20251211Staff Comments.pdf

RECEIVED
December 11, 2025
ADAM TRIPLETT IDAHO PUBLIC
DEPUTY ATTORNEY GENERAL UTILITIES COMMISSION
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83702
[phone]
IDAHO BAR NO. 10221
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER )
COMPANY'S APPLICATION FOR ) CASE NO. IPC-E-25-31
APPROVAL OR REJECTION OF AN )
ENERGY SALES AGREEMENT WITH )
FOSSIL GULCH WIND PARK,LLC FOR THE ) COMMENTS OF THE
SALE AND PURCHASE OF ELECTRIC ) COMMISSION STAFF
ENERGY FROM THE FOSSIL GULCH WIND )
PARK )
COMMISSION STAFF ("STAFF") OF the Idaho Public Utilities Commission
("Commission"), by and through its attorney of record, Adam Triplett, Deputy Attorney General,
submits the following comments.
BACKGROUND
On September 30, 2025, Idaho Power Company("Company"), applied for approval of an
Energy Sales Agreement ("ESA") with Fossil Gulch Wind Park, LLC ("Seller") for energy
generated by the 10.5-megawatt("MW") Fossil Gulch Wind Park("Facility") in Twin Falls
County, Idaho. The Facility delivered energy to the Company under an agreement dated
September 9, 2004 ("2004 Agreement"), which expired on September 30, 2025.
Since the 2004 Agreement expired before approval of the proposed ESA, the Company
and the Seller entered into an Interim Agreement, under which the Company will buy generation
from the Facility at Surplus Energy Price defined in the ESA for the lapsed contract period from
September 30, 2025,until the service date of the final order issued by the Commission.
STAFF COMMENTS 1 DECEMBER 11, 2025

STAFF ANALYSIS
Staff s review focused on the avoided cost rates, the Maximum Capacity Amount, the
Interim Agreement due to the lapsed contract period, the replacement of the 90/110 rule, shortfall
damages, the definition of Surplus Energy,provisions addressing potential modifications to the
Facility, and Appendix E (Wind Energy Production Forecasting).
Staff recommends that the Commission approve the Interim Agreement, approve the
ESA, and declare that all payments the Company makes to the Seller for purchases of electric
energy generated by the Facility as prudently incurred expenses for ratemaking purposes,
conditioned on the Company and Seller updating the ESA to reflect the following modifications
through a compliance filing:
1. Recalculate avoided cost of energy based on:
a. The AURORA model from the 2025 Integrated Resource Plan ("IRP"), instead of
the AURORA model from the 2023 IRP;
b. Inclusion of all resource changes of high certainty as of September 26, 2025, the
execution date of the ESA; and
c. The Facility's updated generation profile.
2. Recalculate avoided cost of capacity based on:
a. The data from the 2025 IRP, instead of the 2023 IRP; and
b. The Facility's updated generation profile.
3. Address the issue of Maximum Capacity Amount by:
a. Modifying it to 10 MW; or
b. Adopting a bifurcated rate that includes a rate of avoided cost of energy, avoided
cost of capacity, and wind integration charges for hourly generation up to 10
megawatt hours ("MWhs") and a second rate of avoided cost of energy and wind
integration charges without avoided cost of capacity for any hourly generation
above 10 MWhs,until the first capacity deficit date. After that date, a single rate
of avoided cost of energy, avoided cost of capacity, and wind integration charges
will be applied to all generation. If the parties decide to adopt a bifurcated rate,
Staff further recommends that the first capacity deficit date used should start with
the authorized date as of the execution date of the ESA on September 26, 2025,
STAFF COMMENTS 2 DECEMBER 11, 2025

