20251113Comments - Redacted.pdf

RECEIVED
NOVEMBER 13, 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-25-23
COMPANY'S 2025 INTEGRATED
RESOURCE PLAN IDAHO IRRIGATION PUMPERS
ASSOCIATION,INC.'S COMMENTS
ON 2025 INTEGRATED RESOURCE
PLAN
Idaho Irrigation Pumpers, Inc. ("IIPA"),by and through counsel,hereby submits its Comments on
Idaho Power Company's 2025 Integrated Resource Plan, as follows:
I. Introduction
On June 27, 2025, Idaho Power Company("Idaho Power" or"Company") filed its 2025
Integrated Resource Plan ("2025 IRP" or"IRP") and requested Commission acknowledgment of
the plan. The Commission issued Order No. 36706 on August 11, 2025,providing the notice of
the Application and intervention deadlines.
The Commission has emphasized that IRP acknowledgment is a review of the planning process
under Order No. 22299 and its progeny. As such, Commission acknowledgment of the IRP does
not approve the IRP or any resource acquisitions, endorse any portfolio, or predetermine
prudency or cost recovery. IRP acknowledgement is conditional on whether the Company has
reasonably addressed the required subjects, modeled alternatives, and documented assumptions
in a manner consistent with least-cost, least-risk planning.
In light of significant ambient uncertainty and volatility in western energy markets, IIPA
recognizes that the 2025 IRP correctly identifies uncertainty as a central planning challenge.
Idaho Power's recognition of the growing importance of interregional market participation,
flexible resources, and cross-scenario risk assessment reflects a mature understanding of how
system conditions are evolving throughout the West. These are constructive elements of the plan.
However, despite these improvements, the IRP's modeling and conclusions can continue to be
improved in several key respects, as described below.
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.IRP COMMENTS—Page I
CASE NO.IPC-E-25-23

These comments will address the Company's IRP, and how its models and assumptions result in
summer-only customers bearing a disproportionate share of demand-related costs. It is therefore
critical that the IRP record accurately identify which season and which customers drive capacity
and transmission needs. The 2025 IRP, as filed, creates a misleading record by attributing
reliability and transmission needs to summer peaks, when in fact, the data show that winter load
growth and new load due to large customers are the true drivers. The Commission should
expressly recognize that the record demonstrates capacity and transmission costs are not caused
by summer-only customers, and that reliability and transmission needs and costs are being driven
by summer peaks and large load customers.
II. Standard of Review
Order No. 22299 requires that each utility's IRP:
1. Forecast future load over 20 years, with scenarios addressing uncertainty;
2. Inventory existing supply resources;
3. Evaluate additional demand and supply-side resources;
4. Provide an analysis of load, resources, and risk under a wide range of potential futures; and
5. Present a short-term Action Plan linked to the analysis.
Subsequent orders reiterate that acknowledgment recognizes the Company's ongoing planning
process, not the conclusions or results. The Commission evaluates whether the IRP gives
balanced treatment to alternatives and adequately documents assumptions. Where the IRP record
is inconsistent with actual system drivers, the Commission should note those inconsistencies to
prevent future cost misallocations. That is the core issue being addressed in these comments: the
current IRP record inappropriately allocates need and costs of new resources and transmission.
IIPA acknowledges that Idaho Power has made strides in addressing several of the core IRP
requirements. The Company's expanded evaluation of DSR; updated resource cost assumptions;
and clearer documentation of modeling methodologies reflect genuine progress in meeting the
expectations of Order No. 22299.
III. Summary of the IRP Deficiencies
Idaho Power's 2025 IRP Action Plan is internally inconsistent and analytically unsound. Its
modeling omits key resources, embeds erroneous seasonal assumptions, and attributes new
transmission and capacity costs to legacy customers who do not cause them. Each of the
following deficiencies undermines acknowledgment under Order No. 22299.
To be clear, IIPA recognizes that Idaho Power has incorporated constructive elements into the
2025 IRP, including its identification of flexible resources as an emerging need, its
acknowledgment of uncertainty in federal policy, and its continued recognition of the role of
energy efficiency and demand response. These improvements, however, do not cure the
substantial analytical flaws identified below.
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Absence of Jackalope Wind Undermines the Preferred Portfolio
Idaho Power's 2025 IRP modeling is materially flawed. The most conspicuous flaw is the
absence of 600 MW of wind energy identified for 2027. The Jackelope wind project,which is
intended to provide that capacity, appears infeasible within the planning horizon, and the
Company's Action Plan offers no remedy or sensitivity analysis to address this outcome.
