20251223Final_Order_No_36885.pdf

Office of the Secretary
Service Date
December 23,2025
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER ) CASE NO. IPC-E-25-33
COMPANY'S ANNUAL COMPLIANCE )
FILING TO UPDATE THE LOAD AND GAS )
FORECAST IN THE INCREMENTAL COST ) ORDER NO. 36885
INTEGRATED RESOURCE PLAN AVOIDED )
COST MODEL )
On October 15, 2025, Idaho Power Company ("Company") filed its Annual Compliance
Filing ("Filing") to update the load forecast, the natural gas forecast, and long-term contract
changes used to determine avoided cost rates for Public Utilities Regulatory Policy Act of 1978
("PURPA") qualifying facilities ("QFs") under the Company's Incremental Cost Integrated
Resource Plan ("ICIRP") avoided cost method. In addition, the Company updated its Peak and
Premium Peak Hours used to determine capacity payments for energy storage QFs. The Company
requested an effective date of January 1, 2026, for these updates.
On November 4, 2025, the Commission issued a Notice of Filing and Notice of Modified
Procedure, establishing deadlines for public comments and for the Company to reply. Commission
Staff("Staff') filed comments to which the Company replied.
Having reviewed the record, the Commission issues this Order approving the Company's
annual update to its load forecast, contract changes, Peak Hours, and Premium Peak Hours as
discussed herein. The Commission declines to adopt the Company's natural gas price forecast and
directs the Company to take additional action described below.
BACKGROUND
Pursuant to PURPA and the Federal Energy Regulatory Commission's ("FERC")
implementing regulations, this Commission has approved the IRP Method to calculate avoided
cost rates for QFs that are above the resource-specific project eligibility cap. QFs that are below
the applicable project eligibility cap may receive published avoided cost rates calculated using the
surrogate avoided resource ("SAR Method"). See Order No. 32697 at 7-8. The avoided cost rate
is the purchase price paid to QFs for the energy, or the energy and capacity, that the QF provides
to the utility. 18 C.F.R. § 292.101(b)(6)(defining "avoided cost"). To ensure that avoided costs
most accurately reflect the utility's marginal cost of energy or capacity, the Commission has
directed utilities to "update fuel price forecasts and load forecasts annually—between IRP filings,"
ORDER NO. 36885 1

and to update the Commission about its "long-term contract commitments because of [their]
potential effect . . . on a utility's load and resource balance." Order No. 32697 at 22.
THE FILING
The Company currently forecasts an average annual load growth for the 20-year period
following September 2024 forward that constitutes an increase from the average annual load
growth forecast that the Commission approved in the Company's 2024 annual update. The
Company states it developed its natural gas forecast using the most recent Henry Hub and Sumas
Basis Annuals from S&P Platts Long-term Forecast, which was published in August 2025. The
Company believes its proposed natural gas forecast is the most accurate and up-to-date reflection
of the inputs to the Company's current avoided costs.
The Company states it has seven non-PURPA, long-term power purchase agreements with
projects that are currently online, Elkhorn Valley Wind (101 megawatts ("MW")), Raft River
Geothermal (13 MW), Neal Hot Springs Geothermal (22 MW), Jackpot Solar (120 MW), Black
Mesa Solar(40 MW), Franklin Solar(100 MW), and Pleasant Valley Solar(200 MW). In addition
to its agreements with non-PURPA projects, the Company has 129 contracts for PURPA QFs
which have a total nameplate capacity of 1,128.58 MW. The Company further represents that it
has one non-PURPA long-term battery services agreement with a battery energy storage system,
the Kuna BESS (150 MW/600 MWh).
The Filing also updates the Peak and Premium Peak Hours used by the Company for the
avoided capacity cost calculations available to energy storage QFs. The Company proposes
transitioning to a Loss of Load Probability("LOLP"), arguing that its more objective and capacity-
based framework offers greater transparency and objectivity than the current method established
in Order No. 34913. The Company conducted separate analyses using LOLP capacity-based
framework exclusively and the existing method exclusively. The results of those analyses
produced different Peak and Premium Peak Hours, which are set forth in the following table:
A Existing Methodology Proposed Update
Summer Peak Hours Jam: 1:00pm through 10:OOpm June 15 to September 15: 3:O0pm to
Auu ust:3:O0pm to 8:O0pm 11:00pm
Summer Premium Peak J*:6:OOpm through 10:OOpm June 15 to September 15:6:00pm to
Hours August: 6:OOpm to 8:OOpm 11:00pm
Winter Peak Hours No winter hours identified November 15 to February 15:S:OOam
to 10:OOam and 4:OOpm to 10:OOpm
Winter Premium Peak November 15 to February 15:&00am
Hours No winter hours identified to 9:OOam and S:OOpm to 8:00 pm
ORDER NO. 36885 2

