20240415Application.pdf

MEGAN GOICOECHEA ALLEN
Corporate Counsel
[e-mail]
April 15, 2024
Monica Barrios-Sanchez, Secretary
Idaho Public Utilities Commission
11331 W. Chinden Blvd., Bldg 8,
Suite 201-A (83714)
PO Box 83720
Boise, Idaho 83720-0074
Re: Case No. IPC-E-24-17
Application of Idaho Power Company for Authority to Implement Power Cost
Adjustment (“PCA”) Rates for Electric Service from June 1, 2024, through May
31, 2025
Dear Ms. Barrios-Sanchez:
Attached for electronic filing is Idaho Power Company’s Application and Direct
Testimony of Jessica G. Brady filed in support of the Application.
Attachment Nos. 3 and 6 to the Application and Exhibit Nos. 4 and 5 to the Direct
Testimony of Jessica G. Brady contain confidential information and will be provided
separately via an encrypted email to the parties who sign the Protective Agreement. A
Word version of the testimony will also be sent in a separate email for the convenience
of the Reporter.
Accompanying this filing is the Company’s Press Release, Customer Notice, and
Direct Mail Postcard.
If you have any questions about the attached documents, please do not hesitate
to contact me.
Sincerely,
Megan Goicoechea Allen
MGA:sg
Enclosures
RECEIVED
Monday, April 15, 2024 4:10 PM
IDAHO PUBLIC
UTILITIES COMMISSION

CERTIFICATE OF ATTORNEY

ASSERTION THAT INFORMATION CONTAINED IN AN IDAHO PUBLIC UTILITIES
COMMISSION FILING IS PROTECTED FROM PUBLIC INSPECTION

Idaho Power Company’s Application for Authority to Implement Power Cost
Adjustment (“PCA”) Rates for Electric Service from June 1, 2024 through May 31,
2025

Case No. IPC-E-24-17

The undersigned attorney, in accordance with Commission Rules of Procedure
67, believes that Attachment Nos. 3 and 6 to Idaho Power Company’s Application for
Authority to Implement Power Cost Adjustment Rates for Electric Service from June 1,
2024 through May 31, 2025 and Exhibit Nos. 4 and 5 to the Direct Testimony of Jessica
G. Brady, dated April 15, 2024, may contain information that Idaho Power Company and
a third-party claim constitutes confidential trade secrets, proprietary information, and/or
private business records required by law to be submitted to or inspected by a public
agency as described in Idaho Code § 74-101, et seq., and § 48-801, et seq., or is
otherwise protected from public disclosure and as such is exempt from public inspection,
examination, or copying.

DATED this 15th day of April 2024.

Megan Goicoechea Allen
Counsel for Idaho Power Company

MEGAN GOICOECHEA ALLEN (ISB No. 7623)
LISA D. NORDSTROM (ISB No. 5733)
Idaho Power Company
1221 West Idaho Street (83702)
P.O. Box 70
Boise, Idaho 83707
Telephone: [phone]
Facsimile: [phone]
[e-mail]
[e-mail]

Attorneys for Idaho Power Company

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPANY FOR
AUTHORITY TO IMPLEMENT POWER
COST ADJUSTMENT (“PCA”) RATES
FOR ELECTRIC SERVICE FROM JUNE
1, 2024, THROUGH MAY 31, 2025.

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CASE NO. IPC-E-24-17

APPLICATION

Idaho Power Company (“Idaho Power” or “Company”), in accordance with Idaho
Code § 61-502 and Commission Rule of Procedure1 52, hereby respectfully requests the
Idaho Public Utilities Commission (“Commission”) approve an update to Schedule 55
based on the quantification of the 2024-2025 Power Cost Adjustment (“PCA”) to become
effective June 1, 2024, for the period of June 1, 2024, through May 31, 2025. If the
proposed rates and charges for electric service in the state of Idaho included as

1 Hereinafter cited as RP.

Attachment 1 to this Application are approved, the 2024-2025 PCA will result in an overall
revenue decrease of approximately $35.7 million, or a 2.31 percent decrease from current
billed revenue.
In support of this Application, Idaho Power has filed the Direct Testimony of
Jessica G. Brady, Senior Regulatory Analyst (“Brady Testimony”). Ms. Brady’s testimony
provides an overview of the PCA, details the 2024-2025 PCA amount, explains the factors
that impact this year’s PCA quantification, presents the calculation of the proposed 2024-
2025 PCA rates, and discusses the additional PCA component related to revenue
sharing. In addition, the Brady Testimony details the net customer impact of the 2024-
2025 PCA rates if approved as filed and addresses compliance with prior Commission
Orders. In further support of this Application, Idaho Power represents as follows:
I. BACKGROUND
1. Idaho Power is an Idaho corporation whose principal place of business is
1221 West Idaho Street, Boise, Idaho 83702.
2. Idaho Power is a public utility supplying retail electric service to more than
600,000 customers in southern Idaho and eastern Oregon. Idaho Power is subject to the
jurisdiction of this Commission in Idaho and to the jurisdiction of the Public Utility
Commission of Oregon. Idaho Power is also subject to the jurisdiction of the Federal
Energy Regulatory Commission.
3. The Company is compensated for “normal” costs of generating electricity
through its base electricity rates established by the Commission in general rate cases.
However, though the power supply expense component embedded in base rates is static,
due to the Company’s unique reliance on hydro generation, actual power supply

expenses vary from year to year with changes in streamflow conditions.
4. As a result of the Company’s request to establish a permanent mechanism
to adjust rates annually to reflect variations in power supply costs in Case No. IPC-E-92-
25, the Commission issued Order No. 24806 on March 29, 1993, in which it approved the
implementation of an annual Power Cost Adjustment procedure in order to provide
consistency and stability to rates.2 The PCA is a cost recovery mechanism that passes
on both the benefits and costs of supplying energy to Idaho Power customers. Neither
Idaho Power nor its shareholders receive any financial return on this filing – money
collected from the surcharge can be used only to pay power supply expenses.
5. Since its establishment, the PCA mechanism has been incrementally
refined and modified through a series of Commission Orders, as more fully set forth
below, to ensure the mechanism achieves its desired purpose and to incorporate other
distinct elements, such as revenue sharing, as circumstances dictated.
6. For example, following several Commission orders addressing the need to
modify the Company’s then-existing PCA methodology, the Company initiated Case No.
IPC-E-08-19 requesting the Commission approve a settlement stipulation that addressed
a number of issues and components of the PCA. In Order No. 30715, the Commission
approved the stipulation and changes to the PCA formula, which included, in pertinent
part, revising the PCA sharing methodology that allocates non-PURPA3 power supply
expenses between customers and shareholders.4 More specifically, the PCA sharing