Bennett Gas Expansion Highlights a Planning Disconnect
Idaho Power's parallel application for a Certificate of Public Convenience and Necessity for the
167-MW Bennett Gas Expansion Project(Case No. IPC-E-25-29)underscores the incoherence
of the 2025 IRP Action Plan. That filing rests entirely on the 2023 IRP's capacity analysis and
makes no reference to the 2025 IRP. The Company is thus pursuing Commission approval of a
new gas resource outside of, and inconsistent with,the IRP it now asks to have acknowledged,
further demonstrating that the Action Plan does not represent an integrated or reliable plan for
meeting capacity needs.
Unacknowledged Transmission and Generation Projects
The Action Plan also fails to present several major transmission and generation additions (B2H,
Gateway West, or the Mayfield substation) as acknowledgeable items. In fact,the 2025 IRP
includes no economic analysis whatsoever of the ongoing cost effectiveness of these multibillion
dollar transmission investments, despite their central role in the Preferred Portfolio. Likewise,
the Action Plan omits acknowledgment of over one gigawatt of new generation additions
between 2026 and 2028, leaving substantial capital commitments outside of Commission review.
Transmission Expansion Is Driven by New Industrial Load, Not Reliability Needs
Idaho Power expressly seeks acknowledgment of the Southwest Intertie Project—North(SWIP-
N), a transmission project that appears designed primarily to serve the Company's new large
industrial load requests rather than traditional or reliability-driven needs. The record
demonstrates that these large loads are the dominant factor driving incremental transmission
requirements across Idaho Power's system.
Risk of Stranded Costs from Speculative Industrial Load
The Action Plan's risk analysis compounds these omissions by failing to consider a highly
material risk: the potential collapse or withdrawal of expected industrial load after Idaho Power
I
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.IIiP COMMENTS—Page 3
CASE NO.IPC-E-25-23

is financially committed to new generation and transmission. Order No. 22299 requires analysis
of load under a wide range of plausible futures. One such future, entirely credible in light of
recent market volatility, is that some or all of the forecasted large industrial load fails to
materialize or subsequently shuts down. Under that scenario, Idaho Power will have invested
billions of dollars in B2H, SWIP-N, Gateway West, and associated generation and storage, all
justified by forecasted load growth. Once those facilities are built, however, their costs become
stranded if the loads depart, shifting the financial burden to existing ratepayers.
Lack of Sensitivity Testing for Load Attrition or Timing Uncertainty
Even if these large-load customers provide letters of credit or minimum-load guarantees, such
instruments do not eliminate the risk. Unless the Commission explicitly acknowledges that the
incremental costs of these transmission resources are attributable to new large loads and ensures
those costs are recovered from the benefiting customers, exit payments will not be sufficient to
cover the stranded investment. The result is a transfer of risk from speculative new industrial
customers to Idaho Power's existing customer base.
Financial Exposure and Precedent for Utility Insolvency
IIPA is therefore concerned that the Company's proposed Action Plan exposes Idaho Power to
serious liquidity and solvency risk if the anticipated industrial load fails to appear. The warning
signs are clear: utilities across the West, including PacifiCorp2, have already cautioned regulators
of bankruptcy exposure tied to overextension on speculative growth. Idaho Power's 2025 IRP
repeats that error by embedding unverified load growth into its transmission buildout without
demonstrating corresponding long-term cost recovery.
Irrigation Customers Do Not Drive New Transmission Costs
Irrigation load still follows its predictable summer pattern and has not increased materially.
Historically, transmission capacity freed up each fall and winter, allowing the same network to
accommodate irrigation peaks without upgrades. Today, that seasonal slack is consumed by year-
round industrial demand. The record therefore does not support allocating incremental
transmission or capacity costs to seasonal irrigation customers.
Outage and Reliability Data Contradict Summer-Scarcity Claims
Idaho Power's own outage records show that transmission availability is lowest in July and
August but that the grid historically recovered in winter. With continuous industrial load, that
recovery no longer occurs: the system operates near its limits year-round. Modeling that treats
summer as the exclusive reliability constraint misrepresents the actual pattern of stress and
overstates summer adequacy risk.
Modeling Bias and Misallocation of Seasonal Costs
z https://www.wweek.com/news/state/2025/11/05/pacificorp-warns-of-bankruptcy-risk/
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.IRP COMMENTS—Page 4
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The IRP embeds structural modeling biases that inflate summer prices and misattribute costs.
Idaho Power's transmission inputs reduce import capability in summer, apply higher seasonal
losses, and include a"Longhorn Transmission for IPC Load" element that contributes capacity
only in summer. These assumptions mechanically create modeled summer scarcity even though
market and outage data show that winter is the true adequacy season. This distortion risks
shifting transmission and capacity costs onto summer-only rate classes.
