20250801Comments - Redacted.pdf

RECEIVED
August 1, 2025
IDAHO PUBLIC
Eric L. Olsen(ISB#4811) UTILITIES COMMISSION
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 WRITTEN
STORAGE AGREEMENT WITH COMMENTS
CRIMSON ORCHARD SOLAR LLC.
Idaho Irrigation Pumpers, Inc., by and through counsel, hereby submits its 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's ("the Company") request for
19 approval of a Power Purchase Agreement("PPA") and Energy Storage Agreement
20 ("ESA")with Crimson Orchard Solar LLC. I will explain why this proposed investment
21 is not prudent, lacks sufficient cost containment mechanisms, and poses significant
22 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 independent 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-year Crimson 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 cap recoverable costs at the levels currently projected
20 in the company's financial models, which underestimate the project's long term cost
21 burdens. I will explain the rationale for these conclusions and recommendations in the
22 forthcoming testimony.
' Company's Application in IPC-E-25-10 p. 1 and 2.
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CASE NO.IPC-E-25-10

I Q. WHAT ARE SOME OF THE RISKS THAT THE RATEPAYERS WILL HAVE
2 TO BEAR IF THE COMPANY'S APPLICATION FOR THE PPA, ESA,AND
3 RATEMAKING TREATMENT IS APPROVED AT THIS TIME?
4 - The lack of performance guarantees the ESA contract may subject ratepayers to
5 substantial costs in the event of underperformance;
6 - The Company's unrealistic assumptions regarding ESA escalation rate over the 20-year
7 term misleadingly downplays long term financial risk;
8 - The incremental borrowing rate and WACC used in the Company's models are
9 inconsistent and thus misrepresent the true project cost;
10 - Supply chain and permitting delays exist;
11 -Fire risk is not robustly modeled, and the resulting inputs to the RCAT model are
12 misleading;
13 - The Company is proposing to acquire a considerable amount of debt through its use of
14 PPAs, which may obscure true project costs for future rate cases.
15 Q. WHAT ARE THE CONSEQUENCES OF THESE RISKS?
16 A. Taken together, these factors inflate the project's perceived economic value while
17 understating its true cost,potentially resulting in significant ratepayer exposure. The
18 actual levelized cost could be substantially higher than claimed by the Company if these
19 risks materialize.
20
21 The lack of performance guarantees in the ESA contract may subject ratepayers to
22 substantial costs in the event of underperformance
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I Q. DO YOU HAVE CONCERNS ABOUT THE LACK OF MEANINGFUL
2 PERFORMANCE GUARANTEES IN THE CRIMSON ORCHARD ENERGY
3 STORAGE AGREEMENT (ESA)?
4 A. Yes, I have significant concerns about the lack of meaningful performance guarantees in
5 the ESA2, which appears to shield the Company from financial consequences if the
6 project underperforms or misses its COD. The structure of the contract exposes
7 ratepayers to significant financial risk without providing sufficient assurance that the
8 project will deliver the promised capacity and energy over its 20 year term.
9 Q. WHAT SPECIFIC CONTRACT TERMS ARE PROBLEMATIC IN THE ESA?
10 A. There does not appear to be any penalty associated with a reduction in capacity. The ESA
11 allows for contract capacity to be reduced if the BESS fails to achieve its full 100 MW
12 nameplate capacity by the COD. Instead of imposing financial penalties,the contract
13 adjusts the effective capacity to reflect the actual performance at the time of
14 commissioning. This means that the Company can reduce its capacity commitment
15 without financial consequence, potentially resulting in lower grid reliability and higher
16 replacement costs for ratepayers. Related to this is that the ESA specifies fixed monthly
17 capacity payments that are not adjusted based on actual performance, further reducing the
18 financial risk to the company if the BESS system degrades over time or fails to deliver
19 the expected capacity. This approach is particularly problematic given the known
2 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
CASE NO.IPC-E-25-10