STAFF COMMENTS
Staff reviewed the Company's load forecast, natural gas price forecast, contract updates,
Peak and Premium Peak Hours, and revised the SAR model to incorporate the June 2027 capacity
deficiency approved in Order No. 36855. This review resulted in Staff recommending approval of
only the Company's load forecast. Instead of approving the Company's other proposals, Staff
recommended adoption of its natural gas forecast,Peak and Premium Peak Hour proposal,updated
SAR model, and the avoided cost rates for new and replacement contracts derived from Staff s
SAR model, all effective January 1, 2026.
I. Load Forecast
Staff compared the load forecast proposed in this case with the one approved in last year's
annual update (Case No. IPC-E-24-40). From 2026 through 2028, reduced load from special
contract customers resulted in a lower proposed load forecast than last year. After 2028, inclusion
of additional special contract customers resulted in the forecast exceeding last year's. Staff found
this variation and the resulting proposed forecast reasonable. Accordingly, Staff recommended
that the Commission approve the Company's proposed load forecast effective January 1, 2026.
II. Natural Gas Price Forecast
Staff compared the Company's proposed August 2025 S&P Platts long-term natural gas
forecast to other available sources. Because ICIRP-based contracts are limited to two years, Staff
focused its review on near-term prices and compared the Company's Henry Hub forecast with
forecasts from cases AVU-E-25-13 and PAC-E-25-19, as well as NYMEX forward prices as of
October 15, 2025. As the Company's near-term prices are materially higher than these
benchmarks, Staff recommended rejection of the Company's gas price forecast.
Staff developed an alternative forecast using the methodology approved in Order Nos.
35344 and 36464. Under this approach, the first three years rely entirely on NYMEX forward
prices published on October 15, the fourth year reflects an average of NYMEX and the Platts
forecast, and the fifth year and beyond rely solely on the Platts forecast. Staff validated its forecast
by comparing it to the same benchmark sources used previously and found it to be consistent,
particularly in the near term. Accordingly, Staff recommended that the Commission approve its
natural gas price forecast effective January 1, 2026.
ORDER NO. 36885 3

III.Contract Changes
Staff reviewed the contract changes since last year's annual update case and believed them
to be correct.
IV.Peak and Premium Peak Hours for Energy Storage QFs
Instead of relying on the approved methodology for determining Peak and Premium Peak
Hours, the Company proposed using the LOLP method. The current methodology identifies Peak
and Premium Peak Hours subjectively by comparing multiple data sources. In contrast,the LOLP
methodology uses the Company's Reliability and Capacity Assessment Tool ("RCAT") model to
calculate the probability of demand exceeding available generation each hour, with Peak and
Premium Peak Hours defined by the highest LOLP values. This methodology is used to calculate
avoided capacity costs in the export credit rate for on-site generation customers and to set Time-
of-Use customer rates. See Case Nos. IPC-E-25-15 and IPC-E-23-11.
Despite considering this more sophisticated and objective approach reasonable, Staff noted
that the Company did not exclude Sundays and holidays in its reporting. Accordingly, Staff
recommended that the Commission reject the Company's Peak and Premium Peak Hours and
adopt Staff s proposal reflected in the following Table No. 2 from Staff s comments:
Table No. 2: Staff Proposed Peal: Hours and Premium Peal: Hours
Summer Peak Hours June 15 to September 15 excluding Sundays and holiday s
3:00 pm to 11:00 pm
Summer Premium Peak Hours June 15 to September 15 excluding Smidal's mid holidai-s
6:00 pm to 11:00 pm
Winter Peak Hours November 15 to February 15 excluding Sundays and holidays:
5:00 am to 10:00 am and 4:00 pm to 10:00 pm
Winter Premium Peak Hours November 15 to February 15 excluding Sundays and holidays:
6:00 am to 9:00 am and 5:00 pm to 8:00 pm
A. Applying Peak Hours and Premium Peak Hours in ICIRP Method
The Company provided an example of applying Peak and Premium Peak Hours in its
ICIRP method, but Staff identified four issues with this method that need resolution. First, the
example did not apply monthly Loss of Load Expectation weights to capacity payments. Second,
it is unclear how rates would be calculated for half-month periods. Third, the benchmarking
timeframe for Peak Hour Capacity Factor may need alignment with the approved Peak and
ORDER NO. 36885 4

