20260217Final_Order_No_36937.pdf

Office of the Secretary
Service Date
February 17,2026
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER ) CASE NO. IPC-E-25-23
COMPANY'S 2025 INTEGRATED )
RESOURCE PLAN ) ORDER NO. 36937
On June 27, 2025, Idaho Power Company ("Company") applied to the Idaho Public
Utilities Commission ("Commission") requesting that the Commission issue an order
acknowledging the Company's 2025 Integrated Resource Plan("IRP") ("Application").
On August 11, 2025, the Commission issued a Notice of Application and Notice of
Intervention Deadline. Order No. 36706. The Commission granted intervention to Micron
Technology,Inc.,Idaho Irrigation Pumpers Association("IIPA"),Northwest Energy Coalition and
Renewable Northwest ("NWEC/RNW"), and Renewable Energy Coalition ("REC"). Order Nos.
36717, 36740, 36751, and 36758.
On October 6, 2025, the Commission issued a Notice of Modified Procedure establishing
comment deadlines. Order No. 36786. Commission Staff("Staff'), IIPA, and NWEC/RNW filed
comments. The Commission also received three public comments. The Company filed reply
comments.
On December 23, 2025, IIPA filed an Application for Intervenor Funding in the amount of
$16,688.29.
Based on our review of the record,we now issue this Order acknowledging the Company's
2025 IRP, as described herein, and granting IIPA's Application for Intervenor Funding.
THE APPLICATION
The Company stated that its 2025 IRP represents a comprehensive analysis of the optimal
mix of both demand- and supply-side resources available to reliably serve customer demand and
flexible capacity needs from 2026 to 2045. Application at 1-2. According to the Company, it used
Energy Exemplar's Aurora Long-Term Capacity Expansion ("LTCE") modeling tool to develop
portfolios that are least-cost, least-risk for a variety of alternative future scenarios.Id. at 2.
The Company had four primary goals for its 2025 IRP.Id. at 4.Firstly,the Company sought
to identify sufficient resources to meet the anticipated growing demand for energy within the
Company's service area throughout the 2026-2045 planning period. Id. Secondly, the Company
ORDER NO. 36937 1

wanted to ensure its Preferred Portfolio reasonably balanced cost and risk, while adhering to
relevant environmental regulations. Id. Next, the Company sought balanced consideration of
supply-side resources, demand-side measures, and transmission resources. Id. Finally, the
Company sought to meaningfully engage the public in the planning process.Id.
According to the Company, two notable trends emerged in the 2025 IRP: (1) the essential
need for added transmission and flexible resources and (2) the unpredictability of additional load
growth stemming from heightened uncertainty surrounding state and federal policy. Id. at 9.
The Company identified key branches of the 2025 IRP to evaluate in additional detail, and
the Company required the model to build portfolios both with and without each branch.Id. at 1I-
12. The Company stated that the most impactful contingency scenario analyzed under the 2025
IRP is the potential repeal of the 2024-revised Environmental Protection Agency Rule I I I(d)
regarding carbon emissions for existing and new resources. Id.
In advance of finalizing the 2025 IRP, the Company held four technical workshops to
address Staffs concerns regarding the 2023 IRP.Id. at 14. The Company believed the workshops
successfully resolved Staffs previous concerns, including: "(1) future resource costs and Aurora
resource selection; (2) Aurora resource selection and Aurora dispatch; (3) interconnection costs,
REC price forecasts, and load percentile methodology; and(4) the timing of highest risk."Id.
The Company used its analysis to select a Preferred Portfolio,which included a mixture of
generation resources, energy storage systems, and transmission. Id. at 12. According to the
Company,the Preferred Portfolio is the least-cost,least-risk option that balances the need for clean,
low-cost resources without compromising system reliability. Id. The Company further stated that
its Preferred Portfolio adds "1,445 [megawatts ("MW")] of solar, 885 MW of storage (4-hour
batteries, as well as 50 MW of long duration 100-hour storage), 700 MW of wind, 550 MW of
new gas,344 MW of incremental energy efficiency,and 20 MW of incremental demand response."
Id. at 3. Additionally, the Company represented that the Preferred Portfolio involves converting
multiple coal-fired generation units, currently representing 484 MW, to natural gas, adding a total
of 611 MW of natural gas through 2045.Id. The Company stated that the Preferred Portfolio adds
a total of 4,071 MW of incremental resource capacity over the 20-year planning period, including
the Boardman-to-Hemingway (`B2H") transmission line as of December 2027; the Southwest
Intertie Project-North transmission line as of November 2028; and the Midpoint—Hemingway#2
500 kilovolt with the first phase in 2028 and the second phase in 2030. Id.
ORDER NO. 36937 2