Failure to Test Load Attrition and Financial Risk
The Company's risk analysis omits a critical scenario: the collapse or delay of expected large-
load growth after Idaho Power commits to major generation and transmission investments.
Without such sensitivity testing, the Action Plan ignores the potential for stranded costs. Even
with minimum-load agreements or letters of credit, exit payments would not cover the billions
invested in infrastructure built for speculative load.
Low Qualified Facility Renewal Rate Increases Resource Needs
The Company appears to assume a 28 percent renewal rate for qualified facilities.3 This low
renewal rate may be attributable to Idaho Power's qualified facility contract terms. The IRP
selects a large portfolio of wind and solar resources. However, in the current political climate,
Idaho Power may face difficulty securing these resources. Renewing qualified facilities may be a
significant resource that can meet Idaho Power's continuing resource needs. There may be value
in revisiting Idaho Power's qualified facility contract rates and terms to ensure that they contain
sound energy policy to attract qualified facility renewals when economically efficient for
customers.
Requested Commission Findings
IIPA requests that:
1. The Commission recognize that the IRP's resource plan is contingent on infeasible or
outdated project assumptions;
2. The Commission expressly recognize that IPC's new large loads are causal factors in the
acquisition of SWIP-N, Gateway West, and Mayfield; and
3. The Commission should observe that it has not acknowledged 132H, GWW, Mayfield, or
new generation or storage resource in this IRP's actions, and that prior acknowledgments
are not applicable to the actions in the current Action Plan.
s Public Utility Commission of Oregon,Docket No.LC 87, The Renewable Energy Coalition's Opening Comments
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.IRP COMMENTS—Page 5
CASE NO.IPC-E-25-23

IV. Transmission Expansion Is Load-Driven,Not Reliability-Driven
EPA agrees with Idaho Power that transmission planning is increasingly important as the region
electrifies and as winter adequacy tightens across the West. The Company's identification of
transmission as a core planning challenge is appropriate and reflects industry-wide reality.
However,the IRP's conclusions about what is driving those needs are not supported by the
record.
New Large Loads Eliminate Seasonal Headroom
Idaho Power's transmission expansion plan is not driven by traditional summer irrigation peaks
or baseline reliability needs: it is driven by the addition of large, continuous industrial loads that
now occupy the system year-round. These new Additional Firm Load("AFL") customers such as
Micron,Meta(Brisbie), Lamb Weston, and INL, have added hundreds of average megawatts of
firm demand that persist through winter as well as summer. The result is the elimination of the
seasonal headroom that once allowed the system to absorb irrigation peaks without new
infrastructure. Idaho Power's own IRP data show that transmission availability is lowest during
summer,when irrigation occurs, and that the system no longer recovers in winter because these
large industrial loads maintain high utilization levels throughout the year. Consequently, the need
for new transmission lines such as B2H, SWIP-N, and Midpoint/Hemingway#2 arises from
incremental,year-round industrial demand that keeps the grid at or near its limits,not from any
change in irrigation patterns or summer-only load. These projects are therefore properly
understood as load-driven investments,built to serve new firm customers rather than to maintain
service for existing ones.
Irrigation Load Has Not Changed—But the System Around It Has
This demonstrates that the incremental load is continuous and capacity-consuming in all months,
eliminating the winter headroom that once followed the irrigation season. What has changed is
that these high load factor industrial customers are now present year-round, occupying the
transmission capacity that historically became available once irrigation ended.
With respect to irrigation ratepayers specifically, irrigation load has always been highest in
summer, and the transmission system has long been built to accommodate that seasonal pattern.
What has changed is that large, continuous industrial loads (such as the AFL)are now present
year round. Those new loads occupy the very transmission capacity that historically became
available once the irrigation season ended. As a result, infrastructure originally designed to serve
legacy agricultural customers is now being used to serve new industrial demand, tightening
available capacity and driving incremental transmission investment.
4
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Quantified Growth in Additional Firm Load(AFL)
Idaho Power's own filings identify rapid growth in AFL (large industrial and special-contract
loads)amounting to hundreds of aMW of firm,year round demand. Appendix A and C show
AFL averaging-- aMW in 2028 and rising to— aMW in 2029 as large-load
customers such as Micron,Meta(Brisbie), Lamb Weston,and INL come online.
— Taken together, the Company's own statements show SWIP-N
is purpose-built for winter deliverability,not summer relief,which contradicts the Company's
position that summer months have the highest LOLP.