I degradation risks associated with lithium-ion batteries, which can lose 20-30% of their
2 capacity over a 10-year period if not properly maintained3.
3 Q. HOW COULD THESE CONTRACT TERMS AFFECT RATEPAYERS?
4 A. These contract terms may expose ratepayers to a number of risks. First, there is the risk of
5 underperformance. If the BESS system underperforms, ratepayers may be forced to carry
6 the costs of capacity shortfalls (or any replacement or repairs). Second, there is the issue
7 of reduced grid reliability. Any reduced capacity could compromise grid reliability,
8 especially during periods of peak demand, which could increase the risk of blackouts as
9 well as generate emergency power costs for ratepayers.
10 Q. DO THE CONTRACT TERMS AFFECT A FINDING OF PRUDENCY?
11 A. Yes, the issues I've identified with respect to the problematic contract terms materially
12 undermines a finding of prudency in that the true risk of underperformance of capacity
13 falls on the ratepayers.
14 Q. WHAT SHOULD THE COMMISSION DO TO ADDRESS THESE CONCERNS?
15 A. The Commission should not approve the ESA in light of the significant gap in financial
16 risk protection for ratepayers. Alternatively, the ESA is approved, the Commission
17 should disallow cost recovery in the event of underperformance of the BESS.
18
s Id and"Nothing in the Agreement requires the Design/Baseline Values for Certain Test
Metrics 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 Staffs Request for Production 14.
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.'S WRITTEN COMMENTS—Page 6
CASE NO.IPC-E-25-10

I The Company's unrealistic assumptions regarding escalation rate over the 20-year term
2 misleadingly downplays long term financial risk;
3 Q. DO YOU HAVE CONCERNS ABOUT THE ESCALATION RATE
4 ASSUMPTIONS USED IN IDAHO POWER'S FINANCIAL MODELING FOR
5 THE CRIMSON ORCHARD PROJECT?
6 A. Yes, I have concerns about the models provided by the Company,which assume a zero
7 percent escalation rate over the 20-year term of the ESA 4. This assumption is unrealistic
8 and misleading in that it fails to account for the long-term financial risks associated with
9 rising costs over the life of the project.
10 Q. WHY IS ASSUMING A ZERO PERCENT ESCALATION RATE
11 PROBLEMATIC?
12 A. The Company's use of a 0% escalation rate in evaluating the ESA fails to reflect the
13 economic reality of a long-duration infrastructure agreement. Although the monthly
14 capacity payment under the ESA is nominally fixed5, the Company is treating the
15 agreement as a capital lease for accounting purposes and amortizing associated costs over
16 a 20-year term6. In this context, the ESA functions similarly to a utility-owned asset, and
17 it is unreasonable to assume that associated costs such as performance degradation,
18 maintenance obligations, and lifecycle management, will remain flat over two decades.
19
a Company's financial models,Response to Staff s Request for Production 1,confidential attachment 2026
RFP financial models.
5 Company's Application in 25-10,page 10.
6 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".
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.'S WRITTEN COMMENTS—Page 7
CASE NO.IPC-E-25-10

I Q. CAN YOU PROVIDE EXAMPLES OF TYPICAL ESCALATION FACTORS
2 THAT SHOULD HAVE BEEN CONSIDERED?
3 A. Yes,utilities commonly apply escalation rates in the range of 1.5%to 3%7 annually for
4 operating expenses,based on historical trends and inflation projections. The Company
5 has failed to account for projected increases in costs of things like labor,parts
6 replacement and maintenance, and insurance premiums. This is especially problematic
7 given that the ESA is treated as a capital lease,with the utility incurring long-term
8 financial obligations akin to ownership. Under that structure, the utility and not the
9 developer bears the long-term risk of performance and financial exposure. Therefore,
10 using a 0%escalation rate understates the economic burden to ratepayers, and fails to
11 capture the true lifecycle costs of the asset.
12 Q. HOW WOULD THE LCOC CHANGE IF THE COMPANY HAD INCLUDED A
13 2.5% ESCALATION RATE OVER THE 20 YEAR TERM OF THE ESA?
14 A. With a 2.5%annual escalation rate over the 20-year term the LCOC of the BESS ESA
15 would increase from without imputed debt to- Minonth
16 without imputed debt(or from_ with imputed debt imputed debt).
17 Q. WHAT IMPACT COULD THESE UNREALISTIC ASSUMPTIONS HAVE ON
18 RATEPAYERS?
19 A. If the actual costs escalate, even modestly,the project could become financially
20 unsustainable,requiring ratepayers to absorb the difference. This misrepresentation of
21 long-term costs could also undermine the project's competitiveness relative to other
https://solarbuildermag.com/news/utility-rate-escalation-is-trending-up-according-to-new-study/
"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.".
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.'S WRITTEN COMMENTS—Page S
CASE NO.IPC-E-25-10