The 2025 IRP includes the Company's Near-Term Action Plan ("NTAP"), which reflects
the Preferred Portfolio's near-term actionable items. Id. at 12. According to the Company, the
NTAP is critical to position the Company to provide reliable and economic service to its customers.
Id.
STAFF COMMENTS AND COMPANY REPLY
1. Staff Comments
Staff recommended that the Commission acknowledge the Company's 2025 IRP and
agreed that the Company's 2025 IRP meets the requirements of Commission Order Nos. 22299
and 25260. Staff Comments at 2, 14. Staff believed the Company's 2025 IRP satisfied Commission
directives requiring electric utilities to (1) submit a biennial IRP considering existing resources,
load forecasts,and future resources necessary to reliably serve the future load,and(2)factor public
participation into the development of the plan. Id.; Commission Order Nos. 22299, 25260.
Additionally, Staff supported the Company's selection of its Preferred Portfolio.' Staff Comments
at 6-9, 14. However, Staff did not believe it is appropriate or necessary for the Commission to
acknowledge the second sub-list("2025 IRP Decisions for Acknowledgement") of the Company's
NTAP, containing Company actions that have yet to be the subject of a separately filed case.Id. at
9-10. Staff also had numerous suggestions for the Company to consider for the next IRP.Id. at 3.
Staff recommended improvements to the Company's levelized cost of capacity("LCOC")
calculations, which Staff characterized as a fundamental input to the LTCE model. Id. Staff
suggested the Company provide rationale for the overnight plant capital it uses for each resource.
Id. Staff commended the Company's new approach of assigning a standard value to
interconnection capital estimates and recommended the Company continue using this approach.
Id. Staff also encouraged the Company to include a detailed discussion of resources requiring a
capacity factor applied to the LCOC and the annual capacity factor values used for each resource
that requires one in the next IRP. Id. at 4, 14. Lastly regarding LCOC calculations, Staff
recommended the Company simplify and standardize the application of escalation factors. Id. at
4.
' Staff noted that Commission acknowledgement of the Company's 2025 IRP would not confer a prudence
determination on resources included in the Preferred Portfolio and that future prudency determinations would depend
on an evaluation of the Company's selection of resources based on conditions at the time of acquisition. Staff
Comments at 2,9.
ORDER NO. 36937 3

Staff also suggested the Company's model constraints for new transmission lines may not
sufficiently account for project delays. Id. at 5-6. According to Staff, transmission construction
projects are particularly susceptible to delays. Id. at 6. Staff recommended the Company build
delay into the modeled commercial operation date ("COD") for new transmission resources. Id.
Staff proposed the Company accomplish this by: (1) adding up to 12 months to the modeled COD
for projects facing unresolved permitting and/or right-of-way issues, or (2) modeling delays as a
risk variable that would inform least-cost contingencies.Id.
Staff recognized the Company is facing challenges related to large load growth beginning
in 2026 and continuing through at least 2031. Id. at 10. Staff encouraged the Company to engage
the Commission when there is tension between the Company's obligation to serve new large loads
and its obligation to provide fair,just, and reasonable rates prior to taking action that could limit
the available options. Id.
Though Staff believed the Preferred Portfolio's Energy Efficiency ("EE") and Demand
Response ("DR") measure selections and supporting methodology were generally reasonable,
Staff suggested the Company provide additional details in future IRPs regarding its selection of
EE measures. Id. at 11. Staff was particularly concerned with the Aurora model's selection of EE
measures that were not expected to be cost-effective. Id.
According to Staff, the Public Utility Regulatory Policies Act ("PURPA") new
development rates and replacement rates, which the Company used as part of its baseline
assumptions regardless of where projects are located, does not sufficiently account for policy
differences among the Company's service territories. Id. at 13. To more accurately reflect actual
circumstances in baseline assumptions, Staff recommended the Company: (1) develop Idaho's
PURPA new development and replacement rates separately using Idaho-specific data; (2)
separately develop Idaho's PURPA new development and replacement rates for projects that use
the Surrogate Avoided Resource ("SAR")method and for those that use the Incremental Cost IRP
("ICIRP") method; and (3) contact expiring Idaho projects to gain understanding of project
renewal intentions, when the empirical data for determining replacement rates is insufficient or
unavailable.Id.
Staff encouraged the Company to further explain the calibration process between the LTCE
and the Reliability and Capacity Assessment Tool ("RCAT") models in its next IRP. Id. at 14.
Specifically, Staff believed the Company should provide additional clarity regarding the
ORDER NO. 36937 4

