20260731Comments.pdf

RECEIVED
July 31, 2026
IDAHO PUBLIC
UTILITIES COMMISSION
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 ) COMMENTS OF
CONVENIENCE AND NECESSITY FOR ) RENEWABLE NORTHWEST
THE SOUTH HILLS AND PEREGRINE ) AND NW ENERGY COALITION
POWER PLANTS AND FOR AN )
ASSOCIATED ACCOUNTING ORDER. )
I. INTRODUCTION AND SUMMARY
Pursuant to the Notice of Modified Procedure in Idaho Public Utilities Commission
("Commission") Order No. 37046, Renewable Northwest("RNW") and NW Energy Coalition
("NWEC") ("Joint Advocates") submit these comments in the above-captioned matter. The Joint
Advocates appreciate the opportunity to provide comment in this important proceeding whose
outcome will have significant implications for the future of utility service for Idaho Power
Company("Idaho Power" or"the Company") customers, as well as the cost and risk they are
subjected to. RNW is a regional clean energy advocacy nonprofit with a mission to decarbonize
the region by accelerating the transition to renewable electricity.' NWEC advances clean,
equitable, and affordable energy policies by leveraging their analytic expertise and convening a
broad alliance of people and organizations.' The Joint Advocates have a shared interest in
ensuring fairness and competition in utility Request for Proposals ("RFP")processes that result
in least-cost, least-risk resources to meet the needs of the Company's needs that is clearly
identified and tethered to sound analysis in an Integrated Resource Plan ("IRP"). Contrary to the
1 https://renewablenw.org/about-us#block-ounnission
2 https://nwenergy.org/about-the-coalition/
IPC-E-26-04 NWEC/RNW Comments
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Company's assertions,' the Application fails to further any of these interests and would shift
undue cost and risk onto its customers.
On March 10, 2026, the Company applied to the Commission requesting a Certificate of
Public Convenience and Necessity("CPCN") for the South Hills Power Plant, a natural gas-fired
power plant providing up to 222 megawatts ("MW") of nameplate generation, a CPCN for the
Peregrine Power Plant, a natural gas-fired power plant providing up to 430 MW of nameplate
generation, and an order confirming the Company's application of accrual of Allowance for
Funds Used During Construction to coincide with initial procurement activities for both facilities
("Application").' According to the Company,these facilities are "necessary for Idaho Power to
continue to provide safe, reliable electric service in 2029 and beyond."' The Application seeks a
Commission recognition that the 652 MW of thermal generation sought is necessary to maintain
the Company's obligation to provide adequate and reliable service on a just and reasonable
basis.6 The record in this proceeding demonstrates that they are not.
Despite the Company's contention otherwise, the Application fails to demonstrate that
the Peregrine and South Hills plants were tied to either a sound RFP or IRP process. As these
comments will demonstrate,the decision to select these resources fundamentally lacked
sufficient analytical rigor and competition and would shift substantial cost and risk onto
customers relative to the resources that were actually selected in the RFP. As such, the Joint
Advocates respectfully recommend that the Commission deny the Application and direct the
Company to:
• Demonstrate the load forecast establishes a need for resources
3 See,e.g.,Application at 5.
4 IPC-E-26-04,Order No. 37048 at 1.
5 Application at 2.
6 Application at 11.
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• Demonstrate the Company will seek cost recovery from new customers who cause the
need for new resources
• Conduct a competitive and robust RFP process to assess resource options specific to
the identified need
• Utilize accurate and up to date resource costs assumptions
• Fully disclose and analyze the range risks of associated with new gas generation
II. DISCUSSION
A. The Company's relies on uncertain load forecast and new large loads to justify need
Idaho Power asserts that continued load growth drives the need for additional capacity of
236 MW by 2029, increasing to 352 MW in 2030.' The proposed procurement of both South
Hills and Peregrine power plants would dramatically exceed this capacity need by adding 652
MW of capacity. The Joint Advocates note the load forecast here did not arise through the public
IRP process. Rather, the load forecast is internal to Idaho Power and includes substantial
amounts of new industrial load.' Despite asking, the parties have not seen a load and resource
balance that excludes the speculative new large loads driving a large part of this resource need.9
This effectively skirts the reasonable inquiry regarding the extent to which additional firm load is
contributing to capacity needs. Although the Company may believe some level of new firm load
is guaranteed to materialize and be sustained, the extent to which the load may be flexible, and
thus fit within the current system, or whether the load is sustained over the lifetime of the
proposed power plants ought to be open for discussion.