Premium Peak Hours or replacement with Effective Load Carrying Capability, as proposed for the
Fossil Gulch wind project. Fourth, the example incorrectly includes QF generation on Sundays
and holidays, which should be excluded. Staff recommended the Company meet with Staff before
entering any new ICIRP-based energy storage QF contracts.
B. Applying Peak Hours and Premium Peak Hours in SAR Model
The existing SAR model treats all Peak Hours the same, and the Company proposed
updating only the total annual Peak Hours. Staff recommended calculating separate avoided
capacity costs for summer and winter to reflect seasonal risk, 83.3% in summer and 16.7% in
winter. Under Staff s method, the Combined Cycle Combustion Turbine Annual Capacity Value
is allocated by season and multiplied by the QF's generation during each season's Peak Hours to
determine seasonal Capacity Payments.
V. Updated SAR Model and Published Rates
Staff updated the SAR model to reflect two key changes. First, Staff incorporated the
recently approved June 2027 capacity deficiency for all QFs from Order No. 36855. Second, Staff
calculated seasonal avoided capacity costs for energy storage QFs. Using its updated SAR model,
Staff generated published avoided cost rates for all technology types. Attachment A to Staff s
comments presents the rates for new contracts. Attachment B provides rates for replacement
contracts. Staff recommended that the Commission approve the updated SAR model and the
published avoided cost rates in Attachments A and B, with an effective date of January 1, 2026.
COMPANY REPLY
I. Load Forecast
The Company supported Staffs recommendation to approve the Company's proposed
load forecast.
II. Natural Gas Forecast
The Company stated that its proposed natural gas forecast ensures that avoided costs are
accurate and consistent with the IRP methodology. The proposed forecast aligns with the 2025
IRP and uses the August 2025 Platts long-term forecast, which the Commission previously
approved as reasonable. See Order No. 35644.
The Company justified relying on Platts because it incorporates real-time market
fundamentals (e.g., supply, demand, pipelines, and storage) producing forecasts that reflect
physical gas markets and align with the Company's trading operations. The Company contrasted
ORDER NO. 36885 5

this with the Intercontinental Exchange's NYMEX prices that reflect future contracts used for
hedging, which do not match the Company's daily physical gas procurement or operational
practices. Accordingly, the Company believes its Platts-based natural gas forecast provides the
most accurate and current reflection of avoided costs.
III.Peak and Premium Peak Hours for Energy Storage QFs
The Company acknowledged its failure to clarify that its proposed Peak and Premium Peak
Hours exclude Sundays and holidays. Because Sundays and holidays are so excluded, there is no
substantive difference between the Company's proposal and Staff s recommendation on this issue.
The Company also agreed that meeting with Staff to coordinate the application of Peak and
Premium Peak Hours in the ICIRP model in future ICIRP-based energy storage QF contract
negotiations would be beneficial.
IV.Updating SAR Model and Published Rates
The Company agreed with Staff s updates to the SAR model and found the published
avoided cost rates reasonable and consistent with Commission orders, with one proposed
modification to improve transparency and usability. Specifically, the Company recommended
incorporating the summer and winter risk split into a different portion of the rate calculation model.
According to the Company, this will enhance the model's usability and ensure that seasonal risk
assumptions are transparent and easily verifiable. The Company included a Microsoft Excel
spreadsheet reflecting this proposed change with its reply comments.
COMMISSION FINDINGS AND DECISION
The Commission has jurisdiction over this matter under Idaho Code§§61-501through 503.
The Commission is empowered to investigate rates, charges, rules, regulations, practices, and
contracts of public utilities and to determine whether they are just, reasonable, preferential,
discriminatory, or in violation of any provision of the law, and to fix the same by order. Idaho
Code §§ 61-502 and -503. Additionally, the Commission has authority under PURPA and FERC
regulations to set avoided costs, to order electric utilities to enter fixed-term obligations for
purchase of energy from QFs, and to implement FERC rules. The Commission may enter any final
order consistent with its authority under Title 61, Idaho Code, and PURPA.
Under this authority,we have reviewed the record, including the Filing, Staffs comments,
and the Company's reply. Although we find the proposed load growth forecast and all contract
changes to be reasonable as filed,we cannot say the same for the Company's proposed natural gas
ORDER NO. 36885 6