2 In the Matter of the Application of Idaho Power Company for Authority to Implement a Power Cost
Adjustment Tariff for Electric Service to Customers in the State of Idaho and for Approval of New Rates
for Service Under the FMC Special Contract, Case No. IPC-E-92-25, Order No. 24806, p. 25-26 (Mar. 23,
1993).
3 Public Utility Regulatory Policies Act of 1978 (“PURPA”).
4 In the Matter of Idaho Power Company’s Petition for Approval of Changes to its Power Cost Adjustment
(PCA) Mechanism, Case No. IPC-E-08-19, Order No. 30715, p. 4-5 (Jan. 9, 2009).

ratio was modified to 95 percent customer, 5 percent Idaho Power.5 In addition, in Order
No. 30715 the Commission approved changes to the Load Growth Adjustment Rate
(“LGAR”), third-party transmission expense, the PCA forecast, and power supply expense
distribution.6
7. Following the notice of intent to file a general rate case filed by the Company
in August 2009, the Company, Commission Staff, and other stakeholders worked together
to develop an approach that would allow the Company to implement a multi-year rate
case moratorium while at the same time giving the Company the opportunity to recover a
maintenance level of earnings over the term of the moratorium. This ultimately resulted
in the Company seeking approval of a settlement stipulation filed in lieu of a general rate
case in Case No. IPC-E-09-30, which was granted by the Commission in Order No.
30978.7 Through this stipulation, a revenue sharing mechanism was established to allow
the Company to amortize Accumulated Deferred Investment Tax Credits (“ADITC”) when
earnings fall below a certain Return on Equity (“ROE”) threshold, or share a portion of
revenues with Idaho customers in the form of a rate reduction when earnings are above
a certain ROE threshold. This ADITC/Revenue Sharing mechanism was subsequently

5 With respect to PUPRA expenses and demand response incentive payments, when actual annual
expenses deviate from base level NPSE, the Company is allowed to pass 100 percent of the difference
for recovery or credit through the PCA.
6 Id.
7 In the Matter of the Application of Idaho Power Company for an Accounting Order to Amortize Additional
Accumulated Deferral Income Tax Credit and Approving a Rate Case Moratorium, Case No. IPC-E-09-30,
Order No. 30978, p. 5-7 (Jan. 13, 2010).

extended, and percentages, thresholds, and accounting were modified by the
Commission in Order Nos. 32424,8 33149,9 and 34071.10
8. At the Commission’s request, Staff initiated Case No. GNR-E-10-03 to
explore issues related to the load growth adjustment portion of the utilities’ power cost
adjustment mechanisms, particularly considering use of a LGAR in periods of declining
load. In that case, the Commission ultimately adopted a revised LGAR methodology and
changed the name of the methodology to the Load Change Adjustment Rate (“LCAR”),
as set forth in Order No. 32206.11
9. In 2014 and 2015, the Company and Staff considered potential ways to
improve the PCA’s accuracy and, as a result of these efforts, agreed on a number of
changes to the calculation of the PCA true-up. The ensuing proposal, to convert the
PCA’s existing Load Change Adjustment deferral calculation to a Sales-Based
Adjustment (“SBA”), and modify the PCA deferral balance’s monthly interest calculation,
was set forth in a settlement agreement and submitted to the Commission in Case No.
IPC-E-15-15. On May 28, 2015, the Commission issued Order No. 33307 approving
changes to the PCA pursuant to the settlement agreement: (1) replacing the existing
LCAR with the SBA, calculated in the same manner as the LCAR but replacing the load-
based megawatt-hour (“MWh”) denominator with the corresponding sales-based MWh

8 In the Matter of the Application of Idaho Power Company to Extend and Modify Accounting Order to
Amortize Additional Accumulated Deferred Income Tax Credits (ADITC), Case No. IPC-E-11-22, Order
No. 32424, p. 4 (Dec. 27, 2011).
9 In the Matter Idaho Power Company’s Application to Extend its Accumulated Deferred Investment Tax
Credits/Revenue Sharing Mechanism Beyond 2014, Case No. IPC-E-14-14, Order No. 33149, p. 4-5
(Oct. 9, 2014).
10 In the Matter of the Investigation into the Impact of Federal Tax Code Revisions on Utility Costs and
Ratemaking, Case No. GNR-U-18-01, Order No. 34071, p. 4-5 (May 31, 2018).
11 In the Matter of the Commission’s Inquiry into Load Growth Adjustments that Are Part of Power Cost
Adjustment Mechanisms, Case No. GNR-U-10-03, Order No. 32206, p. 6-7 (Mar. 15, 2011).

denominator; and (2) calculating monthly interest on the deferral balance by assigning
annual base Net Power Supply Expenses (“NPSE”) to each month according to expected
base rate revenue collection as set in the Company’s last general rate case, Case No.
IPC-E-11-08.12
10. Following changes to federal and Idaho state tax rates implemented in
2018, the Commission opened a multi-utility case, Case No. GNR-U-18-01, to investigate
whether to adjust utilities’ rates and charges to reflect the income tax and revenue
requirement reductions resulting from the tax changes. After considering the impacts of
tax reform on its operations, the Company worked together with Staff on a proposal that
would return to customers the tax benefits the Company was realizing under the tax law
changes with limited negative impact to the Company and entered into a settlement
stipulation reflecting the same. The settlement stipulation filed with the Commission on
April 12, 2018, included, among other things, extending and modifying the
ADITC/Revenue Sharing mechanism to the iteration applicable to the instant request.13
On May 31, 2018, the Commission issued Order No. 34071 approving the settlement
stipulation including the following modifications to the sharing portion of the mechanism,
which allowed for greater customer benefits.14 First, for actual year-end Idaho
jurisdictional earnings greater than 10 percent ROE, all amounts up to and including 10.5
percent ROE will be shared between customers and the Company on an 80 percent and

12 In the Matter of Idaho Power Company’s Application for Approval of Computational Modifications to the
True-Up Portion of the Power Cost Adjustment, Case No. IPC-E-15-15, Order No. 33307, p. 4-5 (May 28,
2015).
13 The mechanism was most recently modified in the Company’s 2023 General Rate Case, IPC-E-23-11.
However, the stipulated modifications were effective January 1, 2024, and will not impact the PCA filing
until 2025.
14 GNR-U-18-01, Order No. 34071, p. 4-5.