7 Idaho Power Company,Direct Testimony of Jared Ellsworth at 12.
8 Ellsworth Direct at pg 9.
9 Staff s Request for Production No.25.
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The Commission does not have any certainty these projected new loads will materialize
and thus risks approving an overbuild of the system. Further, in other proceedings and public
forums, Idaho Power asserts that new loads will pay the entire costs of the new infrastructure
required. The Commission should deny the Application until Idaho Power demonstrates the
resources are needed to meet a known and measurable load and that new customers pay for new
resources.
B. The resources were not procured through a competitive procurement process
Despite the Company's assertions, the resources at issue in the Application were not
procured through a competitive RFP process and, therefore, cannot be the verifiably least-cost,
least-risk resources. In testimony, the Company points to a 138 MW capacity need in 2028
identified in the 2023 IRP, which included 555 MW of supply-side resources to meet those
needs.10 The Company notes that the 2023 IRP also identified incremental capacity needs of 142
MW in 2029 and 369 MW in 2030, growing to over 1,150 MW by 2038.11 The Company asserts
that the RFP conducted subsequent to the 2023 IRP allowed it to "access the broader peak
capacity and energy market across a spectrum of potential resources and developers to obtain the
best resources for Idaho Power's customers."12 In testimony, the Company spends significant
time noting the rigor of the competitive solicitation process that followed the 2023 IRP.13
According to the Company, it"conducted an extensive competitive bidding process following
the resource procurement rules of the [Oregon Public Utility Commission], as required by the
Idaho Commission at that time.1,14 The Company states:
10 Hackett Direct at 6,lines 2-6.
11 Id.at lines 6-9. As these comments will note,the capacity need identified by the Company in later years is based
on questionable assumptions.
12 Id.at lines 13-16.
13 See Hackett Direct at 7.
14 Hackett Direct at 39.
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[t]he RFP process began with the engagement of an [Independent Evaluator], with
participation from OPUC Staff and stakeholders throughout, and involved a
comprehensive eligibility screening process, the meticulous assessment and scoring of
resource bids, including benchmark resources, and a rigorous scenario analysis followed
by a portfolio sensitivity analysis and an additional qualitative factor analysis of the final
shortlist projects.15
While it is true that the Company conducted a competitive solicitation process to identify
resources to meet system needs, neither resource in the Application was considered in that
process. That is to say that neither South Hills nor Peregrine were examined by an Independent
Evaluator("IE"), they did not appear on a Final Shortlist("FSL"), were not examined in any
RFP, and were not analyzed in any public process that would allow independent verification
regarding whether the resources are truly least-cost, least-risk. As noted by the Company, at the
time these resources were selected, the Commission required the Company to follow the Oregon
Public Utility Commission's Competitive Bidding Requirements ("CBRs").16 Among many
other factors, the CBRs require—absent a specific waiver—that the selection of a FSL "must be
based on bid scores and the results of modeling the effect of candidate resources on overall
system costs and risks using modeling methods that are consistent with those used in the
Commission-acknowledged IRP."11 Rather than following this binding precept, the Company
internally evaluated South Hills and Peregrine alongside RFP FSL bids in an opaque process
utterly bereft of any stakeholder input opportunities.I I The magnitude of cost and risk the
Company will seek to shift to customers in a later cost recovery proceeding requires a greater
level of transparency and scrutiny.
1s Id.