and then be updated to reflect all resource changes of high certainty on the
Company's system as of September 26, 2025.
4. Correct the calculation description in Article 6.4.4.
5. Update the definition of Surplus Energy.
6. Remove the modification language in Appendix B to avoid potential confusion.
7. Correct the error in Appendix E.
Avoided Cost Rates
Since the Facility is above the 100-kW wind eligibility cap set for published avoided cost
rates, the proposed rates are determined under the Company's Incremental Cost Integrated
Resource Plan ("ICIRP") method for qualifying facilities ("QF") exceeding the eligibility cap.
Staff reviewed the proposed rates, which include avoided cost of energy, avoided cost of
capacity, and wind integration charges. Each component is discussed below.
Avoided Cost of Energy
Staff analyzed the proposed avoided cost of energy and recommends that the parties
update avoided cost of energy through a compliance filing based on the most recent IRP filed
with the Commission, all resource changes of high certainty as of September 26, 2025, and the
Facility's updated generation profile.
a. 2025 IRP vs. 2023 IRP
In determining the proposed avoided cost of energy, the Company started with the
AURORA model from the most recently acknowledged IRP (i.e. the 2023 IRP) and then updated
the load forecast and the gas price forecast used in the model with the newer forecasts approved
in the latest annual update case (Case No. IPC-E-24-40). Response to Staff Production Request
No. 4 (e), (f), and(g). However, Staff believes that the parties should have used the AURORA
model from the most recently filed IRP (i.e. the 2025 IRP), instead of the AURORA model from
the most recently acknowledged IRP. Order No. 32697 requires that variables and assumptions
utilized in the IRP methodology remain fixed between IRP filings, except for load forecasts and
fuel price forecasts, which should be updated annually. Order No. 32697 at 22. The Company
filed the 2025 IRP on June 27, 2025, and the parties executed the ESA on September 26, 2025.
STAFF COMMENTS 3 DECEMBER 11, 2025

Staff recommends that the parties use the AURORA model from the 2025 IRP to determine
avoided cost of energy.
b. Resource Changes of High Certainty
Order No. 32697 also states that it is appropriate to consider long-term contract
commitments and expirations/terminations in the ICIRP method. Therefore, the Company has
included contract changes in the ICIRP method on a continuous basis and has reported these
changes in the annual compliance filing occurring on October 15 of each year. However,
resource changes in the Company's system are not always contract based. For example, a
resource can be added to the Company's system through a Certificate of Public Convenience and
Necessity("CPCN"), which allows the Company to own the resource without contracting with
another party. Similarly, a resource can be canceled through a withdrawal of a CPCN without
any contract expirations or terminations. Therefore, Staff recommends that the Company
incorporate all resource changes of high certainty-(i.e. contract-based and non-contract-based) in
the AURORA model to calculate the avoided cost of energy, as of September 26, 2025, the
execution date of the ESA.
Examples of resource changes of high certainty as of September 26, 2025, that have not
been reflected in the AURORA model from the 2025 IRP include the withdrawal of the 600-MW
Jackalope Wind Project, the 80-MW Blacks Creek Project, and the 167-MW Bennett Expansion
Gas Project. Response to Staff Production Request No. 4 (h). The withdrawal of the 600-MW
Jackalope Wind Project was filed on September 19, 2025. The project includes a 300-MW
Power Purchase Agreement("PPA") and a 300-MW wind plant to be owned by the Company
under the CPCN Certificate#559. See Case No. IPC-E-25-28. The 80-MW Blacks Creek
Project is being acquired through a PPA executed on August 8, 2025. See Case No. IPC-E-25-
27. The Company filed a CPCN for the 167-MW Bennett Gas Expansion Project on September
19, 2025. See Case No. IPC-E-25-29. Although these resource changes have not been approved
by the Commission by the time Staff is producing the comments, Staff believes these resource
changes are of high certainty and should be added to the AURORA model from the 2025 IRP.1
1 For determining first capacity deficiency periods,the Commission allowed executed contracts where pre-approval
is unnecessary to be included in the Load and Resource Balance. Order No.35834 at 9. Recently,the Commission
allowed Boise Bench and Hemingway Expansion battery storage facilities,which already received approval of their
CPCN,to be included in the analysis of determining the first capacity deficiency period. However,the Commission
further stated that it will evaluate inputs to the capacity deficiency analysis on a case-by-case basis moving forward.
Order No. 36855 at 4.
STAFF COMMENTS 4 DECEMBER 11, 2025