20 percent basis, respectively.15 The customer revenue sharing benefit will be in the form
of a reduction to rates at the time the subsequent year’s PCA becomes effective. Second,
Idaho earnings above a 10.5 percent ROE will also be shared, with customers receiving
55 percent of the earnings in the form of a reduction to rates at the time the subsequent
year’s PCA becomes effective, as well as 25 percent of the earnings applied as an offset
to the Company’s pension balancing account, with the Company retaining the remaining
20 percent.16
11. On May 28, 2021, the Commission issued Order No. 35054 approving the
Company’s 2021 annual PCA filing and instructing it, based on Staff’s recommendation
to simplify the PCA mechanism, “to initiate discussions with interested parties and to file
a case with the Commission to review whether the PCA mechanism should be modified”
before the Company’s next PCA application.17
12. As a result of this endeavor, the Company proposed in Case No. IPC-E-21-
38 to simplify its PCA mechanism by replacing the “true-up” and “true-up of the true-up”
components of the PCA with a balancing account. On January 10, 2022, the Commission
issued Order No. 35290 approving the Company’s request to modify the PCA mechanism
thereby combining the two true-up components into one balancing account rate, referred
to below as the “Balancing Adjustment.”18 This modification was intended to make the
PCA more transparent and easier to understand and does not materially affect the overall
cost recovery of the PCA.

15 Id.
16 Id.
17 In the Matter of Idaho Power Company’s Application for Authority to Implement Power Cost Adjustment
(PCA) Rates for Electric Service from June 1, 2021 through May 31, 2011, IPC-E-21-10, Order No.
35054, p. 5 (May 21, 2021).
18 Idaho Power Company’s Application for Modification of the Power Cost Adjustment Mechanism, Case
No. IPC-E-21-38, Order No. 35290, p. 2-3 (Jan. 10, 2022).

II. THE PCA MECHANISM
13. As explained more fully above, the PCA quantifies and tracks annual
differences between actual NPSE and the normalized or “base level” of NPSE recovered
in the Company’s base rates, resulting in a credit or surcharge that is updated annually
on June 1.
14. The PCA mechanism utilizes a 12-month test period of April through March
(“PCA Year”) and consists of a forecast component and a Balancing Adjustment (formerly
referred to as the “true-up” and the “true-up of the true-up”). The PCA forecast represents
the difference between the Company’s NPSE forecast from its March Operating Plan and
the base level NPSE recovered in the Company’s base rates. The PCA sharing
mechanism allows the Company to pass to Idaho customers 95 percent of the annual
differences in actual non-PURPA power expenses as compared to the base level NPSE,
whether positive or negative. The Balancing Adjustment includes a backward-looking
tracking of differences between the prior PCA Year’s forecast and actual NPSE incurred
by the Company and also tracks the collection of the prior year’s Balancing Adjustment.
15. The PCA is also the rate mechanism used by the Company to provide direct
revenue sharing benefits resulting from the Revenue Sharing mechanism originally
approved in Order No. 34071.
Forecast.
16. The Brady Testimony describes and computes the PCA rate to be effective
June 1, 2024, through May 31, 2025. The system-level forecast of NPSE for the 2024-
2025 PCA Year is $509,555,990, which is $24,648,746 higher than the currently approved

base level NPSE of $484,907,244 and $31,943,394 lower than last year’s forecast
amount of $541,499,384. The decrease in this year’s forecast is primarily due to higher
forecast hydro generation compared to last year.
17. As described in Ms. Brady’s testimony, the difference between the system-
level forecast of NPSE and the currently approved base level NPSE is adjusted for the
PCA sharing provisions and allocated to Idaho customers to determine the 2024-2025
PCA forecast component to be collected from Idaho customers of $22,712,031.
Balancing Adjustment.
18. Per Order No. 35290,19 the “true-up” and the “true-up of the true-up” have
been combined into a single Balancing Adjustment. In addition to the NPSE incurred
during the April 2023 through March 2024 period, Idaho Power included its actual cost of
Western Energy Imbalance Market (“EIM”) participation for April 2023 through December
2023 in the Balancing Adjustment as approved by the Commission in Order No. 34100.20
Because EIM costs were included in base rates resulting from the Company’s 2023
General Rate Case, which went into effect on January 1, 2024, EIM costs are no longer
included in the PCA as of that date. Benefits associated with EIM participation are
embedded in actual NPSE experienced over that same period.
19. The PCA Balancing Adjustment deferral balance at the end of March 2024,
with interest applied, was approximately $90 million, which represents a decrease to
customers rates in this year’s PCA Balancing Adjustment. Order No. 35804 in last year’s
PCA filing directed Idaho Power to collect the 2022-2023 PCA deferral balance equally

19 Case No. IPC-E-21-38.
20 In the Matter of the Application of Idaho Power to Establish a Method of Recovery for Costs Associated
with Participation in the Western Energy Imbalance Market, Case No. IPC-E-17-16, Order No. 34100, p.
3-4 (Jul. 2, 2018).