16 Hackett Direct at 2.
17 OAR 860-089-0400(4).
18 See,e.g.,Hackett Direct at 28.
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While the Commission's CPCN process is not a cost recovery proceeding at which the
prudence of the underlying resources is at issue, it functions as a significant rung on the ladder
towards prudence. By granting the CPCN, the Commission signals to the Company that the
analysis supporting the resource decision was reasonable in light of prevailing circumstances at
the time. This determination then becomes meaningful evidence when Idaho Power seeks a
prudence determination and future rate recovery. Notably, Idaho Power does not seek any cost
recovery now and testifies to available financing opportunities and accounting methods to track
investments in these proposed gas plants. This clarifies that what Idaho Power seeks today is a
regulatory stamp of confidence the Company will recover these costs in the future. Doing so
implicitly commits customers to volatile and rising costs and risks for gas fuel supply and price.
CPCN approval has been reserved for circumstances in which the Company can conclusively
demonstrate that the resource is the result of a competitive process, optimally blends of costs and
risks for customers, and that regulatory support is required to acquire reasonable financing.19
Here, the Company cannot demonstrate that was the case.
Idaho Power testifies that, in the competitive procurement process that compiled a list of
viable resources online by 2029, eleven of the twelve bids on the FSL were wind, solar, storage,
or a combination thereof.20 Following the assembly of the FSL, the Company performed a
sensitivity analysis and a qualitative review of various factors regarding the resources that
included the impacts of the Inflation Reduction Act("IRA") repeal, tariff, siting, factors, and
GIA and/or transmission factors.21 Notably, this review did not assess the risks of gas supply
19 See, e.g., Idaho Public Utilities Commission Order No. 36011 at 5. ("The Company represented that it completed
a robust and competitive RFP process for identifying the lease-cost,least-risk resource acquisitions,and the
Company indicated that as it gains experience with the development and insurance of RFPs,future RFPs will be
refined and become more robust to ensure a continued competitive resource acquisition process.").
20 Hackett Direct at 20-21.
21 Hackett Direct at 21.
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availability and costs, the reliability risks related to reliance on thermal generation, and other
regulatory and legal risks that are addressed later in these comments. The FSL—which did not
include either resource in the Application—was approved by the Oregon Commission on August
30, 2025.22 Following this process, the Company provided Notice to Proceed with the Bennett
Gas Expansion Project—the only gas bid into the FSL that went through a competitive process.23
According to the Company, to meet the remaining capacity need after adding the Bennett
gas resource, it requested updated pricing information from the 2029 final shortlist battery
energy storage system("BESS")resources in October 2025.24 Subsequent to that process, the
Company provided a general project update indicating a transition from the Milner 60 MW
BESS benchmark bid to a gas resource, which ultimately formed the basis for this Application.21
To justify this drastic shift that occurred outside of the competitive RFP process, the Company
claims that its "Internal Bid Team was no longer able to confirm the Milner 60 MW BESS
benchmark bid was eligible for the 30 percent Investment Tax Credit [(ITC)]."26
This statement is interesting. The One Big Beautiful Bill Act ("OBBBA")was signed
into law on July 4, 2025 and retained the 30% ITC for storage resources like the Milner 60 MW
BESS project.27 28 It is unclear why the Company would assert after October 2025 that it was
uncertain that the Milner BESS project could qualify for ITCs given that the July 4, 2025 final
version of the OBBBA explicitly included the 30% ITC for storage resources. The Company
never explains this timeline in testimony but cites the potential lack of a tax credit, aka economic
22 Id.at 23.
2s Id.
24 Id.at 24.
25 Id.at 25.
26 Id.at 26.
27 https://www.cleanegroup.org/what-nonprofits-need-to-know-about-itc-2025/
28 https://www.congress.gov/bill/119th-congress/house-bill/1/text
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uncertainty, as a primary reason to shuffle in the two thermal resources that are the subject of the
Application.
