to
I 1 credit CCCTs with any avoided outage or avoided risk premium relative to fire-prone
12 resources. By omitting this,the Company may be understating the resilience value and
13 potential cost savings of dispatchable thermal resources,particularly in a system
14 increasingly exposed to wildfire threats. This omission undermines the credibility of the
15 Company's claimed capacity needs and materially affects a finding of prudency for the
16 proposed project.
17 Q. IN A RELATED DOCKET (IPC-E-24-45) THE COMPANY ASSERTS THAT ITS
18 WILDFIRE RISK FACTOR IS UNRELATED TO THE BESS PROJECTS. DO
19 YOU AGREE?
20 A. No, I do not agree. In the Company's reply comments in IPC-E-24-4520, the Company
21 asserts that the wildfire risk factor is unrelated to the BESS project, and instead reflects
22 an adjustment to the availability of certain transmission facilities that have been
20 Company reply comments in IPC-E-24-45 p.20.
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.'S WRITTEN COMMENTS—Page 18
CASE NO.IPC-E-25-10

I proactively de-energized due to wildfire encroachment and that therefore there is no
2 relationship between wildfire risk factor and risk to ratepayers. This framing misses the
3 broader point of the concern: the issue is not whether the wildfire risk factor applies to
4 the BESS assets directly, but rather whether the assumptions underlying the Company's
5 overall reliability modeling which includes transmission availability are overly optimistic
6 or insufficiently stress-tested. The Company assumes that firm market purchases can be
7 delivered through transmission paths that by their own admission have been affected by
8 wildfire outages or de-ratings. If those paths are compromised during peak conditions
9 when the BESS resources are needed most, then both the transmission access and the
10 ability to dispatch stored energy could be constrained. Thus, the risk is systemic and not
11 confined to one modeling input. The Company's attempt to isolate the wildfire risk factor
12 as unrelated to BESS ignores the interconnected nature of the grid and the potential
13 compounding impact of concurrent stress events.
14
15 The Company is proposing to acquire a considerable amount of debt through its use of
16 PPAs,which may obscure true proiect costs for future rate cases
17 Q. DO ANY FINANCIAL RISKS ASSOCIATED WITH THE PPA EXIST WITH
18 RESPECT TO IMPUTED DEBT?
19 A. Yes. The Company is not accounting for the financial risks associated with imputed debt
20 that arises from the PPA. Long term PPAs are treated as debt like obligations by credit
21 rating agencies,which means they factor into the Company's credit rating in the same
22 way as on balance sheet debt. As of 2024 year end, the Company reported $7.1 billion in
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.'S WRITTEN COMMENTS—Page 19
CASE NO.IPC-E-25-10

I contractual PPA obligations compared to- in traditional debt21. The Company
2 is proposing to acquire a considerable amount of debt through its use of PPAs here and in
3 contemporaneous dockets,and I would like to flag a concern that this sort of"off balance
4 sheet"financing may obscure true project costs for future rate cases.
5 Q. DOES THE COMPANY'S FAILURE TO INCLUDE FINANCIAL RISK
6 ASSOCIATED WITH IMPUTED DEBT RAISE CONCERNS ABOUT
7 PRUDENCY?
8 A. While imputed debt on its own is not necessarily problematic, the Company's reliance on
9 imputed debt in the present docket as well as contemporaneous dockets before the
10 Commission does raise concerns that true project costs may be obscured in future rate
11 cases.
12 Q. CAN YOU PLEASE SUMMARIZE YOUR TESTIMONY AS IT RELATES TO
13 YOUR RECOMMENDATION THAT APPROVAL OF AN ESA AND PPA BE
14 DENIED,AND THAT THE COMMISSION SHOULD EITHER DENY OR
15 PLACE A CAP ON RECOVERY FOR LEASE EXPENDITURES FOR
16 RATEMAEING PURPOSES?
17 A. Yes. The Commission should deny approval of the Crimson Orchard ESA and PPA, and
18 decline to acknowledge the lease accounting necessary to facilitate the transaction and the
19 resulting expenses as prudently incurred for ratemaking purposes. The Company's filings
20 fail to demonstrate that these agreements represent the least cost, least risk option or that
21 the associated costs have been fully and transparently evaluated. The supplemental tariff
22 amendments filed August 15,2025,do not resolve these shortcomings. While they cap
21 Response to Staff Request for Production 2.number 23 nil case IPC-E-24-46.
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.'S WRITTEN COMMENTS—Page 20
CASE NO.IPC-E-25-10

1 tariff-driven increases, they also eliminate force majeure protections and allow cost
2 recovery above the Company's modeled assumptions, further undermining a fording of
3 least-cost, least-risk. If the Commission does decide to approve the agreements, it should
4 impose a soft cap on the recoverable costs to those anchored in the Company's own
5 financial modeling assumptions,which includes a M escalation rate for the ESA and a
6 _ incremental borrowing rate for lease accounting. The Commission should make
7 clear that if actual costs or financing terms deviate materially from those assumed in the
8 Company's model, recovery above those levels will not be presumed piudent. Finally, the
9 Company's reliance on PPA structures, which are treated as imputed debt by credit rating
10 agencies, risks obscuring long-term financial obligations in firture rate cases. Given these
11 risks, the Commission should either deny the application or impose clear, enforceable
12 boundaries on what cost recovery will be permitted.
13 Q. DOES THIS CONCLUDE YOUR COMMENTS?
14 A. Yes.
DATED this Yd day of October, 2025.
f
D RAH GLOSSER
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.'S WRITTEN CObIIMENTS—Page 21
CASE NO.IPC-E-25-10

CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on this 3rd day of October, 2025, I served a true, correct and
complete copy of the foregoing to each of the following,via U.S. Mail or private courier, email or
hand delivery, as indicated below:
Monica Barrios-Sanchez, Commission Secretary ❑ U.S. Mail
Idaho Public Utilities Commission ❑ Hand Delivered
P.O. Box 83720 ❑ Overnight Mail
Boise, ID 83720-0074 ❑ Telecopy(Fax)
[e-mail] ® Electronic Mail (Email)
Donovan E. Walker ❑ U.S. Mail
Tim Tatum ❑ Hand Delivered
Idaho Power Company ❑ Overnight Mail
1221 W. Idaho Street(83702) ❑ Telecopy(Fax)
P.O. Box 70 ® Electronic Mail (Email)
Boise, ID 83707
dwalkernidahopower.com
dockets gidahopower.com
ttatum(k idahopower.com
Lance Kaufman, Ph.D. ❑ U.S. Mail
2623 NW Bluebell Place ❑ Hand Delivered
Corvallis, OR 97330 ❑ Overnight Mail
lance(kae is�.hg t.com ❑ Telecopy(Fax)
❑ 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
tnelsonghollandhart.com
awj ensen(k hollandhart.com
karoach(khollandhart.com
aclee(a,hollandhart.com
ERIC L. OLSEN
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.'S WRITTEN COMMENTS—Page 22
CASE NO.IPC-E-25-10