over a two-year period. As a result, this year’s balance is primarily attributed to the
continued collection of last year’s deferral balance. Actual power supply expenses in the
2023-2024 PCA Year were just 3 percent higher than forecast expenses, so the variance
between forecast and actual power supply expenses for the 2023-2024 PCA Year had a
relatively small impact on this year’s deferral balance. However, this year’s deferral
balance does include increased benefits associated with the SBA, as well as increased
Renewable Energy Credit (“REC”) sales.
Revenue Sharing.
20. The Company’s earnings in each year from 2011 through 2015, as well as
2018 and 2021, resulted in revenue sharing with Idaho customers totaling $126.7 million,
either as a direct rate offset in the PCA or as an offset to amounts that would have
otherwise been collected in rates. The Company’s earnings in 2016, 2017, 2019, 2020,
and 2022 were below the revenue sharing threshold. As described in greater detail in the
Brady Testimony, the Company’s 2023 Idaho jurisdictional year-end ROE was 9.4
percent. In accordance with the terms of the modified revenue sharing mechanism
approved by the Commission in Order No. 34071,21 the Company’s Idaho jurisdictional
year-end ROE was below the 10.0 percent ROE threshold for revenue sharing.
Therefore, the 2024-2025 PCA will not include a revenue sharing component.
III. 2024-2025 PCA CALCULATION AND PROPOSED RATE CHANGES
PCA Rate Calculation.
21. The Brady Testimony describes in detail how the PCA rate is determined,
including how each of its components are calculated. For the 2024-2025 PCA Year, the

21 GNR-U-18-01, Order No. 34071, p. 4-5.

Company’s uniform PCA is comprised of (1) the 0.1501 cents per kilowatt-hour (“kWh”)
for the 2024-2025 projected power cost of serving firm loads under the current PCA
methodology and 95 percent sharing and (2) the 0.5946 cents per kWh for the 2023-2024
Balancing Adjustment. The sum of these two components results in a 0.7447 cents per
kWh charge for all rate classes.
Cumulative Proposed June 1, 2024, Rate Changes.
22. PCA. The 2024-2025 total PCA amount, as measured from the currently
approved base level NPSE is $112.7 million. This represents a decrease in total billed
revenue of $35.7 million, or 2.31 percent, for Idaho customers, effective June 2024
through May 2025.
23. Fixed Cost Adjustment (“FCA”). On March 15, 2024, Idaho Power filed its
annual FCA in Case No. IPC-E-24-10. The Company’s 2024 FCA filing proposes a $10.6
million increase in current billed revenue, or a 1.44 percent increase, for Idaho Residential
and Small General Service customers, effective June 2024 through May 2025.
24. Combined Effect of the PCA and FCA Filings. If the proposed PCA and
FCA rate changes are approved as filed, the combined impact is an overall decrease in
current billed revenue of $25.1 million, or 1.63 percent, for June 2024 through May 2025
25. Attachment 1 to this Application is Idaho Power’s proposed IPUC No. 30,
Tariff No. 101, in both clean and legislative formats, which contains the tariff sheets
specifying the proposed Schedule 55 rates for providing retail electric service to its
customers in the state of Idaho for June 1, 2024, through May 31, 2025.
26. Attachment 2 to this Application contains a summary of revenue impact
showing the effect to each customer class of applying the Company’s proposed PCA

rates that collect $35.7 million less, from June 2024 through May 2025, than the PCA
rates currently in effect.
IV. COMPLIANCE WITH PRIOR COMMISSION ORDERS
IPC-E-23-12, Order No. 35804
27. In Final Order No. 35804 issued on May 31, 2023, the Commission
approved the Company’s request to implement PCA rates for the 2023-2024 PCA year,
subject to certain conditions including (1) directing the Company to notify the Commission
of any outcome of the Hells Canyon Unit No. 3 damage claim and (2) ordering
Commission Staff (“Staff”) to investigate the prudency of the Company’s coal supply
management and associated impact on NPSE. Pursuant to the Commission’s direction
the Company addresses each item, in turn, as follows.
28. The first issue relates to an extended outage at Hells Canyon Unit No. 3
due to repairs, and the Company’s claim against the repair contractor for its failure to
meet completion dates for the project. As a result of the delays, Idaho Power withheld
delay liquidated damages, the majority of which were included as an offset to power
supply costs in the 2023-2024 PCA Year. However, a portion was also recorded to offset
labor costs that would not have otherwise occurred. The Company has provided
additional detail on the delay liquidated damage amounts in Confidential Exhibit No. 5 to
the Brady Testimony.
29. With respect to the Commission request for Staff to investigate the prudency
of the Company’s power supply expenses related to coal supply issues and report its
assessment to the Commission within six months, Commission Staff filed its “Confidential
Staff Report” on November 30, 2023. Based on its assessment, Staff concluded that the

Company encountered unique circumstances during the 2022-2023 year and pursued
many actions to resolve the coal situation, but believed the Company could have taken
additional actions to prudently mitigate NPSE. As a result, Staff recommended that an
adjustment to the NPSE be considered in the Company’s next PCA filing. Instead of
identifying a specific adjustment, Staff recommended that the Company include Staff’s
Report and the Company’s response with its next PCA filing to enable the Commission
to make an informed decision as to any adjustments to the PCA balance. Staff’s Report
and the Company’s response, "Analysis of Coal Supply Issues in the 2022 PCA Year”,
are provided as Confidential Attachment 3 and Attachment 4 to this filing, respectively. In
addition, the Company has included with this filing Attachment 5 and Confidential
Attachment 6, which provide supporting information and analysis. While the Company
appreciates Staff’s review of this matter, it does not agree that an adjustment to NPSE is
reasonable under the circumstances presented. To the contrary, as more fully described
in its response, the Company moved expeditiously and judiciously to mitigate the
challenges that arose from sustained market volatility and limited coal inventories in the
region.
V. MODIFIED PROCEDURE
30. Idaho Power believes that a technical hearing is not necessary to consider
the issues presented herein and respectfully requests that this Application be processed
under Modified Procedure, i.e., by written submissions rather than by hearing. RP 201,
et seq. If, however, the Commission determines that a technical hearing is required, the
Company stands ready to present its testimony, including but limited to the Brady

Testimony filed contemporaneously herewith, and support the Application in such
hearing.
VI. COMMUNICATIONS AND SERVICE OF PLEADINGS
31. In conformance with RP 125, this Application will be brought to the attention
of Idaho Power’s customers by means of a press release to media in the Company’s
service area and a customer notice distributed in customers’ bills, both of which
accompany this filing. The customer notice will be distributed over the course of the
Company’s current billing cycles, and additionally, to ensure that all customers are
notified in a timely manner and have sufficient time to submit comments, Idaho Power is
sending a direct mail postcard to a subset of customers that receive their bill toward the
end of the processing time for this case. As such, a bill insert and/or the direct mail
postcard will be mailed no later than May 20, 2024.
32. The Company has also prominently displayed its intent to file the PCA on
its website since March 15, 2024. Upon filing of this Application, this web graphic will link
directly to the PCA press release and bill insert. Idaho Power will also keep its
Application, testimonies, and exhibits open for public inspection at its offices throughout
the state of Idaho. Idaho Power asserts that this notice procedure satisfies the Rules of
Procedure of this Commission; however, the Company will, in the alternative, bring the
Application to the attention of its affected customers through any other means directed by
this Commission.