The resources included in the Application were never independently verified to be least-
cost, least-risk. They were never analyzed by an Independent Expert and never made available
for public comment. The Company unilaterally decided to move forward with the resources in a
manner that departed from the Oregon Commission's RFP rules—the rules that the Idaho
Commission followed at the time. Due to these factors, and those discussed below, the Joint
Advocates respectfully request that the Commission deny the Application until Idaho Power
shows the resources are the result of, or aligned with, a thorough and competitive and complete
RFP process.
C. The Company has not shown a capacity need prior to the 2025 IRP, nor has it justified
substitution of non-competitive gas for BESS resources previously identified through RFP
The Company has not demonstrated that the Peregrine or South Hills plants are supported
by the 2025 IRP. The Company's preferred portfolio identifies new gas additions of 150 MW in
2029 and 300 MW in 2030.29 The proposed, non-competitive procurement of the 652 MW of
capacity at the Peregrine and South Hills generators exceeds these identified needs.
Although the Company's preferred portfolio from the 2025 IRP identified several
hundred megawatts of new gas-fired generation in the 2029-2030 timeframe, we have previously
filed concerns30 with the Company's inputs and methods used to reach this finding. While the
resources in the Application are linked to needs identified in the 2023 IRP and subsequent RFP,
the Company believes that the 2025 IRP, buttressed by a more recent load and resource
29 2025 IRP,Table 11.1
30 See IPC-E-25-23 Comments of Renewable Northwest and NW Energy Coalition.
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assessment, establishes that these gas resources are needed.31 Therefore, our past and ongoing
concerns with the 2025 IRP analysis are relevant to this proceeding.
As explained further below,we have three concerns regarding the Company's resource
cost assumptions relevant to this docket: understated costs for gas-fired resources, overstated
costs for storage resources, and unrealistic expectations about future costs. Resource cost
assumptions are one of the most critical inputs in long-term capacity expansion("LTCE")
modeling. Optimized LTCE modeling tools, such as Aurora, seek to minimize portfolio costs
while serving system load, meeting the planning reserve margin ("PRM"), and satisfying model
constraints. The LTCE model evaluates the relative costs and capabilities of resources when
selecting the best candidates to build in each year of the study. Because resource assumptions are
so fundamental to optimized resource selection, the Commission should require the use of
timely, robust, and transparent sources.
a. Assumed costs for gas-fired resources are approximately 25% below benchmark
data.
In the 2025 IRP, the Company adopted capital costs of$1,650/kW for a new CCCT and
$1,200/kW for a new SCCT.32 A recently published study found publicly available datasets
underestimate the costs for new CCCT and new simple SCCT resources as the datasets lag the
most current market conditions.33 The study reviewed seven public IRPs and datasets with near-
term capital and fixed costs for combined cycle combustion turbine ("CCCT") and new simple
31 See,e.g.,Hackett Direct at 26.
32 Idaho Power 2025 IRP,Appendix C at 22.(Note,while the Company's Preferred Portfolio builds reciprocating
internal combustion engine("RICE")resources,our cost review is focused on SCCT and CCCT resources.RICE
units were more difficult to fairly compare in our review of the publicly available datasets due to heterogeneity in
technology assumptions and a dearth of cost data compared to SCCT resources.)
33 The New Reality of Power Generation,An Analysis of Increasing Gas Turbine Costs in the U.S.,Gridlab(Sept
2025).https://gridlab.org/gas-turbine-cost-report/.
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cycle combustion turbine ("SCCT")resources.34 31 36 37 31 1141 Cost estimates varied significantly
across sources for combustion turbine-based resources reflecting the dynamic nature of the
combustion turbine market. The study levelized the capital and fixed cost assumptions for all
resources across these public benchmarks and inflated all dollars to a 2026-dollar year to achieve
a fair comparison. The median data point is used for each resource type to avoid unfair
representations from singular high or low references that can skew the average. Idaho Power
does not clearly state the dollars per kilowatt they expect to pay for the proposed gas plants. But
the public data shows expensive and rising costs. Further, this analysis does not consider the
variable cost of dispatching these units nor the fuel supply risk that relies on unbuilt pipelines for
future operations.
b. Assumed costs for storage resources are 15% to 45% above benchmark data.