Further, Idaho Power's transmission plan is targeted towards reaching external hubs to serve
growing load. The IRP filing explains that Idaho Power must increasingly reserve third-party
transmission beyond its borders to connect to market hubs and is "actively working to secure
additional third-party transmission capacity to the Mid-C market',"with northwest transmission
capability rising with 132H by 2031;winter capability rises with SWIP-N/Four Comers, as stated
in the preceding paragraph. In fact, B2H is framed by the Company as a regional backbone
giving Idaho Power diverse connections to major western market hubs (Pacific Northwest via
B2H; Desert Southwest via the B2H-enabled Four Comers exchange9).
Regarding the Gateway West(Midpoint-Hemingway#2), the IRP ties this directly to serving
future load and relieving core customers: Gateway West Segment 8 (Midpoint-Hemingway#2)
"will increase the Midpoint West and Boise East path capabilities by—2,000 MW,""relieve
Idaho Power's constrained core transmission system between the Magic Valley and the Treasure
Valley,"and`provide future load-service capacity to the Magic Valley.10" That language, "load-
service capacity"and"core constraints",is not about summer-only use; it is about system growth
and deliverability.
The IRP record points to a pipeline of large-load customers and Additional Firm Load(AFL)
that is material in winter and growing. The Company says it"continues to manage a pipeline of
prospective large-load customers(over 1 NM""and is actively supporting siting in its service
area. Projected AFL sales reported in Appendix A of the Company's IRP and reproduced as
Figure 1 below shows that AFL rises precipitously year over year, owing,per the Company's
own caption,to prospective agreements to serve Meta,Micron, and other large load customers.
5 Idaho Power's 2025 IRP P. 67
Id.P. 68
9 Id P.70
is Id.P. 76
"Id P.85
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.IIiP COMMENTS—Page 7
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Projected Additional Firm Sales and Load,2026-2045
Billed Sales
Year (thousands of MWh) Percent Change Average Load(aMW)
2026 2,257 54.2% 258
2027 4,279 89.6% 488
2028 5,795 35.4% 660
2029 7,016 21.1% 801
2030 7,663 9.2% 875
2031 8,748 14.2% 999
2032 9,309 6.4% 1,060
2033 9,307 0.0% 1,062
2034 9,329 0.2% 1,065
2035 9,332 0.0% 1,065
2036 9,346 0.2% 1,064
2037 9,333 -0.1% 1,065
2038 9,332 0.0% 1,065
2039 9,332 0.0% 1,065
2040 9,346 0.2% 1.064
2041 9,389 0.5% 1,072
2042 9,390 0.0% 1,072
2043 9,390 0.0% 1,072
2044 9,403 0_1% 1,070
2045 9,388 -0.2% 1,072
*Includes 8nsbie,LLC(Meta Platforms,Inc.),INL,Lamb Weston,Micron Idaho Semiconductor Manutacturing,
Micron Technology,Simplot Caldwell,Simplot Pocatello Don Plant,and other committed large load customers
who have entered into procurement or construction agreements with Idaho Power but have not yet executed an
ESA.
Figure 1 Additional Firm load from Appendix A of Company's IRP filing
Appendix C's monthly summaries also show that additional firm load is substantial year-round
and growing. For example, 2028 AFL averages
)12. Those AFL levels are as large in winter as in
summer,underscoring that winter capacity and transmission will be used to serve new large load
rather than legacy summer-only usage.
Transmission Topology Mirrors Large Load Locations
Spatially, Idaho Power's transmission topology can be tied directly to new AFL in those service
areas. Idaho Power's near-term transmission buildout is a targeted 500 kV backbone that ties
specific resource entry points to the very load pockets driving the forecast. B211
(Longhorn/Hemingway)adds-300 miles of 500 kV line and-2,050 MW total transfer capability
between Boardman, OR(Longhorn substation)and Hemingway, ID, explicitly included in all
portfolios and paired with a capacity allocation and a Four Comers/Mona market access
exchange. Similarly, Gateway West Segment 8 (Midpoint/Hemingway#2 via Mayfield)relieves
the constrained Midpoint/Hemingway corridor and adds-2000 MW with Phase 1 expected in
2028 and Phase 2 in 2030, directly strengthening delivery into Boise-area special contract loads
such as Micron. Additionally, SWIP-N(Midpoint/Robinson Summit) completes a north/south
intertie to the Desert Southwest(with SWIP-S to Harry Allen),unlocking defined,WECC rated
path capacity and a contracted Idaho Power entitlement for south to-north imports. IRP Table 7.2
shows that these external paths are treated as firm market-import"resources,"with seasonal
■
WAHO IRRIGATION PUMPERS ASSOCIATION,INC.IRP COMMENTS-Page 8
CASE NO.IPC-E-25-23

capacity contributions,i.e., the topology is built to move external energy into Idaho where and
when it's usable. Appendix A defines "Additional Firm Load"as large ESA customers with
individual forecasts, i.e. Micron(Schedule 26/28),Brisbie/Meta (Schedule 33), Lamb Weston
(Schedule 34), INL (Schedule 30),which again are concentrated around the Treasure/Magic
Valley backbone that B211,Gateway West 8, and SWIP-N feed into. The Company's own
Appendix A tables and narrative show rapid AFL growth through 2030 (to—875 aMW) and
identify these named facilities and locations,while Meta's CEYW renewables and Micron's
Boise sited fab are explicitly referenced which underscores that the new 500 kV capacity
primarily serves access to specific new generation and specific new large loads, and not generic
system use.