adjustments to the seasonal Planning Reserve Margin ("PRM") and the Effective Load Carrying
Capability (`ELCC") curve when the LTCE-developed portfolio results in a capacity shortfall in
the RCAT model. Id.
Finally, Staff recommended the Company explore incorporating the Westen Energy
Imbalance Market's flexible ramping requirement into the next IRP.According to Staff,the Aurora
model does not capture sub-hourly inputs, and incorporating the flexible ramping requirement
would help ensure the Company meets various reserve needs. Id.
2. Company Reply to Staff
The Company did not object to Staff s position that Commission acknowledgement of
certain items included in the NTAP is not appropriate or necessary where separate filings regarding
the same item already exist. Company Reply Comments at 4.
The Company supported Staffs recommendations that the next IRP provide rationale for
the overnight plant capital selected for each resource and the annual capacity factor values selected
for each resource that requires one. Id. at 4-5. Though the Company believed its method for
applying escalation factors to LCOC calculations in the 2025 IRP was reasonable and consistent
with industry standards, it agreed to work with Staff and the IRP Advisory Council to explore a
more standardized approach, as Staff recommended.Id. at 5-6.
The Company agreed with Staff that new transmission lines are susceptible to legal and
regulatory delays.Id. at 6. The Company stated that it would update transmission assumption with
material changes in the next IRP and work with Staff and the IRP Advisory Council to improve
transmission assumption.Id.
In anticipation of expected large load growth beginning in 2026, the Company committed
to engaging with the Commission in situations requiring trade-offs between the Company's
obligation to serve customers and its obligation to maintain fair,just, and reasonable rates, as Staff
suggested.Id. at 7.
The Company understood Staffs concern regarding the Aurora model's selection of EE
measures that were not expected to be cost-effective. Though the Company stated the selections
were the lowest cost bundles of measures available,it expressed its willingness to explore whether
making these types of resources available for selection is advisable.Id. at 7-8.
The Company agreed with Staff s recommendations to explore developing Idaho's PURPA
new development and replacement rates separately using Idaho-specific data in recognition of
ORDER NO. 36937 5

differing policy environments among the jurisdictions within the Company's service territory. Id.
at 8-9. The Company stated that differences in contract lengths available to SAR and ICIRP
projects were already factored into such rates in the 2025 IRP but committed to evaluating
additional methodological changes to further capture the differences between SAR and ICIRP
pricing and terms and conditions in the forecast of PURPA generation.Id. at 9. The Company also
agreed to contact expiring Idaho projects to gain understanding of project renewal intentions.Id.
In response to Staff s recommendation that the Company further explain the calibration
process between the LTCE and the RCAT models in its next IRP,the Company stated that it would
provide more detail regarding adjustments related to the seasonal PRM and ELCC curves. Id. at
10.
Finally,the Company represented that the Aurora model already captures sub-hourly inputs
for reserves and flexibility. Id. at 11. The Company stated that it was confident WEIM's flexible
ramping requirements were captured in its modeling.Id.
INTERVENOR COMMENTS AND COMPANY REPLY
1. IIPA Comments
IIPA believed the 2025 IRP demonstrated the Company's understanding of the evolving
western energy markets. IIPA Comments at 1. However,IIPA also believed the Company's NTAP
was flawed in several ways. Id. IIPA recommended that the Commission decline to acknowledge
the 2025 IRP, "or at minimum, the Commission should expressly note the plan's instability and
the substantial risk of cost misallocation" for the following reasons.Id. at 10.
According to IIPA, the 2025 IRP incorrectly attributed reliability and transmission needs
to summer peaks, while failing to identify winter adequacy concerns caused by new load due to
large customers as the true drivers. Id. at 2. IIPA recommended the Commission expressly
acknowledge that capacity and transmission costs are being driven by winter demand large load
customers, not by summer-only customers (such as seasonal irrigators). Id. at 2, 4. IIPA argued
that new, year-round industrial demand eliminates the seasonal headroom that has previously
allowed the Company's system to accommodate irrigation peaks without new infrastructure.Id. at
6. Irrigation load has remained consistent according to IIPA. Id.
Therefore, IIPA asked the Commission to note that new large loads are causal factors in
the Company's need to acquire resources, including the Southwest Intertie Project-North("SWIP-
N"), Gateway West ("GWW"), and Mayfield. Id. at 5. IIPA argued that the record shows that
ORDER NO. 36937 6