Levelized cost forecasts for new 4-hour battery storage candidates provide a clearer
picture among the data sources we reviewed. All the sources we reviewed expect new 4-hour
battery storage candidates to range from $l 60 to $180/kW-Yr. The Company's 2025 IRP
forecast costs in the upper end of the distribution,just shy of the 75th percentile. Further, for new
4-hour battery storage resources built in 2030, Idaho Power's assumptions exceed the
Company's own 2023 forecast by 15%, the 2023 Portland General Electric ("PGE") IRP forecast
by 38%, the 2024 NREL Annual Technology Baseline ("ATB")by 21%, and NREL's 2025
34 https://atb.nrel.gov/electricity/2024/about.
35 Assumptions to the Annual Energy Outlook 2025: Electricity Market Module.P 7-8. (April 2025).
36 PacifiCorp 2025 IRP.Volume 1.P 149- 158&P167- 169.
37 Lazard Levelized Cost of Energy+.P34-39.(June 2025).
38 Portland General Electric 2023 CEP/IRP Update.P 96.
39 Avista 2025 IRP.P 190.
40 Mark Shenk,Rush for US gas plants drives up costs,lead times.Reuters(July 21,2025),
https://www.reuters.com/business/energy/rush-us-gas-plants-drives-up-costs-lead-times-2025-07-21/
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Battery Storage Update forecast by 45%. The record in this docket does not specify Idaho
Power's assumed battery storage costs so the Commission cannot compare this option to the
proposed gas plants.
Barring a generational pandemic and subsequent disruption of supply chains and
manufacturing, lithium-ion battery costs have fallen year-over-year.41 The National Renewable
Energy Laboratory's ("NREL") latest 2025 battery storage cost update for storage resources
anticipates a reduction in overnight capital costs of 27%by 203542 while the escalation factors
for the 2025 IRP forecast a reduction of approximately 7%. Company Witness Hacket testifies
that Idaho Power initially identified several battery storage projects as least cost, least risk
resources but then reassessed these quantitative results due to concerns about available tax
incentives and changing ability to meet the capacity need.43 Idaho Power has not demonstrated
that a BESS resource could not meet the capacity needs. And BESS economics have only
improved overtime as cell costs continue to decline at a rapid rate.44As discussed, any other
concerns with "economics" are attributable to IRA tax credits, which were not ultimately
withdrawn for BESS and remain active.45
The Company,by making a resource decision now for service in 2030, is asking the
Commission to essentially adopt a forecast of future resource costs. The Company's forecasts for
resource cost diverge from other publicly available data sources, including industry reports and
41 Lithium-Ion Battery Pack Prices See Largest Drop Since 2017,Falling to$115 per Kilowatt-Hour:Bloomberg
New Energy Finance,(Dec. 10,2024),https:Habout.bnef.com/insights/commodities/lithium-ion-battery-pack-prices-
see-largest-drop-since-2017-falling-to- 115-per-kilowatt-hour-bloombergnef/
42 Wesley Cole et al.,Cost Projections for Utility-Scale Battery Storage: 2025 Update,NREL(June 2025),
https:Hdocs.nrel.gov/docs/fy25osti/9328 I.pdf
43 Hackett,Di at 26.
44 Wesley Cole et al.,Cost Projections for Utility-Scale Battery Storage: 2025 Update,NREL(June 2025),
https:Hdocs.nrel.gov/docs/fy25osti/9328 l.pdf
45 One Big Beautiful Bill Act,Pub.L.No. 119-21,Bill Section 70505 exempting energy storage technology from
early termination under I.R.C. §48E(2025).
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utility IRPs specifically by assuming lower gas costs and higher storage costs. The Company's
assessment of storage over states costs by not incorporating current tax incentives. The
Commission should deny the CPCN until the Company updates resource cost assumptions.
D. Thermal generation carries substantial, material risks which are not adequately
considered by the Company
a. Increased reliance on gas exposes customers to fuel price and supply risks
In addition to these resource cost concerns,we found the Company's evaluation of
substantial, material risk factors associated with thermal generation in the 2025 IRP deficient.