I resource options,potentially locking ratepayers into an unfavorable long-term financial
2 commitment.
3 Q. HOW DO THESE RISKS AFFECT THE PRUDENCY OF THE PROJECT?
4 A. The risk of cost escalation exceeding the 0% claimed by the Company materially
5 undermines a finding of prudency for the Crimson Orchard ESA, in that long term costs
6 may be seriously underestimated, and exposes ratepayers to financial risk.
7 Q. SHOULD THE COMMISSION IMPOSE A CAP ON RECOVERY IN LIGHT OF
8 COST ESCALATION?
9 A. Yes. The Commission should consider capping the recovery of costs for the Crimson
10 Orchard ESA to the values computed by the Company's models which assume a 0%
11 escalation rate over the 20-year term. Allowing cost recovery above this level would
12 effectively reward the company for underestimating its long-term financial risk, creating
13 a disconnect between the assumptions presented to the Commission and the actual costs
14 carried by ratepayers.
15
16 The incremental borrowing rate and WACC used in the Company's models are
17 inconsistent and therefore misrepresent the true project cost
18 Q. DO YOU HAVE CONCERNS ABOUT THE INCREMENTAL BORROWING
19 RATE ("IBR") USED IN THE FINANCIAL MODEL FOR THE CRIMSON
20 ORCHARD ENERGY STORAGE AGREEMENT (ESA)?
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.'S WRITTEN COMMENTS—Page 9
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I A. Yes. WACC for the overall project used in the Company's financial model is�but
2 the 1BR used in the ESA financial model is estimated by the Company as�. This
3 inconsistency suggests that the true cost of financing the project may be understated,
4 potentially exposing ratepayers to unforeseen financial risks.
5 Q. WHY IS THIS INCONSISTENCY BETWEEN WACC AND IBR
6 PROBLEMATIC?
7 A. This inconsistency is problematic for a number of reasons. First, the IBR reflects the
8 effective interest rate used to discount the future lease payments for the Right-of-Use
9 ("ROU") asset and lease liability. By using a_rate, the Company effectively
10 understates the cost of financing the BESS portion,which makes the project appear more
11 financially attractive than it actually is.- WACC is likely more realistic since it
12 includes the blended debt and equity cost. The Company's model that uses the_
13 IBR in the lease accounting is likely reducing the present value of the lease liability,
14 which masks financial risk.
15 Q. WHAT IS THE POTENTIAL EFFECT ON RATEPAYERS OF THIS
16 INCONSISTENCY?
17 A. This inconsistency can lead to inaccurate cost recovery calculations,potentially shifting
18 unexpected costs onto ratepayers if the project underperforms. If the true cost of capital is
19 closer to_ the present value of the lease payments would be significantly higher,
20 leading to higher overall project costs and potentially higher rates for customers. As it is,
21 the Company's total contract value stated in their amortization schedule is
g Company's response to Staffs Request for Production 1,Confidential attachment,2026 RFP Financial
Models,BESS sheet cell C30.
9 Company's response to Staffs Request for Production 11.
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I °. The difference in present value calculations using the WACC versus IBR
2 rates is substantial: (Present Value a� (IBR)versus Approximately
3 (Present Value at_WACC). This difference o
4 - an overstatement of the present value of costs,because they are discounted less
5 aggressively. As a result, ratepayers could end up covering more than what would be
6 reasonable if the Company had applied its true cost of capital.
7 Q. DOES THIS INCONSISTENCY RAISE PRUDENCY CONCERNS?
8 A. Yes, the mismatch between the IBR and WACC raises prudency concerns, as the true
9 cost of capital may be underestimated, and may lead to significant financial losses for
10 ratepayers.
11
12 Supply chain and uermitting delays exist:
13 Q. DO YOU HAVE ANY CONCERNS ABOUT THE ABILITY OF THE COMPANY
14 TO MEET THE CRIMSON ORCHARD PROJECT'S PLANNED COMMERCL L
15 OPERATION DATE OF JUNE 1, 202711`'
16 A. Yes,I have concerns about the project's ability to meet the claimed COD of June 1, 2027.
17 My review of the discovery materials uncovered potential points of delay,including
18 critical equipment procurement battery supply chain challenges due to tariffs and
19 supply/demand. These factors, if not properly mitigated, could delay the project's COD
20 and may materially impact the cost and reliability of the project.
21
10 Company's response to Staffs Request for Production 11,confidential attachment,Capital Lease
expenditures cell E 11.
11 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
CASE NO.IPC-E-25-10