Company's new large industrial load requests are the overwhelming factor driving incremental
transmission needs across the Company's system. Id. at 3. IIPA also represented that the NTAP
fails to consider the implications of potentially withdrawn new large industrial load requests,
exposing existing ratepayers to the risk of significant stranded costs. Id. at 3-4.
IIPA also requested"[t]he Commission recognize that the IRP's resource plan is contingent
on infeasible or outdated project assumptions." Id. at 5. According to IIPA, the Jackalope wind
project appears infeasible, and the NTAP fails to address this likely outcome.2 Id. at 3. IIPA also
stated that the Company's pending application for Certificate of Public Convenience and Necessity
("CPCN") for the Bennet Gas Expansion Project in Case No. IPC-E-25-29 uses the 2023 IRP
capacity analysis and makes no reference to the 2025 IRP. Id.
Furthermore, IIPA recommended the Commission expressly state that it has not
acknowledged B2H, GWW, Mayfield, or new generation and storage resources identified in the
2025 IRP's NTAP. Id. at 5. IIPA contended that the Company did not present these major
transmission and generation additions as actionable items.Id. at 3. IIPA believed the Commission
should observe that prior acknowledgements are inapplicable as to new actions described in the
NTAP. Id. at 5.
2. Company Reply to IIPA
The Company believed IIPA raised several issues that are beyond the scope of an IRP filing
and would be more appropriately addressed by a separate proceeding. Company Reply Comments
at 22-23.
The Company disputed IIPA's claim that the 2025 IRP's modeling incorrectly attributed
reliability and transmission needs to summer peaks. Id. at 23. According to the Company, the
available transmission capacity during summer is objectively lower than during non-summer. Id.
According to the Company, neighboring utilities reserve transmission capacity to serve greater
system demands during summer, limiting the Company's ability to import or export energy. Id.
Additionally,the Company stated that warmer conductors and higher demand result in greater line
losses in the summer. Id. The Company also noted that the Preferred Portfolio seasonal LOLE
analysis showed higher summer risk in all years throughout the planning period. Id. at 28.
2 On December 31, 2025, the Commission issued Order No. 36893, in which it granted the Company's petition to
withdraw the Certificate of Public Convenience and Necessity for the Jackalope Wind Project due to permitting delays
and uncertainty concerning federal land use policies.
ORDER NO. 36937 7

In response to IIPA's contention that the 2025 IRP risks stranded costs by failing to
adequately account for the possibility of delayed or failed large industrial loads, the Company
reiterated that its load forecast included only customers that have made a significant binding
investment or have expressed "interest indicating a commitment of the highest probability of
locating within the service area."Id. at 24-25. The Company also argued that,while cost recovery
is not appropriately reviewed during an IRP proceeding, other dockets and the terms of special
contracts serve to mitigate stranded cost risk. Id. at 25.
The Company stated that the NTAP includes the 600 MW Jackalope wind project because
there were no indications that federal permitting changes would pause the project when the 2025
IRP was developed. Id. at 25-26. Contrary to IIPA's position, the Company argued it would be
unreasonable to deem the 2025 IRP as incomplete due to circumstances arising after the planning
period. Id. at 26.
The Company also disputed IIPA's claim that the 2025 IRP is inconsistent with the
Company's request for a CPCN in Case No. IPC-E-25-29. Id. The Company stated that a system
reliability assessment with updated load and resource inputs performed after the 2025 IRP was the
basis for the Company's CPCN request for the Bennett Gas Expansion Project. Id. at 27.
In response to IIPA's concern that transmission projects were not presented as actionable
items in the NTAP,the Company stated that B2H and GWW were included in all scenarios because
they were committed to prior to the 2025 IRP or because of their universal need.Id. The Company
represented that it modeled a "no-SWIP" scenario that was compared to the Preferred Portfolio.
Id. at 28. The Company also disputed IIPA's contention that the need for transmission projects
was attributable to new industrial load. Id. The Company argued the projects support broader
system reliability and capacity. Id.
3. NWEC/RNW Comments
Though NWEC/RNW believed the Company's approach to resource planning incorporated
many best practices, they argued there are areas where the Company's approach should be
improved. NWEC/RNW Comments at 1. Specifically, NWEC/RNW contended the Company's
could implement improvements concerning resource cost assumptions; assessments of thermal
reliability, fuel supply, and price fluctuations;transparency and flexibility for new large loads; and
a thorough evaluation of each portfolio's risks.Id.
ORDER NO. 36937 8