33. Communications and service of pleadings with reference to this Application
should be sent to the following:
Megan Goicoechea Allen
Lisa D. Nordstrom
Regulatory Dockets
Idaho Power Company
1221 West Idaho Street (83702)
P.O. Box 70
Boise, Idaho 83707
[e-mail]
[e-mail]
[e-mail]
Matthew T. Larkin
Timothy E. Tatum
Jessi Brady
Idaho Power Company
1221 West Idaho Street (83702)
P.O. Box 70
Boise, Idaho 83707
[e-mail]
[e-mail]
[e-mail]

VII. REQUEST FOR RELIEF
34. As discussed in greater detail above, Idaho Power respectfully requests that
the Commission issue an order: (1) authorizing that this matter be processed by Modified
Procedure and (2) approving an update to Schedule 55 based on the quantification of the
2024-2025 PCA, resulting in an overall decrease to current billed revenue of
approximately $35.7 million to become effective June 1, 2024.
DATED at Boise, Idaho, this 15th day of April 2024.

________________________________
MEGAN GOICOECHEA ALLEN
Attorney for Idaho Power Company

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-24-17

IDAHO POWER COMPANY

ATTACHMENT NO. 1

PROPOSED SCHEDULE 55
(CLEAN AND LEGISLATIVE FORMAT)
Idaho Power Company First Revised Sheet No. 55-1
Cancels
I.P.U.C. No. 30, Tariff No. 101 Original Sheet No. 55-1
IDAHO Issued by IDAHO POWER COMPANY
Issued per Order No. Timothy E. Tatum, Vice President, Regulatory Affairs
Effective – June 1, 2024 1221 West Idaho Street, Boise, Idaho

SCHEDULE 55
POWER COST ADJUSTMENT

APPLICABILITY

This schedule is applicable to the electric energy delivered to all Idaho retail Customers served
under the Company’s schedules and Special Contracts listed within this schedule. These loads are
referred to as "firm" load for purposes of this schedule.

BASE POWER COST AND PROJECTED POWER COST

The Base Power Cost of the Company's rates, expressed in cents per kWh, is computed by
dividing the sum of the Company's power cost components by firm kWh sales. The power cost
components are segmented into three categories as described in the table below:

The Projected Power Cost is the Company estimate, expressed in cents per kWh, of the power
cost components for the forecasted time period beginning April 1 each year and ending the following
March 31.

BALANCING ADJUSTMENT

The Balancing Adjustment is based upon the differences between previous Projected Power Cost
and the power costs actually incurred. The Balancing Adjustment is 0.5946 cents per kWh.

EARNINGS SHARING

Order Nos. 30978, 32424, 33149, and 34071 directed the Company to share a portion of its
earnings above a certain threshold with customers through the annual Power Cost Adjustment. The
Company’s 2023 earnings were not above the prescribed threshold resulting in a credit of 0.0000 cents
per kWh.

Idaho Power Company First Revised Sheet No. 55-2
Cancels
I.P.U.C. No. 30, Tariff No. 101 Original Sheet No. 55-2
IDAHO Issued by IDAHO POWER COMPANY
Issued per Order No. Timothy E. Tatum, Vice President, Regulatory Affairs
Effective – June 1, 2024 1221 West Idaho Street, Boise, Idaho

SCHEDULE 55
POWER COST ADJUSTMENT
(Continued)

POWER COST ADJUSTMENT

The Power Cost Adjustment (PCA) is the sum of: 1) 95 percent of the difference between the
Projected Power Costs in Category 1 and the Base Power Costs in Category 1; 2) 100 percent of the
difference between the Projected Power Costs in Category 2 and the Base Power Costs in Category 2;
3) 100 percent of the difference between the Projected Power Costs in Category 3 and the Base Power
Costs in Category 3; 4) the Balancing Adjustment; and 5) Earnings Sharing. The following table calculates
the rates for Categories 1, 2 and 3.

The following table shows the determination of PCA rates for Categories 1, 2, and 3:

Category Description
Base
Power
Cost
Projected
Power
Cost
Difference Sharing
% Rate
(¢ per kWh)
1
The sum of fuel expense and
purchased power expense
(excluding purchases from
cogeneration and small power
producers), less the sum of off-
system surplus sales revenue and
revenue from market-based
special contract pricing.
1.64824 1.77069 0.12245 95% 0.11633
2
Purchased power expense from
cogeneration and small power
producers.
1.35833 1.39092 0.03259 100% 0.03259
3 Demand response incentive
payments. 0.06767 0.06881 0.00113 100% 0.00113
Total 3.07424 3.23041 0.15617 0.15005

Idaho Power Company First Revised Sheet No. 55-3
Cancels
I.P.U.C. No. 30, Tariff No. 101 Original Sheet No. 55-3
IDAHO Issued by IDAHO POWER COMPANY
Issued per Order No. 36042 Timothy E. Tatum, Vice President, Regulatory Affairs
Effective – June 1, 2024 1221 West Idaho Street, Boise, Idaho

SCHEDULE 55
POWER COST ADJUSTMENT
(Continued)

The monthly Power Cost Adjustment rates applied to the Energy rate of all metered schedules and
Special Contracts are shown below. The monthly Power Cost Adjustment applied to the per unit charges
of the nonmetered schedules is the monthly estimated usage times the cents per kWh rates shown below.
Totals may not tie due to rounding.