The Company's Application, Testimony, and other information do not complete this picture and
thus the Commission cannot determine if the gas plants are the least risk resources.
Gas is a notoriously volatile commodity. Its price swings due to economic conditions,
weather trends, and industry operations. The chemical itself is explosive and emits air and water
pollutants when burned. And Idaho, while amidst gas pipeline infrastructure, is reliant on
multinational companies to build, maintain, and operate new pipeline capacity to fuel Idaho
Power's proposed plants. Increasing dependence on imported gas supplies exposes Idahoans to
risks of volatile energy bills, decreasing environmental conditions, and risks to fuel supplies
during critical times.
Idaho Power seeks accounting treatment for the capital expenditure to build two new gas
facilities. These plants require fuel to be used and useful, so expected gas supply costs and risks
should be part of the decision to invest capital in a resource. Unfortunately, Idaho Power glosses
over the need for new pipeline capacity and does not supply a gas price forecast in this docket.
This lack of facts makes it difficult for the Commission to point to a record that establishes the
gas plants are least-risk, least-cost resources.
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Gas prices for the 2025 IRP are based on the 2023 U.S. Energy Information
Administration ("EIA") Annual Energy Outlook("AEO") "Low Oil and Gas Supply." This is the
closest public analysis by Idaho Power available to compare gas plants to other options. The
AEO 2026 Gas Price forecast is between 25 - 50% higher based on various assumptions. The US
Department of Energy points to increasing exports of Canadian Liquified Natural Gas and
increasing demand from data centers as driving up costs for US electricity customers over the
next decade. This councils against expending capital on a resource with a rising and volatile fuel
cost.
Of course, fuel prices are volatile, lower prices could benefit customers while higher
prices could cause additional harm. In the 2025 IRP, the Company's "Low Gas Price" and"High
Gas & Carbon Prices"portfolios result in the lowest($10.1613) and the highest($14.16B)total
portfolio costs, respectively. The costs of these gas price sensitivities, relative to the preferred
portfolio ($10.96B), suggest the Company's capacity to reduce costs under a low gas future (-
$0.80B) is significantly smaller than the increased cost risk(+$3.20B) that a high gas cost future
presents the system. In other words, customers face a higher risk of expensive gas than potential
for lower prices.
The Company will need to acquire new pipeline capacity fuel additional gas generation
resources. Absent new pipelines, the Company expects to procure additional transportation
capacity via the short-term capacity release market, further jeopardizing the certainty of the
supply and delivered price. Looking ahead, Idaho Power points to the Williams Company's plans
to build additional pipeline capacity from Wyoming into Idaho. But this is just an announcement
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of a potential future project and not a specific permit application or proposal.41 There are many
future steps that must take place before Idaho Power can access new capacity alongside the fully
subscribed northwest gas system. By asking for approval to invest capital in new gas plants,
Idaho Power is asking this Commission to rely upon the future existence of an interstate pipeline
built by a company they do not oversee.
The January 2024 Northwest Cold Weather Event shows the risk of further reliance on
gas generation. During record cold weather, the Northwest region faced near critical energy
conditions due to the combined stress of burning gas for heating and for power generation.
Energy prices skyrocketed and utilities in the region urged customers to conserve. This dual
reliance on a single, at capacity, system places customers at risk of outages and cost spikes
during peak hours - hours the Company cites as the time when these new gas resources are most
necessary. The interdependency between the electric and gas systems increases reliability and
ratepayer risk. Instead of increasing reliance on gas, based on uncertain forecasts and thereby
increasing customer risks, the Commission should deny the Application until the Company
adequately discloses and analyzes the fuel supply and cost risk inherent to new gas plants.
b. The Company omits key reliability considerations for thermal resources.