Missing Comparative Analysis of Local Alternatives
Discovery confirms that Idaho Power's IRP treats the entire service area as a single node: Per the
Company, load"does not have a location more granular than `Idaho Power13'."Despite this,the
Company assumes B2H and Gateway West Segment 8 in every case because"additional
transmission capacity between the Treasure Valley and the Magic Valley is necessary." These
admissions show that Idaho Power pre-committed the projects to every scenario rather than
testing their necessity or cost-causation. Further, Idaho Power has not adequately evaluated
transmission alternatives.
— Without this analysis,the IRP record cannot demonstrate that
these multi-billion dollar projects are least-cost or least-risk. The Company's omission is
especially material given that definitive SWIP-N agreements were only executed on February 13,
202515
V. Action PlaI1: AdllllSSlon of Instability
Idaho Power concedes that"before or after acknowledgment Idaho Power may change its
selection to better reflect the realities at the time."This admission underscores the instability of
the Action Plan and confirms that the Company's preferred portfolio is provisional rather than
actionable.
TheAhandonnrent ofJackalope Wind Unravels the.Portfolio Logic
That instability is most evident in the disappearance of the 600 MW Jackalope Wind Project. The
Action Plan's transmission and flexible capacity additions,particularly the new gas resources,
were modeled to integrate and balance that wind capacity. Without Jackalope, the portfolio's
resource mix and timing no longer make sense.
The Bennett Gas Expansion Highlights Cross-IRP Inconsistency
13 Idaho Power's responses to IIPA's second set of DRs 2-1
■
15Id 1-10
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.IIiP COMMENTS—Page 9
CASE NO.IPC-E-25-23

The Company's subsequent filing for the Bennett Gas Expansion Project(Case No. IPC-E-25-
29)reinforces this disconnect: Idaho Power is now pursuing a 167-MW natural-gas plant
justified entirely by the 2023 IRP's capacity analysis, not by the modeling or portfolios in the
2025 IRP that it seeks to have acknowledged. In short, Idaho Power is asking the Commission to
acknowledge a plan that omits a major new gas facility it is simultaneously seeking to certificate
and finance under a separate docket, while relying on a wind project that appears infeasible.
Failure to Quantify Risk and Ratepayer Exposure
The Company's discovery responses further illustrate this fragility. Idaho Power admits it has not
quantified the cost exposure if large-load customers terminate early, nor has it modeled the
system consequences of such a departure. Together, these gaps show that the Action Plan is not a
stable or internally coherent roadmap but rather a placeholder dependent on untested
assumptions about both resource availability and new industrial load. For these reasons,
acknowledgment should be denied, or at minimum, the Commission should expressly note the
plan's instability and the substantial risk of cost misallocation if the true winter and new-load
drivers of capacity need are obscured.
VI. Seasonal Reliability and Model Bias
Idaho Power's Model Overstates Summer Scarcity
Appendix D of the Idaho Power's 2025 IRP identifies summer months as the period of greatest
reliability risk,based on its (loss of load probability, or"LOLP")modeling. In addition Idaho
Power forecasts low winter on-peak energy prices and high summer prices. The Company
therefore positions summer adequacy as the driver of capacity additions.
This finding is inconsistent with current prices and reasonable expectations.
Market Evidence Confirms Winter Reliability Risk
In recent years, observed real-time price spikes and scarcity events occur during extended cold-
weather conditions. Figure 2 below, reproduced from a 2024 CAISO report,16 demonstrates that
average winter prices in Idaho Power's Intermountain("IM") West region exceeded summer
prices in 2023 and 2024.