Schedule Category
Balancing
Adjustment
Earnings
Sharing
Total PCA
1 2 3
1 0.1163 0.0326 0.0011 0.5946 (0.0000) 0.7447
3 0.1163 0.0326 0.0011 0.5946 (0.0000) 0.7447
5 0.1163 0.0326 0.0011 0.5946 (0.0000) 0.7447
6 0.1163 0.0326 0.0011 0.5946 (0.0000) 0.7447
7 0.1163 0.0326 0.0011 0.5946 (0.0000) 0.7447
8 0.1163 0.0326 0.0011 0.5946 (0.0000) 0.7447
9S 0.1163 0.0326 0.0011 0.5946 (0.0000) 0.7447
9P 0.1163 0.0326 0.0011 0.5946 (0.0000) 0.7447
9T 0.1163 0.0326 0.0011 0.5946 (0.0000) 0.7447
15 0.1163 0.0326 0.0011 0.5946 (0.0000) 0.7447
19S 0.1163 0.0326 0.0011 0.5946 (0.0000) 0.7447
19P 0.1163 0.0326 0.0011 0.5946 (0.0000) 0.7447
19T 0.1163 0.0326 0.0011 0.5946 (0.0000) 0.7447
24 0.1163 0.0326 0.0011 0.5946 (0.0000) 0.7447
40 0.1163 0.0326 0.0011 0.5946 (0.0000) 0.7447
41 0.1163 0.0326 0.0011 0.5946 (0.0000) 0.7447
42 0.1163 0.0326 0.0011 0.5946 (0.0000) 0.7447
26 0.1163 0.0326 0.0011 0.5946 * 0.7447
29 0.1163 0.0326 0.0011 0.5946 * 0.7447
30 0.1163 0.0326 0.0011 0.5946 * 0.7447
32 0.1163 0.0326 0.0011 0.5946 * 0.7447
34 0.1163 0.0326 0.0011 0.5946 * 0.7447

* Earnings Sharing Credits are applied as monthly amounts per the table below.

Schedule Special Contract Monthly Credit
26 Micron ($0.00)
29 Simplot ($0.00)
30 DOE ($0.00)
32 Simplot-Caldwell ($0.00)
34 Lamb Weston ($0.00)

EXPIRATION

The Power Cost Adjustment included on this schedule will expire May 31, 2025.
Idaho Power Company Original First Revised Sheet No. 55-1
Cancels
I.P.U.C. No. 30, Tariff No. 101 Nineteenth RevisedOriginal Sheet No. 55-1
IDAHO Issued by IDAHO POWER COMPANY
Issued per Order No. 36042 Timothy E. Tatum, Vice President, Regulatory Affairs
Effective – January 1, 2024June 1, 2024 1221 West Idaho Street, Boise, Idaho

SCHEDULE 55
POWER COST ADJUSTMENT

APPLICABILITY

This schedule is applicable to the electric energy delivered to all Idaho retail Customers served
under the Company’s schedules and Special Contracts listed within this schedule. These loads are
referred to as "firm" load for purposes of this schedule.

BASE POWER COST AND PROJECTED POWER COST

The Base Power Cost of the Company's rates, expressed in cents per kWh, is computed by
dividing the sum of the Company's power cost components by firm kWh sales. The power cost
components are segmented into three categories as described in the table below:

The Projected Power Cost is the Company estimate, expressed in cents per kWh, of the power
cost components for the forecasted time period beginning April 1 each year and ending the following
March 31.

BALANCING ADJUSTMENT

The Balancing Adjustment is based upon the differences between previous Projected Power Cost
and the power costs actually incurred. The Balancing Adjustment is 0.6357 5946 cents per kWh.

EARNINGS SHARING

Order Nos. 30978, 32424, 33149, and 34071 directed the Company to share a portion of its
earnings above a certain threshold with customers through the annual Power Cost Adjustment. The
Company’s 20223 earnings were not above the prescribed threshold resulting in a credit of 0.0000 cents
per kWh.

Idaho Power Company Original First Revised Sheet No. 55-2
Cancels
I.P.U.C. No. 30, Tariff No. 101Thirteenth RevisedOriginal Sheet No. 55-2
IDAHO Issued by IDAHO POWER COMPANY
Issued per Order No. 36042 Timothy E. Tatum, Vice President, Regulatory Affairs
Effective – January 1, 2024June 1, 2024 1221 West Idaho Street, Boise, Idaho

SCHEDULE 55
POWER COST ADJUSTMENT
(Continued)

POWER COST ADJUSTMENT

The Power Cost Adjustment (PCA) is the sum of: 1) 95 percent of the difference between the
Projected Power Costs in Category 1 and the Base Power Costs in Category 1; 2) 100 percent of the
difference between the Projected Power Costs in Category 2 and the Base Power Costs in Category 2;
3) 100 percent of the difference between the Projected Power Costs in Category 3 and the Base Power
Costs in Category 3; 4) the Balancing Adjustment; and 5) Earnings Sharing. The following table calculates
the rates for Categories 1, 2 and 3.

The following table shows the determination of PCA rates for Categories 1, 2, and 3:

Category Description
Base
Power
Cost
Projected
Power
Cost
Difference Sharing
% Rate
(¢ per kWh)
1
The sum of fuel expense and
purchased power expense
(excluding purchases from
cogeneration and small power
producers), less the sum of off-
system surplus sales revenue and
revenue from market-based
special contract pricing.
1.6614361.
64824
1.991918
1.77069
0.3304820
.12245 95% 0.3139580
.11633
2
Purchased power expense from
cogeneration and small power
producers.
1.3692061.
35833
1.395299
1.39092
0.0260930
.03259 100% 0.0260930
.03259
3 Demand response incentive
payments.
0.0684470.
06767
0.073423
0.06881
0.0049760
.00113 100% 0.0049760
.00113
Total 3.0990893.
07424
3.460640
3.23041
0.3615510
.15617 0.3450270
.15005

Idaho Power Company Original First Revised Sheet No. 55-3
Cancels
I.P.U.C. No. 30, Tariff No. 101Twelfth RevisedOriginal Sheet No. 55-3
IDAHO Issued by IDAHO POWER COMPANY
Issued per Order No. 36042 Timothy E. Tatum, Vice President, Regulatory Affairs
Effective – January 1, 2024June 1, 2024 1221 West Idaho Street, Boise, Idaho

SCHEDULE 55
POWER COST ADJUSTMENT
(Continued)

The monthly Power Cost Adjustment rates applied to the Energy rate of all metered schedules and
Special Contracts are shown below. The monthly Power Cost Adjustment applied to the per unit charges
of the nonmetered schedules is the monthly estimated usage times the cents per kWh rates shown below.
Totals may not tie due to rounding.

