20260731IIPA Comments - Redacted.pdf

Eric L. Olsen(ISB#4811)
ECHO HAWK& OLSEN, PLLC RECEIVED
505 Pershing Ave., Ste. 100 JULY 31, 2026
P.O. Box 6119 IDAHO PUBLIC
Pocatello, Idaho 83205 UTILITIES COMMISSION
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-26-04
COMPANY'S APPLICATION FOR
CERTIFICATES OF PUBLIC IDAHO IRRIGATION PUMPERS
CONVENIENCE AND NECESSITY FOR ASSOCIATION,INC.'S WRITTEN
THE SOUTH HILLS AND PEREGRINE COMMENTS
POWER PLANTS AND FOR AN
ASSOCIATED ACCOUNTING ORDER.
The Idaho Irrigation Pumpers Association, Inc. ("IIPA"), by and through counsel, hereby submits
its Written Comments on Idaho Power Company's("Idaho Power"or"Company")Application for
Certificates of Public Convenience and Necessity for the South Hills and Peregrine Power Plants
and for an Associated Accounting Order, as follows:
Introduction
The Idaho Irrigation Pumpers Association ("IIPA") submits these comments to clarify how the
record in this proceeding may affect future rate design, cost-of-service ("COS") allocation, and
cost recovery, in the event the proposed resource is approved.
IIPA does not seek here to relitigate the Company's resource selection. Those issues have been
addressed in prior CPCN proceedings and remain preserved.Instead,these comments are intended
to ensure that the record clearly reflects several features of the proposed project that will directly
influence downstream ratemaking outcomes.
In particular, the record indicates that the proposed resource arises from an identified capacity
deficit, and that the Company pursued procurement under time constraints that affected both the
structure of the contract and the timing of cost commitments. As a result, the project reflects not
only the cost of physical capacity, but also the costs associated with procurement timing,
optionality, and risk allocation.
These distinctions matter for ratemaking. Costs associated with system need are typically allocated
based on cost causation principles,whereas costs associated with timing decisions, execution risk,
or optionality may not be attributable to specific customer classes in the same way.
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CASE NO.IPC-E-26-04

Accordingly, IIPA's purpose is to ensure that the record clearly reflects:
1. the magnitude and structure of the project's costs;
2. the extent to which those costs are driven by system need versus procurement timing or
contractual structure; and
3. the degree to which risks have been transferred to, or retained by,customers.
As discussed below, several elements of the Company's proposal, including pre-approval cost
commitments, cost escalation mechanisms, and the absence of class-specific need analysis, may
affect whether future rates align with cost causation principles or result in cross-subsidization
among customer classes.
These comments do not assert a specific ratemaking outcome. Rather, they identify issues that
should remain visible in the record for consideration in subsequent COS and rate proceedings.
I. Root cause of the project and implication for cost structure.
The record indicates that the project is driven by an identified capacity need. However,the manner
in which that need was addressed—specifically,the timing of procurement and the structure of the
resulting contract—appears to have introduced additional cost components beyond the underlying
resource itself.
In particular:
1. the Company pursued procurement under conditions that required securing manufacturing
capacity in advance;
2. this resulted in a non-refundable reservation payment made prior to regulatory approval;
and
3. the contract includes provisions that allow for cost variability over time (e.g., tariffs,
change-in-law adjustments).
These features suggest that a portion of total project cost may be attributable not solely to the
physical provision of capacity,but also to procurement timing and risk management decisions.
To the extent that is the case, the record does not currently distinguish between costs driven by
system capacity need and costs driven by the timing and structure of procurement.
This distinction may be relevant in future proceedings when determining whether all costs are
appropriately recoverable from customers and how those costs should be allocated.
H. '_von-refundable reservation fee and optionality risk
The record establishes that the Company committed to a non-refundable reservation
fee to secure turbine manufacturing capacity.' This amount represents approximately_ of the
1 Unit Manufacturing Reservation Agreement,Section 2.lines 40-48-
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total project cost )?The Company committed this fee is nonrefundable except in
limited seller-default circumstances.' The Company further confirmed it did not notify the
Commission, Staff, or other parties prior to making this commitment.