NWEC/RNW had four concerns regarding the Company's resource cost assumptions: (1)
understated gas-fired resource costs; (2) overstated wind costs; (3) overstated storage resource
costs; and (4) unrealistic future costs escalation factors. Id. at 2. First, NWEC/RNW argued that
the Company's cost assumptions for new combined cycle combustion turbines and simple cycle
combustion turbines were approximately 25%below the published benchmark data from a recent
study due to lag behind the current market conditions. Id. at 3. NWEC/RNW then contended that
the Company assumed the highest cost assumption for wind generation of any source they
reviewed, with a 30% premium over the median of all sources surveyed. Id. at 4. Next,
NWEC/RNW stated that the Company's assumed costs for storage resources were 151/o-45%
above the 2023 IRP and the sources they reviewed. Id. at 5. According to NWEC/RNW, the
Company used escalation factors that failed to adequately account for battery storage cost
reductions due to generally accepted technology maturity curves.Id.
NWEC/RNW believed the Company's planning omitted key reliability concerns for
thermal resources and that its reliance on new thermal capacity subjects the system to fuel price
volatility and supply risks. Id. at 6-7. NWEC/RNW maintained that classical reliability metrics
are poorly suited for evaluating thermal resources and that the Company should comprehensively
assess thermal resource reliability, including fuel supply curtailment and price volatility risks. Id.
at 6-7. NWEC/RNW noted that the Company's "Low Gas Price" portfolio and "High Gas &
Carbon Prices"portfolio respectively resulted in the lowest and highest total costs of all portfolios
considered, demonstrating the disproportionate risk introduced by increased reliance on thermal
generation. Id. at 7-8.
NWEC/RNW recommended the Company and the Commission create more transparency
and flexibility for new large load forecasts. Id. at 10. According to NWEC/RNW, the 2025 IRP
does not address the risk of over-procurement and stranded assets associated with unprecedented
growth forecasts.Id. at 10-11. Though the Company represented it is only including new industrial
customers that have made a"significant binding investment" or have indicated"a commitment of
the highest probability,"NWEC/RNW believed the Company should provide further clarification
as to the definition of these terms in the next IRP. Id. at 11. NWEC/RNW also asserted that
increased demand-side flexibility from new large load customers could significantly curtail the
need for additional generation capacity, reducing reliability and planning risks. Id. at 12.
NWEC/RNW believed the Company's data regarding loss of load expectations by hour indicated
ORDER NO. 36937 9

substantial opportunity to shift loads to off-peak hours and referenced other jurisdictions that have
recently announced agreements that will enable DR capabilities in data centers.3 Id.
Finally, NWEC/RNW recommended the Company update its approach to risk assessment
and documentation to enable a full assessment of portfolio options. Id. at 14. NWEC/RNW
suggested the Company's Qualitative Risk Analysis should include clear values to define low,
medium, and high risk, and should be expanded to additional future portfolio sensitivities. Id.
NWEC/RNW suggested the Company's Stochastic Risk Analysis should better quantify each
portfolio's sensitivity to key inputs. Id. NWEC/RNW recommended the Company develop a
portfolio scorecard containing metrics determined through collaboration with the IRP Advisory
Council. Id. at 14-15.
4. Company Reply to NWEC/RNW
The Company disputed NWEC/RNW's contentions regarding the 2025 IRP's resource cost
assumptions. Company Reply Comments at 11. According to the Company, its cost assumption
inputs were "informed by bid- level data from recent competitive solicitations and commercial
discussions and benchmarked against reputable public sources... as well as Idaho Power's own
procurement experience." Id. at 11-12. The Company stated that some of the materials
NWEC/RNW cited to question the validity of cost assumptions used in the 2025 IRP were
published after the assumptions were set and could not have reasonably been considered during
the planning stage. Id. at 12.
The Company also challenged NWEC/RNW's position regarding reliability considerations
for thermal resources and increased reliance on new thermal capacity due to fuel price volatility
and supply risk.Id. at 13. The Company stated that it relied on five-year rolling average published
data regarding forced outage rates for these reliability assumptions.Id. at 13-14. According to the
Company, the historical values account for any degradation resulting from more frequent cycling
and integration, any disruption on pipelines, or extreme cold events. Id. at 14. The Company also
contended that the 2025 IRP sufficiently accounted for risks related to fuel price volatility and
deliverability by adding resource diversity—both in terms of generation type and sourcing for the
Company's natural gas supply.Id. at 14-15. Additionally,the Company represents that it included
3 Specifically, NWEC/RNW identified agreements between Google and Indiana Michigan Power and Tennessee
Valley Authority that were announced in August 2025.
ORDER NO. 36937 10