I Q. WHAT SPECIFIC EQUIPMENT RELATED DELAYS COULD IMPACT THE
2 PROJECT'S SCHEDULE?
3 A. The main power transformer required for the project is critical, with a required order date
4 of September 26, 2024. The Company indicates that it has procured the transformer 12, but
5 it is unclear if it has taken actual possession of the transformer. The global supply chain
6 for large electrical components like transformers is currently under severe strain. Any
7 delay in ordering, manufacturing, or delivering this transformer could significantly
8 impact the project's timeline.
9 Q. ARE THERE ADDITIONAL POTENTIAL RISKS RELATED TO THE
10 BATTERY ENERGY STORAGE SYSTEM (BESS)?
11 A. Yes. The BESS component is particularly vulnerable to supply chain disruptions, and
12 cost/availability due to tariffs. The recently implemented tariffs under Trump's
13 administration could significantly impact the BESS component of the Crimson Orchard
14 project. The U.S. has imposed substantial tariffs on imported lithium-ion batteries and
15 related components, many of which are sourced from China. These tariffs have increased
16 the cost of imported batteries,potentially affecting project budgets and timelines. The
17 increased costs due to tariffs could lead to higher capital expenditure for the BESS
18 component. This escalation in costs may affect the project's overall financial viability,
19 especially if the additional expenses cannot be offset through other means. Moreover, the
20 uncertainty surrounding tariff policies could deter investment and complicate long-term
21 planning for the project.
22
12 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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CASE NO.IPC-E-25-10

I Q. HOW DO THESE RISKS AFFECT THE PRUDENCY OF THE PROJECT?
2 A. These supply chain and tariff risks raise serious prudency concerns because they directly
3 impact the project's ability to meet its scheduled COD and cost projections. If the project
4 is delayed or experiences cost overruns, these additional expenses will ultimately be
5 passed on to ratepayers.
6
7 Fire risk not robustly modeled, and the resulting inputs to the RCAT model are misleading
8 Q. WHY IS FIRE RISK A CONSIDERATION WITH BESS FACILITIES?
9 A. Fire risk can cause BESS curtailment in actual operations, reducing the value of the
10 BESS. As instantiated by the Idaho Power Melba substation fire that occurred in 2023,
11 BESS systems (and in particular Li-ion BESS systems) are vulnerable to both initiating
12 and being impacted by wildfires. Factors such as high ambient temperatures,proximity to
13 wildfire events, and even high loads of airborne particulate matter, can impact BESS
14 operability. Battery fires in general must be left to burn, which affects wildfire risk and
15 liability, as I further discuss below. In the case of thermal runaway, once one cell ignites,
16 a chain reaction can subsume neighboring cells, and the reaction generates oxygen and
17 flammable gasses which are resistant to water and standard fire agents.
18 Q. IS THERE A RISK OF BATTERY CURTAILMENT OR DERATING DUE TO
19 HIGH TEMPERATURES AND OR WILDFIRE RISK?
20 A. Yes, there is a well-established risk that BESS systems experience curtailment or derating
21 during periods of extreme heat. It is widely recognized that high ambient temperatures
22 can limit a battery's ability to charge or discharge at full capacity in order to protect
23 system components. Most utility-scale BESS units are equipped with thermal protection
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.'S WRITTEN COMMENTS—Page 13
CASE NO.IPC-E-25-10