This payment has several notable characteristics. First, it is a sunk cost incurred prior to a
determination of need or prudence. Second, it reflects a decision to secure optionality(i.e., future
access to equipment)rather than a completed investment in a used-and-useful asset.And finally,it
transfers procurement timing risk from the Company to customers, if recovered in rates.
If this cost is included in rate base or otherwise recovered from customers, it may shift execution
and timing risk from shareholders to ratepayers as well as establish precedent for recovery of pre-
approval expenditures not contingent on CPCN approval.It may also allocate costs associated with
optionality across all customers,regardless of whether those customers drove the underlying need.
The record does not quantify what portion of this payment is attributable to system need versus
procurement timing,nor does it demonstrate how this allocation of risk is consistent with standard
prudence principles.
III. Scale of investment and potential rate impact
The project's total cost of approximately implies a substantial ongoing revenue
requirement.5
Under typical utility financing assumptions(i.e.blended cost of capital and depreciation),this level
of capital investment would translate into annual revenue requirements on the order of_
per year. Even small deviations in how these costs are fluictionalized or
allocated could result in materially different rate impacts across customer classes.
At this scale, a 5-10% misallocation would correspond to several million dollars annually.
Furthermore, such differences would persist over the life of the asset; and the effects would
compound through subsequent rate cases.
The record contains one quantified example of procurement timing cost-- the non-
refundable reservation payment made to secure turbine manufacturing
capacity.This provides a lower bound on the magnitude of costs attributable to procurement timing
and optionality. While the record does not further decompose total project cost, the structure of
utility-scale generation procurement allows for a bounded, quasi-quantitative assessment of
additional timing related cost drivers based on known externalities.
The first externality is the manufacturing timing premium. Gas turbine supply chains are
characterized by limited manufacturing capacity and long lead times. Securing an earlier delivery
2 Contract for the Sale of Gas Power Equipment and Related Services.Section 2.1-L lines 75-82.
3 Response to IIPA Request No.1-2,Confidential Attachment;see also Company Response stating no refund if CPCN is denied-
4 Response to IIPA Request No.1-1b.
5 Contract for Sale of Gas Power Egtupment 2.1_1.
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position typically requires either upfront reservation payments (such as those observed here), or
acceptance of a higher contract price relative to later delivery. The observed reservation fee
- is consistent with a non-trivial timing premium. If this payment reflects only the explicit
component of securing schedule priority, then the total timing-related premium, including
embedded pricing effects, could plausibly exceed this amount.
Next, there is an acceleration versus deferral cost tradeoff. From a system planning perspective,
procurement timing reflects a tradeoff between the cost of accelerating resource availability
(including reservation payments and potential price premiums), and the cost of deferring
procurement (i.e. reliability risk, market purchases, or interim solutions). The record does not
quantify this tradeoff. However, the presence of a substantial non-refundable payment indicates
that the Company assigned material value to acceleration. In absence of comparative analysis,the
magnitude of this value cannot be independently evaluated.
Exposure to exogenous cost escalation must also be considered. The contract allows for price
adjustments due to tariffs and changes in law. Even under conservative assumptions a 3-5%
escalation applied to corresponds to ; a 5-10% range
corresponds to
These values are comparable in scale to the reservation payment and represent additional cost
drivers not directly tied to system capacity need.
Finally, fuel price sensitivity is a long term cost driver. For a gas-fired resource, lifecycle cost is
strongly influenced by fuel price trajectories. Although the Company performed stochastic
analysis, the absence of integrated sensitivities in the core model limits visibility into how fuel-
driven cost variability compares to capital-related timing costs.Taken together,the record supports
the conclusion that at least is directly attributable to procurement
timing and optionality, and additional timing-related costs may be embedded in contract pricing
but are not separately identified. Finally, other non-need-driven cost drivers (e.g., escalation
provisions) could contribute on the order of several million to tens of millions of dollars over the
project lifecycle.