a wide range of natural gas prices in its stochastic analysis, which supported selection of the
Preferred Portfolio, even when accounting for fuel price volatility. Id. at 15.
In response to NWEC/RNW's recommendation that it consider increased demand-side
flexibility from large loads, the Company stated that it was willing to continue exploring creative
solutions to address unprecedented load growth.Id. at 17.The Company stated specific ratemaking
and tariff design options should be addressed in separate proceedings and not during the IRP filing.
Id. The Company noted that it continues to discuss DR programs and load flexibility with large
load customers while arranging special contracts, pursuant to the Commission approved Schedule
19 for loads in excess of 20 MW.Id. at 17-18. Furthermore, the Company represented that it vets
large load commitments to guard against speculative requests that might result in over-
procurement of resources.Id. at 18.
5. REC Comments
REC had concerns regarding the Company's plan to abandon existing wind and solar
resources. REC Comments at 1. REC argued that the Company's use of a 28%
renewal/replacement rate over the 20-year planning period for wind and solar was neither
reasonable nor accurate.Id. at 2. REC represented that the Company planned to drop 487 MWs of
existing wind capacity over the planning period.Id. REC recommended that the Commission find
the Company's wind and solar methodology is imprudent and order the Company to adjust its
wind and solar renewal methodology in future IRPs. Id.
According to REC, existing facilities typically attempt to avoid transmission costs
associated with selling to a distant utility by continuing to sell to their interconnected utility.Id. at
4.REC stated that 100%of the wind projects it contacted indicated an intent to renew their contract
with the Company. Id. at 6. However, REC believed the Commission's policies regarding
published rates and contract length—which were implemented when the Company had a capacity
surplus—would negatively affect wind and solar renewal rates and that it should reconsider those
policies in separate dockets.Id. at 6-9.
REC also argued that utilizing existing resources provides several benefits over reliance on
more expensive new generation, including avoidance of"permitting risks, fuel risks, tariff risks,
Federal tax credit risks, construction risks, equipment procurement risks,transmission study risks,
and completion schedule risks."Id. at 5.
ORDER NO. 36937 11

6. Company Reply to REC
The Company disagreed with REC's argument that the 2025 IRP modeling included an
unreasonable wind and solar PURPA contract replacement rate.4 Company Reply Comments at
19. According to the Company, it uses data-driven assumptions where available—as directed by
the Commission—and assumes a 75%replacement rate for resources where no existing contracts
have expired—as directed by the Oregon Public Utility Commission. Id. at 19-20. The Company
stated that it continues to use the 75%replacement assumption for expiring contracts based on the
term lengths available in each state.Id. at 20. The Company argued that its experience contradicts
REC's anecdotal representation that 100%of existing wind facilities would enter into replacement
contracts with the Company. Id. Furthermore, the Company contended that its procurement
decisions are based on the most up-to-date information and that if more replacement contracts have
been signed than were previously anticipated,the Company can adjust its procurement efforts.Id.
at 21.
PUBLIC COMMENTS AND COMPANY REPLY
1. City of Boise City ("City")
The City supported the 2025 IRP Preferred Portfolio's addition of solar, wind, and storage
resources and its planned exits from coal-fired generation. City Comments at 1. However,the City
was concerned about the addition of new natural gas capacity. Id. The City encouraged the
Company to further incorporate climate-driven risks into future IRPs. Id.
2. Clean Energy Opportunities for Idaho ("CEO")
CEO, which was part of the Company's 2025 IRP Advisory Council, believed the
Company could make improvements to future IRPs to address new large load growth and the
availability of new resource types. CEO Comments at 1. CEO stated that new solar resources have
changed the cost to serve analysis, noting that energy costs are now lower at mid-day and higher
at night. Id. To take advantage of this change, CEO recommended the Company "ensure that the
portfolio of options modeled reflect the most significant and feasible demand-side opportunities
for minimizing future customer cost increases." Id. at 4. CEO believed these demand-side
measures should include adequate time-of-use pricing incentives for irrigators, commercial,
industrial, and large load customers based on a diurnal cycle focused cost distribution.Id. at 4, 6.
a The Company noted that while REC sometimes used the term"renewal,""replacement"is more accurate,because
even existing resources enter into new contracts. Company Reply Comments at 19.
ORDER NO. 36937 12