16 Figure E.2 of the 2024 CAISO Market Issues and Performance Report hitps://www.caiso.com/documents/2024-
annual-report-on-market-issues-and-performance-aug-07-2025.pdf
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.IRP COMMENTS—Page 10
CASE NO.IPC-E-25-23

Figure E.2 Weighted average monthly 15-minute market prices by region
$260 California
Q $240 Average prices
Desert Southwest
$220 2024 %6(2023)
,c Intermountain West
f0 $200 Pacific Northwest California 41.1 -36%
d $180 — Powerex
Desert SW 30.6 -39%
m $160 IM West 36.7 -32%
r $140 Pacific NW 49.0 -19%
& $120 Powerex 42.4 -49%
v $100
3 $80 ' \
$60
2 $40 ' -
r $20 - -
o $0 G� ;1-1 S� -0 1c� s?
Z C -i Q' v ° G
� � Z
2023 2024
Figure 2 https.11www.coiso.comldocumentsl2024-annual-report-on-market-issues-and-performance-aug-07-2025.pdf
Idaho Power positions Boardman to Hemingway as a capacity resource that will produce
abundant cheap Summer energy. This is false. Figure 2 shows that Mid-C summer energy prices
match that of Intermountain West. If anything, Boardman to Hemingway will drive up winter
energy prices in Idaho as PacifiCorp uses its large east-to-west rights to move energy west out of
Idaho to arbitrage the Pacific Northwest winter demand.
Every western utility is adding large amounts of short duration storage to their system. This
phenomenon will smooth summer pricing, as summer energy shortages are limited to a 4 to 6
hour window between the decline of solar generation and the decline of evening temperatures.
These storage resources, predominantly only 4 hours in duration,provide minimal winter
capacity value because winter heating needs are multi-day events and do not benefit from the
coincidental matching of solar production with energy consumption.17
The CAISO market data cited above demonstrate that actual scarcity events, and thus reliability
costs, remain concentrated in winter months despite a flattening or decline in forward winter
prices.
All of these factors point to increasing winter prices and decreasing summer prices.
Idaho Power's own data confirm that reliability risk is not uniquely concentrated in summer,
even though irrigation continues to follow its traditional seasonal pattern. Appendix C of the
17 In the summer,space cooling energy use coincides with peak solar production,limiting the time period that
storage is required to carry load requirements.
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.IRP COMMENTS-Page 11
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2025 IRP shows that irrigation load still peaks predictably from June through August. What has
changed is the addition of several hundred average megawatts of new industrial and special-
contract load, i,e, Idaho Power's "Additional Firm Load"(AFL). This year-round demand now
occupies transmission capacity that historically became available after the irrigation season,
removing the seasonal flexibility that once allowed the system to operate without major new
investments.
The Company's outage records reinforce this point. Historical data show that transmission
availability is lowest in July and August,which is precisely when irrigation occurs, indicating
that the system has always been most constrained in summertg. When large industrial loads are
layered on top of this seasonal peak, the network remains near full utilization throughout the
year, converting what used to be a temporary summer pinch point into a permanent adequacy
constraint.
■
■
20 Attachment 1 to Idaho Power's Response to IIPA Request No.2-4
IDAHO IRRIGATION PUMPERS ASSOCUTION,INC.IRP COMMENTS—Page 12
CASE NO.IPC-E-25-23

Month
VI. Transmission Investment Drivers and Seasonal Adequacy
The Preferred Portfolio presents Boardman-to-Hemingway(2027), SWIP-North(2028),and
Midpoint-Hemingway#2 (2028/2030)as if they are summer adequacy projects. Yet transmission
flow studies through NERC reliability assessments and CAISO congestion data indicate that
transmission stress occurs primarily under winter adequacy conditions21.
21 NERC 2024-25 winter reliability assessment,e.g."Winter electric load is growing in most areas as the grid
increasingly powers heating,transportation systems,and new data centers"
https://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/NERC WRA 2024.pdf
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.IIiP COMMENTS—Page 13
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Market Congestion and Price Evidence Show Winter Scarcity
Section 5 of the CAISO report documents frequent congestion on Intermountain West interties,
and shows that import dependence and price spikes occur during winter(Q 1) rather than summer
(Q3)22. When congestion data are combined with the seasonal price data shown above, they
demonstrate that congestion is at issue most critically in winter. Furthermore, the CAISO report
explicitly states: "The Pacific Northwest and Intermountain West continued to have significantly
lower transfer capacity into and out of their regions than the Desert Southwest and California.
This contributed to balancing areas in these regions being more frequently separated by
congestion from the larger WEIM system23. Thus, winter imports are capacity driven which
reflects scarcity; whereas summer imports are economically driven.