price forecast. The near-term prices in the Company's proposed forecast substantially exceed those
identified in Case Nos. AVU-E-25-13 and PAC-E-25-19, as well as NYMEX forward prices as of
October 15, 2025. As contracts negotiated with ICIRP avoided cost methodology are typically
two-year contracts, the accuracy and reliability of near-term price forecasting is critical.
Moreover, this is not the first time a significant discrepancy between the Company's
natural gas forecast and those submitted by Idaho's two other large electric utilities has arisen. The
Company's 2021 natural gas forecast was significantly lower than Avista's and Rocky Mountain
Power's forecasts over the near-term, which is the critical timeframe for two-year PURPA
contracts for QFs. Order No. 35294. The natural gas forecast submitted with the Company's last
load and gas update predicted a significant price spike that no other forecast predicted. See Order
No. 36434. To address this discrepancy, we directed the Company to file a three-year natural gas
forecast using the latest NYMEX forwards prices to determine IRP avoided cost rates for contracts
signed after January 1, 2025,until the Company's next natural gas price forecast annual update.
We direct the Company to use the alternative forecast developed by Staff.We acknowledge
the Company's concern that NYMEX forward prices rely on hedging practices that differ from the
Company's. However, considering the near-term consistency of Staff s forecast with other
benchmark sources used previously, we find it reasonable to direct the Company to use this
forecast. Accordingly, this forecast shall be used to determine avoided cost rates for contracts
signed after January 1, 2026.
Regarding the calculation of Peak and Premium Peak Hours,we find it reasonable to direct
the Company to use the LOLP method going forward.Not only is this method a more sophisticated
and objective way to determine Peak and Premium Peak Hours, it is also consistent with the
methods used to calculate avoided capacity costs in the export credit rate for on-site generation
customers and to set Time-of-Use customer rates. Accordingly, we find the proposed Peak and
Premium Peak Hours identified in Table No.2 described above to be reasonable and approve them
for use.
We find it reasonable to approve Staffs updated SAR model for use with the Company's
proposed modification. Unlike the Company's proposal, Staffs SAR model reflects the recently
approved capacity deficiency period of June 2027 and incorporates seasonal avoided capacity
costs. Additionally, we find it reasonable to adopt the Company's proposed revision to Staff s
SAR model as it will improve the transparency and functionality of the model. Accordingly, we
ORDER NO. 36885 7

further find it reasonable to approve the avoided cost rates based on Staff s model for new contracts
contained in Attachment A to Staffs comments and the avoided cost rates for replacement
contracts set forth in Attachment B to Staff s comments.
ORDER
IT IS HEREBY ORDERED that the Company's annual updates to its energy load forecast
are reasonable and approved, effective as of January 1, 2026.
IT IS FURTHER ORDERED that the Company use the alternative natural gas forecast
developed by Staff for contracts signed after January 1, 2026, until the effective date of the next
natural gas price forecast annual update.
IT IS FURTHER ORDERED that Staffs proposed Peak and Premium Peak Hours used to
calculate and pay capacity payments for energy storage QFs using ICIRP-based avoided cost rates
are approved, as described above.
IT IS FURTHER ORDERED that the Company use the LOLP method described in this
order to calculate Peak and Premium Peak Hours going forward.
IT IS FURTHER ORDERED that Staffs updated SAR model, with the Company's
proposed modification, is approved along with the avoided cost rates for new contracts contained
in Attachment A to Staff s comments and the avoided cost rates for replacement contracts set forth
in Attachment B to Staff s comments that are based on that model.
THIS IS A FINAL ORDER. Any person interested in this Order may petition for
reconsideration within twenty-one (21) days of the service date of this Order about 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. See Idaho Code § 61-626.
ORDER NO. 36885 8

DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho this 23rd day of
December 2025.
G
Gv� _
EDWARD LODGE, PRE ENT
HN R. HAMMOND JR., COMMISSIONER
DAYN HARDI , COM SSIONER
ATTEST:
?44- A
ra Calderon Robles
Commission Secretary
I:\Legal\ELECTRIC\IPC-E-25-33_L and G\orders\IPCE2533_final_at.docx
ORDER NO. 36885 9