Schedule Category
Balancing
Adjustment
Earnings
Sharing
Total PCA
1 2 3
1
0.31400.1163 0.02610.0326 0.00500.0011 0.63570.5946 (0.0000)
0.98070.7447
3 0.31400.1163 0.02610.0326 0.00500.0011 0.63570.5946 (0.0000) 0.98070.7447
5 0.31400.1163 0.02610.0326 0.00500.0011 0.63570.5946 (0.0000) 0.98070.7447
6 0.31400.1163 0.02610.0326 0.00500.0011 0.63570.5946 (0.0000) 0.98070.7447
7 0.31400.1163 0.02610.0326 0.00500.0011 0.63570.5946 (0.0000) 0.98070.7447
8 0.31400.1163 0.02610.0326 0.00500.0011 0.63570.5946 (0.0000) 0.98070.7447
9S 0.31400.1163 0.02610.0326 0.00500.0011 0.63570.5946 (0.0000) 0.98070.7447
9P 0.31400.1163 0.02610.0326 0.00500.0011 0.63570.5946 (0.0000) 0.98070.7447
9T 0.31400.1163 0.02610.0326 0.00500.0011 0.63570.5946 (0.0000) 0.98070.7447
15 0.31400.1163 0.02610.0326 0.00500.0011 0.63570.5946 (0.0000) 0.98070.7447
19S
0.31400.1163 0.02610.0326 0.00500.0011 0.63570.5946 (0.0000)
0.98070.7447
19P 0.31400.1163 0.02610.0326 0.00500.0011 0.63570.5946 (0.0000) 0.98070.7447
19T 0.31400.1163 0.02610.0326 0.00500.0011 0.63570.5946 (0.0000) 0.98070.7447
24 0.31400.1163 0.02610.0326 0.00500.0011 0.63570.5946 (0.0000) 0.98070.7447
40 0.31400.1163 0.02610.0326 0.00500.0011 0.63570.5946 (0.0000) 0.98070.7447
41 0.31400.1163 0.02610.0326 0.00500.0011 0.63570.5946 (0.0000) 0.98070.7447
42 0.31400.1163 0.02610.0326 0.00500.0011 0.63570.5946 (0.0000) 0.98070.7447
26 0.31400.1163 0.02610.0326 0.00500.0011 0.63570.5946 * 0.98070.7447
29 0.31400.1163 0.02610.0326 0.00500.0011 0.63570.5946 * 0.98070.7447
30 0.31400.1163 0.02610.0326 0.00500.0011 0.63570.5946 * 0.98070.7447
32 0.31400.1163 0.02610.0326 0.00500.0011 0.63570.5946 * 0.98070.7447
34 0.1163 0.0326 0.0011 0.5946 * 0.7447

* Earnings Sharing Credits are applied as monthly amounts per the table below.

Schedule Special Contract Monthly Credit
26 Micron ($0.00)
29 Simplot ($0.00)
30 DOE ($0.00)
32 Simplot-Caldwell ($0.00)
34 Lamb Weston ($0.00)

EXPIRATION

Idaho Power Company Original First Revised Sheet No. 55-3
Cancels
I.P.U.C. No. 30, Tariff No. 101Twelfth RevisedOriginal Sheet No. 55-3
IDAHO Issued by IDAHO POWER COMPANY
Issued per Order No. 36042 Timothy E. Tatum, Vice President, Regulatory Affairs
Effective – January 1, 2024June 1, 2024 1221 West Idaho Street, Boise, Idaho
The Power Cost Adjustment included on this schedule will expire May 31, 20245.

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-24-17

IDAHO POWER COMPANY

ATTACHMENT NO. 2

2024 REVENUE IMPACT SUMMARY

Total Percent
Rate Average Normalized Current Adjustments Proposed Change
Line Sch. Number of Energy Billed Mills to Billed Total Billed Mills
Billed to Billed (2)
No Tariff Description No.Customers (1)(kWh) (1)Revenue Per kWh Revenue Revenue Per kWh Revenue

Uniform Tariff Rates:

1 Residential Service 1 502,357 5,582,403,703 $691,190,525 123.82 ($13,174,473) $678,016,052 121.46 (1.91)%
2 Master Metered Mobile Home Park 3 19 5,177,497 $613,522 118.50 ($12,219) $601,303 116.14 (1.99)%
3 Residential Service Time-of-Day 5 989 18,025,131 $2,147,357 119.13 ($42,539) $2,104,818 116.77 (1.98)%
4 Residential Service On-Site Generation 6 18,601 172,081,522 $21,541,347 125.18 ($406,112) $21,135,235 122.82 (1.89)%
5 Small General Service 7 30,614 138,530,041 $20,890,475 150.80 ($326,931) $20,563,544 148.44 (1.56)%
6 Small General Service On-Site Generation 8 107 500,088 $74,134 148.24 ($1,180) $72,954 145.88 (1.59)%
7 Large General Service 9 39,293 3,954,934,403 $360,491,542 91.15 ($9,333,645) $351,157,897 88.79 (2.59)%
8 Dusk to Dawn Lighting 15 0 2,615,028 $1,352,653 517.26 ($6,171) $1,346,481 514.90 (0.46)%
9 Large Power Service 19 124 2,067,577,655 $156,904,282 75.89 ($4,879,483) $152,024,799 73.53 (3.11)%
10 Agricultural Irrigation Service 24 19,627 1,830,563,531 $185,503,555 101.34 ($4,320,130) $181,183,425 98.98 (2.33)%
11 Unmetered General Service 40 1,700 14,381,350 $1,491,502 103.71 ($33,940) $1,457,562 101.35 (2.28)%
12 Street Lighting 41 3,324 20,670,727 $3,863,385 186.90 ($48,783) $3,814,602 184.54 (1.26)%
13 Traffic Control Lighting 42 779 2,983,484 $248,426 83.27 ($7,041) $241,385 80.91 (2.83)%
14 Total Uniform Tariffs 617,534 13,810,444,160 $1,446,312,706 104.73 ($32,592,648) $1,413,720,057 102.37 (2.25)%