c. The Facility's Updated Generation Profile
The Facility's generation profile is used to calculate avoided cost of energy. Response to
Staff Production Request No. 4 (b). The proposed avoided cost of energy is based on a
generation profile with a total annual generation amount of 25,464 MWhs. Response to Staff
Production Request No. 4 (c). However, after the avoided cost of energy was calculated, the new
ownership group updated the Facility's generation profile with an updated total annual
generation amount of 24,072 MWhs. Supplemental Response to Staff Production Request No. 3.
Although the parties updated the Initial Year Monthly Net Energy Amounts in the ESA based on
the updated generation profile, the proposed avoided cost of energy in the ESA was not updated.
Staff recommends that the parties update the avoided cost of energy based on the Facility's
updated generation profile so that accuracy in pricing and consistency within the ESA are
achieved.
Avoided Cost of Capacity
The ESA proposes immediate capacity payments, and Staff believes this treatment is
reasonable. The ESA also proposes using Effective Load Carrying Capability ("ELCC") to
determine the Facility's capacity contribution. Staff believes this method is reasonable.
However, Staff identified two issues in the proposed avoided cost of capacity. Staff recommends
that the parties address them through a compliance filing by using the data from the most recent
IRP filed with the Commission and the Facility's updated generation profile.
a. Immediate Capacity Payments
During the contract term of the 2004 Agreement, the Company has acquired significant
amounts of capacity to meet its capacity needs. For example, the Company has acquired
resources in 2023,2 2024,3 and 20254 to address the system's capacity deficiency in these years.
Staff believes that the Facility has contributed to meeting the Company's need for capacity and
should be granted immediate capacity payments, instead of waiting until the first capacity deficit
year.
2 Case No.IPC-E-22-13.
3 Case Nos.IPC-E-23-05 and IPC-E-23-20.
4 Case No.IPC-E-23-20.
STAFF COMMENTS 5 DECEMBER 11, 2025

Additionally, the Commission expressed that lack of continuous operation of a plant
could affect capacity payments. Order Nos. 33357, 34692, 34887, and 35303. Since this
Facility has continuously operated after September 30, 2025 (Response to Staff Production
Request No. 1), the expiration date of the 2004 Agreement, Staff believes that the Facility should
be granted immediate capacity payments.
b. ELCC
The currently approved ICIRP method determines a project's capacity contribution by
comparing its performance against the performance of a Company's benchmark resource during
the timeframe of 3:00 pm to 7:00 pm in July. However, the proposed capacity contribution of
this Facility is not calculated by this method, and is instead based on the Facility's ELCC value.
The new method first calculates the perfect generation capacity required to achieve a loss
of load expectation of 0.1 event-days per year. Then, the Facility is added to the system, and the
perfect generation capacity required to achieve the same reliability target is calculated again.
The ELCC value of the Facility is equal to the difference between the two perfect generation
capacity sizes divided by the Facility's nameplate. Supplemental Response to Staff Production
Request No. 3.
Compared to the currently approved method that only measures a resource's performance
during a few selected hours, the ELCC method is an improved method that considers the overall
system reliability across all hours within a calendar year. This method has been used by the
Company in its IRPs and resource procurement processes. Supplemental Response to Staff
Production Request No. 3. Therefore, Staff believes the new ELCC method is reasonable.
c. 2025 IRP vs. 2023 IRP
The data used in determining the proposed avoided cost of capacity comes from the most
recently acknowledged IRP (i.e. the 2023 IRP), such as the inflation rate, the general operation
and maintenance ("O&M") escalation rate, and the cost of capital and the fixed O&M cost for a
Simple Cycle Combustion Turbine plant. Supplemental Response to Staff Production Request
No. 3. Staff believes that the parties should have used the data from the most recently filed IRP
(i.e. the 2025 IRP), instead of the most recently acknowledged IRP. Order No. 32697 requires
that variables and assumptions utilized in the IRP methodology remain fixed between IRP
filings, except for load forecasts and fuel price forecasts, which should be updated annually.
Order No. 32697 at 22. The Company filed the 2025 IRP on June 27, 2025, and the parties
STAFF COMMENTS 6 DECEMBER 11, 2025