I systems that automatically reduce or curtail power output when cell temperatures
2 approach critical thresholds. In addition, the associated power inverters often derate their
3 output during high-temperature conditions to prevent overheating. However, the
4 Company's testimony and modeling assume full availability of the BESS projects during
5 critical summer peak periods without accounting for potential heat-related performance
6 limitations. Given the high summer temperatures common in the project areas, this
7 omission materially undermines the Company's claims that the BESS projects will
8 reliably meet peak capacity needs when they are most needed.
9 Q. HOW DOES THE COMPANY MODEL FIRE RISK?
10 A. I have reviewed the Company's model13 and base my answers to the questions in this
11 section on this model and associated testimony. The Company uses a"historical outage"
12 method within its RCAT model which feeds into the Company's long term capacity
13 model. The company considers only external transmission lines that import power into
14 Idaho Power's Balancing Authority(i.e. internal outages are not considered). For each of
15 the three paths modeled, Equivalent Forced Outage Rate during Demand("EFORd") is
16 calculated for 31 days of each summer in 2022, 2023, and 2024, and the average value
17 for these three is taken as a percent (#wildfire outage days/# summer days per path), and
18 subtracted from 100%. The EFORd values are used as an input for RCAT which is used
19 to inform capacity planning and procurement.
20 Q. ARE THE ASSUMPTIONS USED BY THE COMPANY REFLECTIVE OF REAL
21 WORLD CONDITIONS?
13 Company's response to IIPA's Request for Production No. 1 -9 and associated confidential attachment
containing EFORD worksheet.
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CASE NO.IPC-E-25-10

I A. No. The Company only uses three years of summer data(2022-2024); only considers 31
2 days in each summer; and does not include internal transmission wildfire risk, as which
3 85 of the—100 outage events reported by the Company were characterized14. Speaking
4 specifically to the time-limited nature of the data(3 summers of 31 days each), it is
5 highly unlikely that this limited duration captures long-term risk trends. A 10-15 year
6 window adjusted for climate acceleration would yield a more robust statistical result.
7 Additionally, the model is binary in the sense that it only counts "outage days", not
8 outage duration, or load impact severity from the outages. A more nuanced approach to
9 modeling the wildfire risk would need to consider MW lost, hours of outage, and
10 associated curtailment costs. Finally, as more BESS projects are added to the system, the
11 risk of wildfire absolutely increases. In short, the model does not accurately reflect or
12 predict real world wildfire risk. Additionally, reasons that I explain below, the resulting
13 EFORd calculations produced by the model are further misleading, and may propagate to
14 the Company's capacity planning models.
15 Q. IS THE COMPANY'S EFORd CALCULATION MISLEADING?
16 A. Yes. The Company's EFORd calculation is misleading. EFORd is a measure of the
17 probability that a generating unit will not be available due to forced outages or forced
18 deratings when there is demand. EFORd provides a percentage estimate of how likely a
19 generator is to be unavailable due to unexpected issues when it's needed to provide
20 electricity to the grid.A lower EFORd indicates a more reliable and available unit15. In
21 the Company's model for calculating the EFORd, as described above, the EFORd is
14 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.
15 https://www.cw-connect.com/sites/default/files/2020-
01/Reliability_Analysis_of Power Plant Unit Outage_Problems_2013.pdf.
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.'S WRITTEN COMMENTS—Page 15
CASE NO.IPC-E-25-10

I calculated as 10011/o minus the average%unavailable days in 31 days of each summer
2 from 2022-2024. So, if the number of wildfire days modeled by the Company was
3 notionally increased, for example, in the Idaho NW region,to include 10 more outage
4 days across the three summers (I'm selecting these values randomly), the EFORd
5 calculated by the Company's model will actually drop from
6 suggesting that the system is more reliable than it is. In other words, if you force more
7 wildfire days into the model, the model predicts fewer future outage days,An internally
8 consistent forced outage model would have more wildfires lead to higher outages .It
9 appears that the Company's EFORd calculation actually reflects system reliability,not
10 forced outage probability. At this time it is unclear whether the Company"corrects"the
11 EFORd calculation in its RCAT/AURORA models, or if the error is continually
12 propagating as discussed below.
13 Q. HOW DOES THE EFORd CALCULATION IMPACT THE COMPANY'S RCAT
14 MODELS AND TRIGGER PROCUREMENT?
15 A. Incorporating these wildfire risk inputs into the RCAT model impacts the outage
16 generation table used to calculate the Loss of Load Expectation("LOLE"),thus
17 impacting the annual capacity position calculation. Since the EFORd values are used in
18 the LOLE and annual capacity calculations, these errors may propagate through the
19 models and show the units as offering more capacity than they do. In Idaho Power's
20 RCAT model,wildfire-related EFORd reduces available capacity,which may flip the
21 capacity position from surplus to deficit, triggering procurement in AURORA. If the
22 Company's EFORd values do actually reflect availability rather than forced outage
"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).
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CASE NO.IPC-E-25-10