While these estimates are necessarily approximate, they indicate that a non-trivial share of total
project cost may be attributable to procurement timing, risk management, and external factors
rather than the underlying provision of capacity. The record does not quantify or isolate these
components,which may be relevant in future determinations of prudence, cost recovery, and cost
allocation.
IV. Incomplete sensitivity analysis within cost effectiveness framework
The Company acknowledged that its 20-year cost-effectiveness analysis did not include a natural
gas price scenario analysis for the project.' Instead, the Company relied on a separate stochastic
6 Response to BPA Request No.1-1lb_
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analysis using multiple gas price forecasts and reported that the selected portfolio was least cost in
85% of high-gas-price iterations.'
While stochastic analysis is informative, its separation from the core decision framework has
several implications. To wit, it limits transparency insofar as the Commission is not presented with
a consistent set of comparable scenarios within the primary model, and therefore constrains the
ability to evaluate how systematically varying the fuel prices assumptions would affect relative
resource rankings. In the end, this reduces the clarity regarding the robustness of the selected
resources under alternative plausible fuel price trajectories.
For a gas-fired resource with long term exposure to fuel price volatility, integrated sensitivity
analysis is central to a least cost/least risk determination. The absence of such analysis within the
core framework leaves a gap in the record.
V. Reliance on external analysis for storage sensitivities
The Company indicated that sensitivity analysis for battery storage alternatives is contained in the
LEI Closing Report, rather than directly developed within this record.' To the extent that
alternative resource sensitivities are not modeled within the same analytical framework and results
are not presented on a consistent, side by side comparison basis, the record does not provide a
directly comparable evaluation of resource options.
This limits the ability to determine whether the selected resource represents the least cost option
under a consistent set of assumptions,particularly since storage technologies are often sensitive to
input assumptions (e.g., duration, degradation, market participation).
VI. Absence of modeling regarding AFL contribution to need
The Company confirmed that it conducted no additional modeling or analysis regarding the
contribution ofAFL customers to the identified capacity deficits.9 The Company further stated that
it does not evaluate system capacity position without AFL, and therefore cannot provide the
requested percentages.'0
This has direct implications for cost allocation. If the system need driving the project is not
decomposed by customer class, then there is no analytical basis to assign costs in proportion to
cost causation and it is not possible to determine whether certain classes are over or under
contributing to capacity needs. The end result is that allocation decisions may default to broad
averages rather than class-specific drivers.
This is particularly significant for a capacity-driven resource, where allocation is typically based
on contribution to peak demand or related metrics.
7 Response to IIPA Request No.1-1 Ib.
8 Response to IIPA Request No.1-3b.
9 Response to IIPA Request No.1-5b.
10 Response to IIPA Request No.1-10.
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VII. Contractual cost escalation mechanisms
The contract allows for adjustments in price due to tariffs and changes in law.11 These provisions
introduce uncertain future cost exposure. Given the project scale, even a 5%cost increase would
correspond to approximately and such increases could occur after CPCN
approval. Absent specific limitations, these costs may be recoverable from customers.
The record does not provide quantified bounds on these risks or describe how such incremental
costs would be allocated across customer classes.
VM. Contractual risk structure
The contract includes provisions for: equitable adjustments; excusable events; and capped
liquidated damages.12 These provisions suggest that certain risks (e.g., delays, cost increases)
may be partially transferred away from the vendor,which means that customer exposure may not
be fully offset by damages and residual risk may ultimately be borne through rates. The record
does not quantify the magnitude of these risks or demonstrate how they are balanced between
shareholders and customers.
Conclusion
The record in this proceeding demonstrates that the proposed resource involves a large capital
investment a material pre-approval,non-refundable cost commitment-
- and contractual provisions that allow for cost variability over time.