executed the ESA on September 26, 2025. Staff recommends that the parties use the data from
the 2025 IRP to determine avoided cost of capacity.
d. The Facility's Updated Generation Profile
The Facility's generation profile is used to calculate avoided cost of capacity. Response
to Staff Production Request No. 4 (b). The proposed avoided cost of capacity is based on a
generation profile with a total annual generation amount of 25,464 MWhs. Supplemental
Response to Staff Production Request No. 3. However, after the avoided cost of capacity was
calculated, the new ownership group updated the Facility's generation profile with an updated
total annual generation amount of 24,072 MWhs. Supplemental Response to Staff Production
Request No. 3. Although the parties updated the Initial Year Monthly Net Energy Amounts in
the ESA based on the updated generation profile, the proposed avoided cost of capacity in the
ESA was not updated. Staff recommends that the parties update the avoided cost of capacity
based on the Facility's updated generation profile so that accuracy in pricing and consistency
within the ESA are achieved.
Wind Integration Charges
This 10.5-MW Facility is the first wind project after the new Schedule 87, Intermittent
Generation Integration Charges, was approved in Order No. 36679. Therefore, it should be
charged at the rates for the first 100-MW block of capacity. Staff verified that the proposed wind
integration charges in the ESA are correct.
Maximum Capacity Amount
Although the Facility has the same nameplate capacity size of 10.5 MW in the ESA as it
is in the 2004 Agreement, the Maximum Capacity Amount has increased from 10 MW in the
2004 Agreement to 10.5 MW in the ESA.
When a proposed capacity size is greater than an original capacity size, the Commission
has previously allowed two options. First, the parties can modify the proposed Maximum
Capacity Amount to match the original size. Order No. 35296. Or alternatively, the parties can
adopt a bifurcated rate structure: one rate that includes both avoided cost of energy and avoided
cost of capacity for all generation up to the original size and a second rate that only includes the
avoided cost of energy for the capacity exceeding the original size until the first capacity deficit
STAFF COMMENTS 7 DECEMBER 11, 2025

date. See e.g. Order Nos. 34956, 35262, and 35223. After that date, a single rate that includes
both avoided cost of energy and avoided cost of capacity will be applied to all generation.
For this wind Facility, a bifurcated rate will include a rate of avoided cost of energy,
avoided cost of capacity, and wind integration charges for hourly generation up to 10 MWhs and
a second rate of avoided cost of energy and wind integration charges without avoided cost of
capacity for any hourly generation above 10 MWhs, until the first capacity deficit date. After
that date, a single rate of avoided cost of energy, avoided cost of capacity, and wind integration
charges will be applied to all generation.
If the parties desire to adopt a bifurcated rate, the first capacity deficit date should be
determined as follows: First, the authorized first capacity deficit date as of September 26, 2025,
the execution date of the ESA, which is June 2026 from Case No. IPC-E-23-27. Order No.
36226. Second, unlike the Surrogate Avoided Resource ("SAR") model that uses a fixed first
capacity deficit date, the ICIRP method allows the authorized first capacity deficit date to be
updated. Order No. 33933 in Case No. IPC-E-17-12 states that:
We now clarify that under the IRP method of calculating avoided cost rates,
consistent with Order No. 33357,utilities may continue to use a queue to track the
order in which QF projects have entered negotiations with the utility and to consider
the queue in the calculation of incremental pricing. As a result, the capacity
deficiency date for a particular project under the IRP method may be later than the
July 2026 date identified in the Company's IRP if that project enters the queue after
other QFs. On the other hand, it may be earlier if earlier-queued QFs terminate
their projects or otherwise drop out of the queue. For published rates under the
Surrogate Avoided Resource (SAR) method, the capacity deficiency date is fixed
as the date approved in Order No. 33898—July 2026.
As stated above, Staff believes all resource changes (i.e. PPAs, Company-owned
resources, etc.) of high certainty on the Company's system should be included when updating the
capacity deficiency date under the ICIRP method, not just the QF changes in the queue.
Therefore, Staff recommends that if the parties desire to adopt a bifurcated rate, the first capacity
deficit date should start with the authorized date as of the execution date of the ESA on
September 26, 2025, and then be updated to reflect all resource changes of high certainty as of
September 26, 2025.
STAFF COMMENTS 8 DECEMBER 11, 2025