I probability, but are used as if they're derate factors, the model could undercount risk. In
2 this case, the LOLE would be artificially low, causing the system to look more reliable
3 than it actually is, which could show a false surplus in capacity, and cause the RCAT to
4 underestimate background risk which would make new resources look more valuable
5 than they in fact, are.
6 Q. WILL RATEPAYERS BEAR ANY RISK OF INACCURACIES IN THE
7 WILDFIRE RISK CALCULATIONS?
8 A. Ratepayers will ultimately bear the risk of inaccuracies in the wildfire risk calculations.
9 The force majeure provisions in the ESA (and PPA) appear to exempt the developer from
10 paying damages if the project is delayed or destroyed by a wildfire,potentially shifting
11 the financial burden to ratepayers if replacement capacity is required 17. Additionally, the
12 contracts do not clearly require the developer to rebuild the project if it is destroyed by
13 wildfire, raising the risk that the Company and its ratepayers could be left without the
14 promised capacity and energy for extended periods.
15 Q. DOES THE COMPANY'S MISCALCULATION OF WILDFIRE RISK AND
16 EFORD AFFECT A FINDING OF PRUDENCY?
17 A. Yes. Given the increasing severity of wildfire events in the western United States, the
18 failure to properly model wildfire-driven transmission and generation outages materially
19 understates system risk. For example, a resource like combined-cycle combustion
20 turbines (CCCTs) are generally less prone to wildfire-related disruptions because they are
21 often located near load centers, behind substation protection, and connected via hardened
17 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 infrastructure. In contrast, renewable projects like solar and wind are frequently sited in
2 remote, high-fire-risk areas, and rely on long transmission corridors vulnerable to
3 proactive de-energization or fire-related derates. Yet the Company does not appear to
4 credit CCCTs with any avoided outage or avoided risk premium relative to fire-prone
5 resources. By omitting this, the Company may be understating the resilience value and
6 potential cost savings of dispatchable thermal resources,particularly in a system
7 increasingly exposed to wildfire threats. This omission undermines the credibility of the
8 Company's claimed capacity needs and materially affects a finding of prudency for the
9 proposed project.
10 Q. IN A RELATED DOCKET (IPC-E-24-45) THE COMPANY ASSERTS THAT ITS
11 WILDFIRE RISK FACTOR IS UNRELATED TO THE BESS PROJECTS. DO
12 YOU AGREE?
13 A. No, I do not agree. In the Company's reply comments in IPC-E-24-4518, the Company
14 asserts that the wildfire risk factor is unrelated to the BESS project, and instead reflects
15 an adjustment to the availability of certain transmission facilities that have been
16 proactively de-energized due to wildfire encroachment and that therefore there is no
17 relationship between wildfire risk factor and risk to ratepayers. This framing misses the
18 broader point of the concern: the issue is not whether the wildfire risk factor applies to
19 the BESS assets directly, but rather whether the assumptions underlying the Company's
20 overall reliability modeling which includes transmission availability are overly optimistic
21 or insufficiently stress-tested. The Company assumes that firm market purchases can be
22 delivered through transmission paths that by their own admission have been affected by
18 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