In addition,the record indicates that certain sensitivity analyses are not integrated into the primary
cost-effectiveness framework; that class-specific contributions to system capacity need have not
been quantified; and that key cost and risk drivers are not explicitly linked to allocation principles.
Taken together, these factors suggest that a portion of project costs may be driven not only by
underlying system need,but also by procurement timing and contractual structure.
To the extent the resource is approved, these distinctions have direct implications for future rate
proceedings,including:
1. whether particular costs are deemed prudently incurred and recoverable;
2. how costs are fimctionahzed between capacity, energy, and other services; and
3. whether allocation outcomes align with cost causation or result in cross-subsidization
among customer classes.
EPA submits these comments to ensure that these issues are clearly reflected in the record and
available for full consideration in subsequent COS and rate design proceedings. IIPA reserves all
rights to address these matters in those future dockets.
11 Contract Sections 2.1.1 and 14.3.
12 Contract Sections 5,14.
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CASE NO.IPC-E-26-04

DATED this 3 1" day of July, 2026.
ECHO HAWK& OLSEN
ERIC L. OLSEN
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.WRITTEN COMMENTS—Page 7
CASE NO.IPC-E-26-04

CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on this 31 st day of July, 2026, I served a true, correct and
complete copy of the foregoing to each of the following, via method 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)
secretM.,puc.idaho.gov ® Electronic Mail (Email)
Kelsea Ross, Deputy Attorney General ❑ U.S. Mail
Idaho Public Utilities Commission ❑ Hand Delivered
11331 W. Chinden Blvd., Bldg. No. 8, ❑ Overnight Mail
Suite 201-A (83714) ❑ Telecopy(Fax)
P.O. Box 83720 ® Electronic Mail (Email)
Boise, ID 83720-0074
kelsea.ross&]2uc.Idaho.gov
Donovan E. Walker ❑ U.S. Mail
Timothy Tatum ❑ Hand Delivered
Connie Aschenbrenner ❑ Overnight Mail
Idaho Power Company ❑ Telecopy(Fax)
1221 W. Idaho Street(83702) ® Electronic Mail (Email)
P.O. Box 70
Boise, ID 83707
dwalker&idahopower.com
dockets(&idahopower.com
ttatumgidahopower.com
caschenbrennergidahopower.com
Lance Kaufman, Ph.D. ❑ U.S. Mail
Deborah Glosser, Ph.D. ❑ Hand Delivered
2623 NW Bluebell Place ❑ Overnight Mail
Corvallis, OR 97330 ❑ Telecopy(Fax)
lance(a),ae isg insi hg t.com ® Electronic Mail (Email)
deborah. log sserggmail.com
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CASE NO.IPC-E-26-04

Austin Rueschhoff ❑ U.S. Mail
Thorvald A. Nelson ❑ Hand Delivered
Richard A. Arnett ❑ Overnight Mail
Holland & Hart LLP ❑ Telecopy(Fax)
555 17th Street, Suite 3200 ® Electronic Mail (Email)
Denver, CO 80202
darueschhoff,hollandhart.com
tnelson(ir hollandhart.com
raarnett(cr�,hollandhart.com
acleeghollandhart.com
tlfrielghollandhart.com
Benjamin J. Otto ❑ U.S. Mail
Lauren McCloy ❑ Hand Delivered
Derek Goldman ❑ Overnight Mail
Northwest Energy Coalition ❑ Telecopy(Fax)
1407 W. Cottonwood Ct. ® Electronic Mail (Email)
Boise, ID 83702
bengnwenergy.org
lauren(a-nwenergy.org
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Benjamin J. Otto ❑ U.S. Mail
Mike Goetz ❑ Hand Delivered
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Kyle Unruh ❑ Telecopy(Fax)
Renewable Northwest ® Electronic Mail (Email)
1407 W. Cottonwood Ct.
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Z24'�--
ERIC L. OLSEN
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.WRITTEN COMMENTS—Page 9
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