Interim Agreement
The 2004 Agreement was going to expire on September 30, 2025. Due to the Seller's
delay, the parties did not execute the ESA until September 26, 2025. Application at 4 and 11.
This resulted in a lapsed contract period between the expiration of the 2004 Agreement and the
approval of the ESA. In order to continue generation during the lapsed contract period, the
parties entered into an Interim Agreement, where the Facility's energy will be paid at the Surplus
Energy Price during the lapsed contract period"subject to any true-up, adjustment, or rejection
of terms and provisions, or the contract itself,by the Commission." Application at 12.
Surplus Energy Price is defined as "the current month's Market Energy Reference Price
or Light Load Purchase Price, whichever is lower." ESA at 27. In similar situations in the past,
the Commission has allowed higher prices than the proposed Surplus Energy Price. For
example, in Case Nos. IPC-E-24-09 and IPC-E-21-08, the interim price used was based on "the
current month's Market Energy Reference Price or the applicable All Hours Energy Price,
whichever is lower." Therefore, Staff believes the proposed Surplus Energy Price is acceptable.
Replacement of 90/110 Rule
Order No. 29632 states that:
[i]t is the Commission's belief that a legally enforceable obligation translates into
reciprocal contractual obligations for both parties, a quid pro quo. It is not just a
lock-in of avoided cost rates but is also an obligation to deliver...For a QF it
translates into an obligation or commitment to deliver its monthly estimated
production. Idaho Power proposes that this delivery of committed energy fall
within a 90/110 band...We find 90/110 to be reasonable.
Therefore, QFs' contracts include a 90/110 rule as a provision. However, Order No. 30488
allowed wind QFs to replace the 90/110 rule with Mechanical Availability Guarantee ("MAG"),
wind forecasting fees, and wind integration charges. Since the ESA contains these three
elements, Staff believes it is acceptable to not include the 90/110 rule.
Shortfall Damages
Under the MAG, the Facility shall achieve a minimum monthly mechanical availability
of 85%, meaning the Facility's monthly Net Energy needs to exceed 85% of the Facility's
Calculated Net Energy Amount for the month. ESA at 8 and 25. If the Facility does not meet
STAFF COMMENTS 9 DECEMBER 11, 2025

the 85%threshold, shortfall damages will be incurred. ESA at 8. However, Article 6.4.4 in the
ESA incorrectly describes how damages should be calculated: "The month's Calculated Net
Energy Amount minus the month's actual Net Energy delivers multiplied by the Availability
Shortfall Price." (Emphasis added). Staff believes the shortfall damages should be calculated
based on 85% of the Calculated Net Energy Amount, instead of 100% of the Calculated Net
Energy Amount. Therefore, Staff recommends that the parties update the ESA through a
compliance to correct the calculation description in Article 6.4.4.5
Definition of Surplus Energy
The ESA defines Surplus Energy as follows:
(1) All Net Energy produced by the Seller's Facility and delivered by the Facility
to the Idaho Power electrical system that exceeds the Nameplate Capacity of the
Facility. Deliveries above the Facility's Nameplate Capacity solely for the purpose
of accommodating hourly scheduling in whole MWs by a third-party transmission
provider shall not be considered Surplus Energy as described within this paragraph
1.42 item 1 or (2) All Net Energy produced by the Seller's Facility and delivered
by the Facility to the Idaho Power electrical system prior to the Operation Date.
ESA at 12.
Subsequently, the Company explained that Surplus Energy is intended to only address
Net Energy produced prior to the Operation Date, which is Item 2, not Item 1. The inclusion of
Item 1 in the definition was an error. Response to Staff Production Request No. 6. Staff
recommends that the parties update the ESA through a compliance filing to update the definition
of Surplus Energy by removing Item 1.6
Provisions Addressing Potential Modifications to Facility
There are two places in the ESA that address potential modifications to the Facility:
Article 23 and Appendix B. Staff believes that Article 23 has comprehensively addressed
potential modifications to the Facility and the language in the article complies with Order No.
35705. Staff also believes that the modification language in Appendix B is redundant and could
5 The Company is amenable to correcting the calculation description in Article 6.4.4. Response to Staff Production
Request No. 7.
6 The Company is amenable to removing Item 1 from the definition of Surplus Energy. Response to Staff
Production Request No. 6.
STAFF COMMENTS 10 DECEMBER 11, 2025