1 wildfire outages or de-ratings. If those paths are compromised during peak conditions
2 when the BESS resources are needed most, then both the transnussion access and the
3 ability to dispatch stored energy could be constrained. Thus, the risk is systemic and not
4 confined to one modeling input. The Company's attempt to isolate the wildfire risk factor
5 as turelated to BESS ignores the interconnected nature of the grid and the potential
6 conupou nding impact of concurrent stress events.
7
8 The Company is proposine to acquire a considerable amount of debt throullh its use of
9 PPAs, which may obscure true project costs for future rate cases
10 Q. DO ANY FINANCIAL RISKS ASSOCIATED WITH THE PPA EXIST WITH
11 RESPECT TO IMPUTED DEBT?
12 A. Yes. The Company is not accounting for the financial risks associated with imputed debt
13 that arises from the PPA. Long term PPAs are treated as debt like obligations by credit
14 rating agencies, which means they factor into the Company's credit rating in the same
15 way as on balance sheet debt. As of 2024 year end, the Company reported$7.1 billion in
16 contractual PPA obligations compared to- in traditional debt19. The Company
17 is proposing to acquire a considerable amount of debt through its use of PPAs here and in
18 contemporaneous dockets, and I would like to flag a concern that this sort of"off balance
19 sheet" financing may obscure true project costs for fiitlre rate cases.
20 Q. DOES THE COMPANY'S FAILURE TO INCLUDE FINANCIAL RISK
21 ASSOCIATED WITH IMPUTED DEBT RAISE CONCERNS ABOUT
22 PRUDENCY?
19 Response to Staff Request for Production 2,nwnber 23 in case IPC-E-24-46.
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.'S Vb'RITTEN COMMENTS—Page 19
CASE NO.IPC-E-25-10

I A. While imputed debt on its own is not necessarily problematic, the Company's reliance on
2 imputed debt in the present docket as well as contemporaneous dockets before the
3 Commission does raise concerns that true project costs may be obscured in future rate
4 cases.
5 Q. CAN YOU PLEASE SUMMARIZE YOUR TESTIMONY AS IT RELATES TO
6 YOUR RECOMMENDATION THAT APPROVAL OF AN ESA AND PPA BE
7 DENIED,AND THAT THE COMMISSION SHOULD EITHER DENY OR
8 PLACE A CAP ON RECOVERY FOR LEASE EXPENDITURES FOR
9 RATEMAIINNG PURPOSES`.'
10 A. Yes. The Commission should deny approval of the Crimson Orchard ESA and PPA, and
11 decline to acknowledge the lease accounting necessary to facilitate the transaction and the
12 resulting expenses as prudently incurred for ratemaking purposes. The Company's filings
13 fail to demonstrate that these agreements represent the least cost, least risk option or that
14 the associated costs have been fully and transparently evaluated. If the Commission does
15 decide to approve the agreements, it should impose a soft cap on the recoverable costs to
16 those anchored in the Company's own financial modeling assumptions,which includes a
17 0%escalation rate for the ESA and a_ incremental borrowing rate for lease
18 accounting. The Commission should make clear that if actual costs or financing terms
19 deviate materially from those assumed in the Company's model,recovery above those
20 levels will not be presumed prudent. Finally, the Company's reliance on PPA structures,
21 which are treated as imputed debt by credit rating agencies, risks obscuring long-term
22 financial obligations in future rate cases. Given these risks, the Commission should either
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.'S WRITTEN COMMENTS—Page 20
CASE NO.IPC-E-25-10

I deny the application or impose clear, enforceable boundaries on what cost recovery will
2 be permitted.
3 Q. DOES THIS CONCLUDE YOUR COMMENTS?
4 A. Yes.
DATED this 1st day of August, 2025.
D RAH GLOSSER
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.'S WRITTEN COMMENTS—Page 21
CASE NO.IPC-E-25-10

CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on this 1st day of August, 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)
secretary,puc.idaho.gov ® 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
dwalkergidahopower.com
dockets 6-6dahopower.com
ttatum(cr�,idahopower.com
Lance Kaufman, Ph.D. ❑ U.S. Mail
2623 NW Bluebell Place ❑ Hand Delivered
Corvallis, OR 97330 ❑ Overnight Mail
lance(ae,aegisinsi 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
darueschho ff(a�hollandhart.com
tnels on(a,hollandhart.com
awj ensenghollandhart.com
karoach(a,hollandhart.com
acleenhollandhart.com
ERIC L. OLSEN
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.'S WRITTEN COMMENTS—Page 22
CASE NO.IPC-E-25-10