For thermal resources, assumptions around forced outage rates, derates, loss of fuel, and
other outage types can be adopted to calculate ELCCs and reflect the reality that their reliable
capacity will be less than nameplate. The Company's reliance on ELCC/PRM and EFORd is
limited to assessing the physical reliability- this is important,but not complete. For example,
this metric does not consider operating with frequent daily cycling to integrate variable energy
46 https://www.naturalgasintel.com/news/williams-ceo-says-northwest-northeast-open-for-business-as-natural-gas-
pipeline-proj ects-advance/
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resources, a challenge Idaho Power highlights consistently, that is more stressful than traditional
baseload service and can cause faster performance degradation than implied by historical GADS
data. Moreover, this metric does not fully capture the fuel supply risks from constrained or
disrupted pipelines or competing uses during extreme cold weather events. And the use of a
reliability metric (EFORd) has no bearing on the financial risk to customers from escalating gas
prices. To ensure a least cost and least risk resource selection, Idaho Power must clearly and
comprehensively address the risks of fuel supply curtailments and price volatility.
c. Thermal generation carries substantial regulatory risk
Idahoans, indeed most people, care about clean air and water in their communities. As a
result we see a steady trajectory of increasing requirements to reduce and mitigate pollution from
gas plants. In its Sixth Assessment Synthesis 3 Report(2023), the Intergovernmental Panel on
Climate Change concluded:
Human activities, principally through emissions of greenhouse gases, have unequivocally
caused global warming,with global surface temperature reaching 1.1 degrees C above
1850-1900 in 2011-2020. Global greenhouse gas emissions have continued to
increase...Widespread and rapid changes in the atmosphere, ocean, cryosphere and
biosphere have occurred. Human-caused climate change is already affecting many
weather and climate extremes in every region across the globe. This has led to
widespread adverse impacts and related losses and damages to nature and
people...Continued greenhouse gas emissions will lead to increasing global warming,
with the best estimate of reaching 1.5 degrees C in the near term...Every increment of
global warming will intensify multiple and concurrent hazards...Deep, rapid, and
sustained reductions in greenhouse gas emissions would lead to a discernible slowdown
in global warming within around two decades, and also to discernible changes in
atmospheric composition within a few years.47
47 2023: Summary for Policymakers. In:Climate Change 2023: Synthesis Report.Contribution of Working Groups
1,II and III to the Sixth Assessment Report of the Intergovernmental Panel on Climate Change[Core Writing Team,
H.Lee and J.Romero(eds.)].IPCC,Geneva, Switzerland,pp. 1-34,doi: 10.59327/IPCC/AR6-9789291691647.001,
available at https://www.ipcc.ch/report/ar6/syr/downloads/report/IPCC AR6_SYR SPM.pdf.
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Given the IPCC's demonstration that continued greenhouse gas emissions pose serious risks to
the health and safety of people in every region, many regulatory bodies are requiring mitigation
of greenhouse gas emissions. While the federal pollution rules are in flux; states continue to
enforce Clean Air Act and Clean Water Act requirements to control local pollutants. The overall
trend is towards more protections, especially as people move closer to generation sources. Closer
to home, some states and utilities have adopted specific targets for achieving a clean and
affordable electricity supply. These policies encourage utilities to invest in clean resources to
avoid the well-known costs and risks of gas generation. Idaho Power's proposed gas plants cut
against this clear trend of rising protections for the clean air and water people rely upon.
E. IOUs have a financial incentive for ownership and should be held to competitive
procurement and full regulatory scrutiny of all available resource alternatives
Taken together, the above concerns show the South Hills and Peregrine power plants
were identified outside of a competitive process, exceed the Company's own identified capacity
requirements, and were only supported by the Company's 2025 IRP findings insofar as the
Company did not use industry-standard technology cost inputs and discounted material risks
associated with thermal generation. We also know the Company had received ample bids for
wind, solar, and storage whose combined capacity would have made a large contribution to the
identified need.48 While we acknowledge the Company exercises many best practices and works
diligently to find efficient solutions for supply procurement, it is worth noting that all investor-
owned utilities (IOUs) are incentivized to maximize capital expenditures, and therefore favor
self-build or ownership of generation resources where a reasonable case can be made. We
believe this has motivated creation of the Company's CPCN proposal and for it to commit $19
48 See,e.g.,Hackett Direct at 22.
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million toward the these thermal power plants49 before engaging in a competitive or regulatory
process. The Company's CEO, Lisa Grow, acknowledged the preference for ownership in a
recent investor call:s0
I mean we always want to go in with some company-owned assets or projects, and we do.