cause potential confusion. Staff recommends that the parties update the ESA through a
compliance filing to remove the modification language in Appendix B.7
Appendix E (Wind Energy Production Forecasting)
Appendix E states that "Idaho Power will deduct the Facility's calculated share of the
Wind Energy Production Forecasting costs specified in item d each month..." However, "item
d"does not exist. It should have been"item 4". Response to Staff Production Request No. 12
(a). Staff recommends that the parties update the ESA through a compliance filing to correct this
error in Appendix E.8
STAFF RECOMMENDATION
Staff recommends that the Commission approve the Interim Agreement, approve the
ESA, and declare that all payments the Company makes to the Seller for purchases of electric
energy generated by the Facility as prudently incurred expenses for ratemaking purposes,
conditioned on the Company and Seller updating the ESA to reflect the following modifications
through a compliance filing:
1. Recalculate avoided cost of energy based on:
a. The AURORA model from the 2025 IRP, instead of the AURORA model from
the 2023 IRP;
b. Inclusion of all resource changes of high certainty as of September 26, 2025, the
execution date of the ESA; and
c. The Facility's updated generation profile.
2. Recalculate avoided cost of capacity based on:
a. The data from the 2025 IRP, instead of the 2023 IRP; and
b. The Facility's updated generation profile.
3. Address the issue of Maximum Capacity Amount by:
a. Modifying it to 10 MW; or
The Company is amenable to removing the modification language in Appendix B to avoid potential confusion.
Response to Staff Production Request No.9.
8 The Company is amenable to correcting the error in Appendix E. Response to Staff Production Request No. 12
(a).
STAFF COMMENTS 11 DECEMBER 11, 2025

b. Adopting a bifurcated rate that includes a rate of avoided cost of energy, avoided
cost of capacity, and wind integration charges for hourly generation up to 10
MWhs and a second rate of avoided cost of energy and wind integration charges
without avoided cost of capacity for any hourly generation above 10 MWhs, until
the first capacity deficit date. After that date, a single rate of avoided cost of
energy, avoided cost of capacity, and wind integration charges will be applied to
all generation. If the parties decide to adopt a bifurcated rate, Staff further
recommends that the first capacity deficit date used should start with the
authorized date as of the execution date of the ESA on September 26, 2025, and
then be updated to reflect all resource changes of high certainty on the Company's
system as of September 26, 2025.
4. Correct the calculation description in Article 6.4.4.
5. Update the definition of Surplus Energy.
6. Remove the modification language in Appendix B to avoid potential confusion.
7. Correct the error in Appendix E.
Respectfully submitted this 11 th day of December 2025.
Adam Triplett
Deputy Attorney General
Technical Staff. Yao Yin
1:\Utility\UMISC\COMMENTS\IPC-E-25-31 Comments.doex
STAFF COMMENTS 12 DECEMBER 11, 2025

CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 11TH DAY OF DECEMBER 2025,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN CASE
NO. IPC-E-25-31, BY E-MAILING A COPY THEREOF TO THE FOLLOWING:
Idaho Power Company:
DONOVAN E. WALKER ENERGY CONTRACTS
LISA C. LANCE 1221 WEST IDAHO STREET (83702)
TIMOTHY E. TATUM PO BOX 70
IDAHO POWER COMPANY BOISE ID 83707
1221 WEST IDAHO STREET (83702) E-MAIL:
PO BOX 70 ee contracts c%idahc� er.conz
BOISE ID 83707-0070
E-MAIL:
dwalker�'Lt>.,i d ahoyower.co.m.
llance{u, dqhopom% com
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PATRICIA JORDA , SECRETARY
CERTIFICATE OF SERVICE