3. Douglas James
Mr. James was concerned about the Company's planned investment in storage resources
due to battery life, unreliability, and fire risks. Douglas James Public Comment at 1.
4. Company Reply to Public Comments
Although the Company agreed with several of CEO's positions concerning hourly pricing
and seasonal capacity, it noted that large general and industrial customer pricing structures already
include time-of-use pricing elements and that the 2025 IRP already assessed additional demand-
side management potential. Company Reply Comments at 30. The Company added that its use of
utility-scale batteries has significantly diminished the incremental capacity benefit of additional
load-shifting programs. Id.
In response to the City's recommendation that the Company incorporate climate-driven
risks, such as public safety power shutoff events into future IRPs, the Company stated that such
events have generally occurred internal to the Company's system and not within the scope of
resource adequacy planning. Id. at 31. However, the Company committed to working with
stakeholders to determine how to incorporate mitigation measures that directly affect resource
planning.Id.
IIPA'S APPLICATION FOR INTERVENOR FUNDING
IIPA's application includes an itemized list of expenses totaling $16,688.29including
expert witness fees and legal fees. IIPA Application for Intervenor Funding, Exhibit A. IIPA
argued that these expenses were reasonably incurred given its full participation in the matter,
including during the discovery process and through its preparation of extensive written comments.
Id. at 1.
IIPA argued that the costs it incurred in this case constitute a financial hardship for the
501(c)(5) nonprofit association. Id. at 2. IIPA stated that it represents farming interests in eastern
and central Idaho through voluntary contributions by its members—which have been falling. Id.
IIPA stated that due to its financial constraints, its participation was focused and prudent. Id. at 3.
IIPA also noted that its recommendations—which included suggestions that the
Commission make explicit findings regarding infeasible project assumptions and the drivers of
incremental costs of transmission resources—materially differed from Staff s recommendations.
Id. IIPA represented that the issues addressed through its participation in the case concerned the
Company's general body of customers. Id.
ORDER NO. 36937 13

COMMISSION FINDINGS AND DECISION
1. Company's IRP
The Company is a public utility as defined in Idaho Code §§ 61-119 and -129, and the
Commission has jurisdiction over it and the issues in this case under Title 61 of the Idaho Code,
including Idaho Code § 61-501. Having reviewed the record, the Commission finds that the
Company's 2025 IRP satisfies the requirements in the Commission's prior orders, and the
Commission acknowledges the 2025 IRP. However, the Commission notes that it is not
acknowledging the second list, labeled "2025 IRP Decisions for Acknowledgment," contained in
the Company's NTAP and located on pages 140-141 of the 2025 IRP.
We appreciate the Company's commitment, as expressed in its Reply Comments, to work
collaboratively with Staff and other interested parties to improve the IRP planning process. We
anticipate the Company's next IRP will incorporate much of the feedback from this case.
Particularly, the next IRP should demonstrate that sub-hourly inputs for reserves and flexibility
are captured in the Auroa model. The Commission also expects the Company to use the most
recent and robust data to inform the cost assumptions included in portfolio modeling.Additionally,
we encourage the Company to continue to explore all cost-effective measures designed to reduce
the impact of expected load growth, including a comprehensive review of plausible demand-side
flexibility.
In acknowledging the 2025 IRP, the Commission once again reiterates that an IRP is a working
document that incorporates many assumptions and projections at a specific point in time. An IRP
is a plan, not a blueprint, and by issuing this Order we merely acknowledge the Company's
ongoing planning process, not the conclusions or results reached through that process. The
Commission recognizes the work that goes into designing and creating the IRP. Not just by the
Company but also by the Intervenors, Staff, and the public at large. The IRP process and resulting
IRP is more than just an exercise that results in a case before the Commission. While the
Commission is only acknowledging the IRP, it expects to see more references to how the IRP has
shaped decisions about the future and impacted operations. The Commission is also interested in
how the near-term resource needs identified in this IRP are used and implemented in the future. If
there are situations in which near-term resources become either impossible or uneconomic, the
Commission is interested in knowing why and how that may influence subsequent IRPs.
ORDER NO. 36937 14