And historically, we've won about 50% of those. And so we have -- certainly, we have a
desire to own as many of the resources as we can, and we do so in a competitive way.
Given the Company's "desire to own as many of the resources as we can,"we encourage the
Commission to require all of the controls inherent in a fully-vetted IRP and competitive RFP
process, along with rigorous data using known and measurable forecasting tools, when providing
regulatory certainty for a utility to acquire resources.
III. CONCLUSION
Notably Idaho Power does not seek any cost recovery and testifies to available financing
opportunities and accounting methods to track investments in these proposed gas plants. This
clarifies that what Idaho Power seeks today is a regulatory stamp of confidence the Company
will recover these costs in the future. Doing so necessarily commits customers to volatility and
rising costs and risks for fuel supply and price. CPCN approval has been reserved for
circumstances in which the Company can conclusively demonstrate that the resource is the result
of a competitive process, optimally blends of costs and risks for customers, and that regulatory
support is required to acquire reasonable financing. Here, the Company cannot demonstrate that
was the case.
49 IIPA's Request for Production No. 1-2-Confidential Attachment 2-GEV_Equipment Contract.pdf
50 Transcript of Idaho Power Company Earnings Call„Testimony of Lisa Grow(April 30,2026). Available at
https:Hseekingalpha.com/article/4897064-idacorp-inc-ida-q 1-2026-earnings-call-transcript
IPC-E-26-04 NWEC/RNW Comments
July 31,2026 17

For the reasons stated above, we recommend the Commission deny Idaho Power's
Application for a CPCN for the South Hill and Peregrine gas plants.
Respectfully submitted,
Is/Benjamin J. Otto, ISB #8292 Is/Mike Goetz
NW Energy Coalition& Renewable NW Regulatory Affairs Director
1407 W Cottonwood Court Renewable Northwest
Boise, ID 83702 421 SW Sixth Ave. #975
[phone] Portland, OR 97204
[phone]
/sl&le Unruh
Director, Montana& Idaho Is/Aaron Menenber�
Renewable Northwest Idaho Policy Manager
421 SW Sixth Ave. #975 Renewable Northwest
Portland, OR 97204 421 SW Sixth Ave#975
[phone] Portland, OR 97204
[phone]
IPC-E-26-04 NWEC/RNW Comments
July 31,2026 18

CERTIFICATE OF SERVICE
I hereby certify that on this 31 st day of July 2026, 1 delivered true and correct copies of the
foregoing COMMENTS OF NWEC AND RNW in IPUC Docket No. IPC-E-26-04 to the
following persons according to Rule 61.03 via electronic mail only.
/s/Beniamin J Otto, ISB No 8292
Attorney for NWEC and RNW
Idaho Public Utilities Commission Monica Barros-Sanchez
Commission Secretary
[e-mail]
Idaho Public Utilities Commission Staff
Kelsea E. Ross
Deputy Attorney General
[e-mail]
Idaho Power Company
Donovan E. Walker
Lisa Lance
Timothy Tatum
Connie Aschenbrenner
[e-mail]
[e-mail]
[e-mail]
[e-mail]
Idaho Irrigation Pumpers Association
Eric L. Olsen
Lance Kaufrnan
[e-mail]
[e-mail]
Micron Technology, Inc
Austin Rueschhoff
Thorvald A. Nelson
Richard A. Arnett
Holland&Hart, LLP
[e-mail]
[e-mail]
[e-mail]
[e-mail]
[e-mail]
IPC-E-26-04 NWEC/RNW Comments
July 31,2026 19