Figure 1.49 from the CAISO report, reproduced below as Figure 4, provides a direct view of the
Intermountain West region. This figure shows both import volumes and market prices for the
Intermountain West region. The stacked bars show the components of net imports (base WEIM,
dynamic WEIM, and non-WEIM imports). Positive values mean the Intermountain West was
importing power; negative values indicate net exports. The lines overlay the corresponding
average day-ahead market prices at Mid-Columbia(blue), Palo Verde (red), and the net
interchange proxy(black). This chart shows that imports are elevated in both winter(Q1) and
summer(Q3). However, the price outcomes are very different: In Q1 2024, imports were high
and average prices spiked above $100/MWh,which is clear evidence of adequacy stress under
cold-weather conditions. The spike in 2024 Q3 imports, however, coincides with moderate prices
(around$60-70/MWh), which reflects economic transfers rather than scarcity. The distinction is
critical. Winter imports are capacity-driven: they occur when the region is short and prices rise
sharply. Summer imports are economically driven: they reflect trading opportunities but do not
signal reliability shortfalls.
Therefore, while Idaho Power's IRP frames transmission projects as summer adequacy solutions,
the market evidence demonstrates that winter adequacy and incremental new load growth are the
true drivers of import dependence and high-cost transmission needs. Summer-only customers do
not drive the need for billion-dollar transmission expansions. Those projects are being built to
serve new load and ensure deliverability under winter stress. The IRP fails to make this explicit,
creating a risk of misallocating costs.
22 CAISO report https://www.caiso.com/documents/2024-annual-report-on-market-issues-and-performance-aug-07-
2025.pdf Table 5.2,Figure 5.9
23 Id p. 5
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.IRP COMMENTS—Page 14
CASE NO.IPC-E-25-23

Figure 1.49 Intermountain west-Net imports and average day-ahead price (peak hours, 2023-
2024)
Net non-WEIM base imports Net base WE imports
Net dynamic WEIM imports Net interchange
Mid-Columbia Palo Verde
1,100 $150
1,000
900
800
700 $100
600
500
3 400
300 $50
200 -4%
100
0
-100 $0
-200
-300
-400
500 -$50
Q1 Q2 Q3 Q4 Q3 Q2 Q3 Q4
2023 2024
Figure 4 https.11www.caiso.comldocumentsl2O24-annual-report-on-market-issues-and-performance-aug-07-2025.pdf
Transmission Expansion Follows Incremental Firm Load, Not Irrigation Demand
-. Absent this incremental load,the existing
transmission network would remain sufficient to meet reliability and market-access needs.
The Company's own IRP shows that B2H is modeled as a summer import path with 1,050 MW
west-to-east and 1,000 MW east-to-west capacity, and that it is"capacity-limited during summer
months due to imports from the Pacific Northwest25". By contrast, SWIP N is explicitly
described as a winter reliability resource, delivering northbound capacity from the Desert
Southwest26.
Taken together,these materials confirm that
transmission expansion is a response to incremental load growth, and not a system necessity for
legacy customers. Thus,the resulting cost escalation in the Preferred Portfolio reflects the need
to serve new firm load,particularly under winter adequacy constraints.
■
Appendix C,Table 7.3 and§7.1,pp.68-73
26 Appendix C.pp.78-81
■
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.IIiP COMMENTS—Page 15
CASE NO.IPC-E-25-23

Implications for Cost Allocation and Customer Impacts
These transmission findings are directly relevant to the cost structure of the Preferred Portfolio.
If major transmission projects such as B2H, SWIP N, and Midpoint-Hemingway#2 are included
primarily to accommodate incremental firm load,then the associated generation additions such
as gas units, long duration storage, and Bridger conversions, are likewise load-driven rather than
baseline reliability requirements. Because Idaho Power's Loss-of-Load Expectation(LOLE) and
Effective Load Carrying Capability(ELCC) analyses show the binding reliability constraints
occur during winter months,the portfolio's most expensive capacity additions are triggered by
new winter load obligations,not by legacy summer peaking conditions. This distinction matters
for cost allocation: the Preferred Portfolio's elevated net present value reflects new-load-driven
winter adequacy costs,not system upgrades benefiting existing customers.
VII. Artificial Sumner Scarcity in Modeling Inputs
Embedded Derates and Loss Factors Inflate Sunnner Prices
First,the Company's AVA Idaho Northwest interface shows a significant seasonal derate. The
workbook lists total transfer capability(TTC)of roughly 450 MW in winter months,but only
340 MW during summer and fall, a reduction of about 24%29. This reduction limits the model's
ability to import lower cost regional power in July through September,which automatically
increases scarcity and clearing prices during that period.
Second,loss factors vary monthly on the same paths from roughly 24%and further reduce
effective headroom in late July-September30. This further reduces effective import headroom in
summer hours.