The Commission does not approve the 2025 IRP, or any resource acquisition referenced in
it, endorse any particular element in it, opine on the Company's prudence in selecting the 2025
IRP's preferred resource portfolio,nor allow or approve any form of cost recovery.The appropriate
place to determine the prudency of the Company's decisions to follow or not follow the 2025 IRP,
and the validation of predicted performance under the 2025 IRP, is a general rate case or other rate
proceeding where the issue is noticed.
2. IIPA's Application for Intervenor Funding
Commission decisions benefit from robust public input. "It is hereby declared the policy
of this state to encourage participation at all stages of all proceedings before the commission so
that all affected customers receive full and fair representation in those proceedings."Idaho Code
§ 61-617A(1). Recoverable costs can include legal fees, witness fees, transportation, and other
expenses so long as the total funding for all intervening parties does not exceed$40,000.00 in any
proceeding.Idaho Code § 61-617A(2).The Commission must consider the following factors when
deciding whether to award intervenor funding:
(1) That the participation of the intervenor materially contributed to the
Commission's decision;
(2) That the costs of intervention are reasonable in amount and would be a
significant financial hardship for the intervenor;
(3) The recommendation made by the intervenor differs materially from the
testimony and exhibits of the Commission Staff; and
(4) The testimony and participation of the intervenor addressed issues of concern
to the general body of customers.
Id.
To obtain an award of intervenor funding, an intervenor must further comply with
Commission's Rules of Procedure 161-165, IDAPA 31.01.01.161-165. Rule 162 of the
Commission's Rules of Procedure provides the form and content requirements for an application
for intervenor funding. The application must contain: (1)an itemized list of expenses broken down
into categories; (2) a statement of the intervenor's proposed finding or recommendation; (3) a
statement showing that the costs the intervenor wishes to recover are reasonable; (4) a statement
explaining why the costs constitute a significant financial hardship for the intervenor; (5) a
statement showing how the intervenor's proposed finding or recommendation differed materially
from the testimony and exhibits of the Commission Staff; (6) a statement showing how the
intervenor's recommendation or position addressed issues of concern to the general body of utility
ORDER NO. 36937 15

users or customers; and (7) a statement showing the class of customer on whose behalf the
intervenor appeared. IIPA's application comports with the procedural and technical requirements
of the Commission's Rules.
Commission Rule 165.02-.03 requires the payment of awards of intervenor funding to be
made by the utility and is an allowable expense to be recovered from ratepayers in the next general
rate case. IDAPA 31.01.01.165.02-.03.
We find that IIPA's application satisfies the intervenor funding requirements. IIPA
intervened and meaningfully participated in all aspects of the proceeding in a manner that
materially contributed to the Commission's final decision. IIPA's Application for Intervenor
Funding was filed timely and no party objected to IIPA's request. We find the expert witness fees,
legal fees, paralegal fees, and soft costs incurred by IIPA are reasonable in amount for this case,
and that IIPA, as a non-profit organization, would suffer financial hardship if the request was not
approved. Accordingly, we award IIPA its full request of$16,688.29 in intervenor funding which
may be recovered by the Company from its Schedule 24, Irrigation customer class.
ORDER
IT IS HEREBY ORDERED that the Company's 2025 IRP is acknowledged.
IT IS FURTHER ORDERED that IIPA's Application for Intervenor Funding is granted in
the amount of$16,688.29. See Idaho Code § 61-617A(2), IDAPA 31.01.01.165.01. The Company
is ordered to remit said amount to IIPA within twenty-eight (28) days from the date of this Order.
IDAPA 31.01.01.165.02. The Company shall be permitted to recover the cost of this intervenor
funding in its next general rate case from its Schedule 24, Irrigation customer class. See Idaho
Code § 61-617A(3).
THIS IS A FINAL ORDER. Any person interested in this Order may petition for
reconsideration within twenty-one (21) days of the service date upon this Order regarding any
matter decided in this Order. Within seven (7) days after any person has petitioned for
reconsideration, any other person may cross-petition for reconsideration. Idaho Code §§ 61-626.
ORDER NO. 36937 16

DONE by order of the Idaho Public Utilities Commission at Boise, Idaho this 17th day of
February 2026.
EDWARD LODG , PRESIDENT
AL gv- �
J R. HAMMOND JR., COMMISSIONER
DAYN H RDIE, COMMISSIONER
ATTEST:
oni a arri -Sanchez
Commission Secretary
I:\LegalTLECTRICUPC-E-25-23_IWordersUPCE2523_FO jl.docx
ORDER NO. 36937 17