Modeled Transmission Elements Misstate Seasonal Availability
Third, Idaho Power modeled a "Longhorn Transmission for IPC Load"element that contributes
capacity only during the summer quarter, even though the physical line is a firm all-season asset.
This seasonal element provides approximately 423 -498 MW only in Q3,with zero winter
capacity, exaggerating the system's summer supply and removing a year-round transmission
resource31
■
ATC Backgnd worksheet,cells Ell—G11(z 450 MW winter)and J11—Nl1 (--340 MW summer/fall);cell 011
restores 450 MW in December.
31 Links worksheet,cells A10—B12(loss factors 0.0204—0.0445)and cell A14(note"Monthly values vary,refer to
ATC Background for IDNW values").
31 Transmission Capacity PRM worksheet,cells AH45—AJ45(423-498 MW July—September)and AK45—AN45 (0
MW October—March).
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.IIiP COMMENTS—Page 16
CASE NO.IPC-E-25-23

Modeling Bias Creates Misleading Summer Price Signals
Taken together, these assumptions systematically elevate simulated summer prices without any
underlying evidence of physical scarcity. Historical outage records and CAISO data instead
show that outages and import constraints occur in both summer and winter, with the most severe
adequacy stress in cold periods.
IX.Conclusion
For the forestated reasons, the Commission should make explicit findings that:
1. The IRP's resource plan is contingent on infeasible or outdated project assumptions;
2. Transmission and capacity needs are driven by new industrial load growth and winter
adequacy, not by summer only customers; and
3. The incremental costs of major transmission additions must be attributed to the customers
and conditions that cause them.
Such findings are essential to prevent misallocation of transmission and capacity costs to legacy
irrigation and seasonal customers and to ensure that future rate recovery aligns with actual
system cost drivers.
DATED this 14th day of November, 2025.
ECHO HAWK& OLSEN
ERIC L. OLSEN
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.IRP COMMENTS—Page 17
CASE NO.IPC-E-25-23

CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on this 14th day of November, 2025, I served a true, correct and
complete copy of the foregoing to each of the following as indicated below:
Monica Barrios-Sanchez, Commission Secretary ❑ U.S. Mail
Jeff Loll, Deputy Attorney General ❑ Hand Delivered
Idaho Public Utilities Commission ❑ Overnight Mail
P.O. Box 83720 ❑ Telecopy(Fax)
Boise, ID 83720-0074 ® Electronic Mail (Email)
[e-mail]
j eff.loll(&puc.Idaho.ggv
Megan Goicoechea Allen ❑ U.S. Mail
Donovan E. Walker ❑ Hand Delivered
Timothy Tatum ❑ Overnight Mail
Riley Maloney ❑ Telecopy(Fax)
Micah Babbitt ® Electronic Mail (Email)
Idaho Power Company
1221 W. Idaho Street(83702)
P.O. Box 70
Boise, ID 83707
mgoicoecheaallen(cr�,idahopower.com
dwalkera,idahopower.com
docketsgidahopower.com
ttatum(&iidahopower.com
rmaloneygidahopower.com
mbabbitt(ai idahopower.com
Lance Kaufman, Ph.D. ❑ U.S. Mail
2623 NW Bluebell Place ❑ Hand Delivered
Corvallis, OR 97330 ❑ Overnight Mail
lancegae 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(d,hollandhart.com
tnelsonghollandhart.com
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.IRP COMMENTS—Page 18
CASE NO.IPC-E-25-23

awj ensen(d),hollandhart.com
karoacha,hollandhart.com
acleekhollandhart.com
tlfrielghollandhart.com
Benjamin J. Otto ❑ U.S. Mail
Attorney for NWEC ❑ Hand Delivered
Lauren McCloy ❑ Overnight Mail
Derek Goldman ❑ Telecopy(Fax)
Mike Goetz ® Electronic Mail (Email)
Katie Chamberlin
Kyle Unruh
1407 W. Cottonwood Court
Boise, ID 83702
benknwenergy org
laurenknwenergy.org
derekknwenerg�org
mike(&renewablenw.org
katherinekrenewablenw.org
kylea,renewablenw.org
Irion Sanger ❑ U.S. Mail
Sanger Greene, P.C. ❑ Hand Delivered
4031 DE Hawthorne Blvd. ❑ Overnight Mail
Portland, OR 97214 ❑ Telecopy(Fax)
irionR,,sanger-law.com ® Electronic Mail (Email)
di�oksanger-law.com
dustin(a,)sanger-law.com
j ohnikrecoalition.com
ERIC L. OLSEN
IDAHO IRRIGATION PUMPERS ASSOCIATION,INC.IRP COMMENTS—Page 19
CASE NO.IPC-E-25-23