15 Total Special Contracts 5 1,320,822,394 $99,344,424 75.21 ($3,117,141) $96,227,283 72.85 (3.14)%

16 Idaho Power Supplied Retail Sales(2) 617,539 15,131,266,553 $1,545,657,130 102.15 ($35,709,789) $1,509,947,341 99.79 (2.31)%
TY Rev Forecast - June 2024 - May 2025
(2) Percentage impact does not include Franchise Fees or Black Mesa sales

Idaho Power Company
Calculation of Revenue Impact 2024
State of Idaho
PCA
Filed April 15, 2024
Summary of Revenue Impact
Current Billed Revenue to Proposed Billed Revenue

Percent
Rate Average Normalized Current Adjustments Proposed Change
Line Sch. Number of Energy Billed Mills to Billed Total Billed Mills Billed to Billed (2)
No Tariff Description No.Customers (1)(kWh) (1)Revenue Per kWh Revenue Revenue Per kWh Revenue

Uniform Tariff Rates:

1 Large General Secondary 9S 39,002 3,312,217,135 $307,142,518 92.73 ($7,816,832) $299,325,685 90.37 (2.55)%
2 Large General Primary 9P 288 638,224,106 $52,969,211 82.99 ($1,506,209) $51,463,002 80.63 (2.84)%
3 Large General Transmission 9T 3 4,493,162 $379,813 84.53 ($10,604) $369,209 82.17 (2.79)%
4 Total Schedule 9 39,293 3,954,934,403 $360,491,542 91.15 ($9,333,645) $351,157,897 88.79 (2.59)%

6 Large Power Secondary 19S 1 6,730,275 $551,693 81.97 ($15,883) $535,810 79.61 (2.88)%
7 Large Power Primary 19P 120 2,029,565,003 $154,056,978 75.91 ($4,789,773) $149,267,205 73.55 (3.11)%
8 Large Power Transmission 19T 3 31,282,377 $2,295,611 73.38 ($73,826) $2,221,784 71.02 (3.22)%
9 Total Schedule 19 124 2,067,577,655 $156,904,282 75.89 ($4,879,483) $152,024,799 73.53 (3.11)%

11 Irrigation Secondary 24S 19,627 1,830,563,531 $185,503,555 101.34 ($4,320,130) $181,183,425 98.98 (2.33)%
12 Irrigation Transmission 24T 0 0 $0 0.00 $0 $0 0.00 0.00%
13 Total Schedule 24 19,627 1,830,563,531 $185,503,555 101.34 ($4,320,130) $181,183,425 98.98 (2.33)%
TY Rev Forecast ‐ June 2024 ‐ May 2025
(2) Percentage impact does not include Franchise Fees or Black Mesa sales
Filed April 15, 2024

Summary of Revenue Impact - Rates 9, 19, and 24 Distribution Level Detail
Current Billed Revenue to Proposed Billed Revenue
Idaho Power Company
Calculation of Revenue Impact 2024
State of Idaho
PCA

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-24-17

IDAHO POWER COMPANY

CONFIDENTIAL
ATTACHMENT NO. 3

STAFF’S REPORT OF COAL ISSUES

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-24-17

IDAHO POWER COMPANY

ATTACHMENT NO. 4

ANALYSIS OF COAL SUPPLY ISSUES IN 2022
PCA YEAR

Analysis of Coal Supply 
Issues in the 2022 PCA Year  

Idaho Power’s Response to Staff’s Confidential 
Report Dated November 30, 2023 

 April 2024 

Idaho Power Company  
 Page i 
Table  of Contents 
Table of Contents ........................................................................................................................... i 
Executive Summary ....................................................................................................................... 1 
Background ............................................................................................................................. 1 
Staff’s Concerns....................................................................................................................... 1 
Idaho Power’s Response ......................................................................................................... 2 
Idaho Power’s Detailed Response ................................................................................................. 4 
Bridger Operational Requirements ......................................................................................... 4 
Monthly Operating Plan Process ............................................................................................. 4 
March 2022 Operating Plan .................................................................................................... 5 
Idaho Power’s Actions to Manage Coal Supply ....................................................................... 6 
Bridger Coal Company ....................................................................................................... 7 
Black Butte Coal ................................................................................................................ 7 
Utilization of Long‐Term, Contingency Coal Storage ......................................................... 8 
Powder River Basin ............................................................................................................ 8 
Actions at Valmy ................................................................................................................ 9 
Optimization of Coal Generation ........................................................................................... 10 
Company Analysis – Financial Impact to 2022‐2023 NPSE .................................................... 10 
Conclusion ............................................................................................................................. 11 

Idaho Power Analysis of Coal Supply Issues in the 2022 PCA Year 
 Page 1 
Executive Summary 
Background 
On April 14, 2023, Idaho Power Company (“Idaho Power” or “Company”) applied to the Idaho 
Public Utilities Commission (“Commission”) in Case No. IPC‐E‐23‐12 for authorization to 
implement its Power Cost Adjustment (“PCA”) rates in Schedule 55—Power Cost Adjustment 
(“Schedule 55”) effective June 1, 2023, through May 31, 2024. In Final Order No. 35804 issued 
on May 31, 2023, the Commission approved the Company’s application, subject to certain 
modifications, and directed Commission Staff (“Staff”) to investigate the prudency of the 
Company’s Net Power Supply Expenses (“NPSE”) related to coal supply issues and report its 
assessment to the Commission within six months of the Commission’s final order. On 
November 30, 2023, Commission Staff filed its “Confidential Staff Report” in Case No. IPC‐E‐23‐
12, in which Staff concluded that the Company did not prudently incur a portion of its 2022‐
2023 NPSE and recommended an adjustment to NPSE be considered in the Company’s next PCA 
filing.  

While the Company appreciates Staff’s review of this matter, it does not agree that an 
adjustment to NPSE is reasonable under the circumstances presented. To the contrary, as more 
fully described below, the Company moved expeditiously and judiciously to mitigate the 
challenges that arose from sustained market volatility and limited coal inventories in the region. 
Staff’s Concerns 
Staff states that given the increased coal forecast and corresponding coal inventory 
requirements for the 2022 PCA year,1 Idaho Power should have recognized the need to act 
promptly to review the Company’s coal inventory, including additional procurements needed to 
meet the forecast, however, “Staff believes the Company did otherwise.”2 More specifically, at 
Bridger, Staff believes that the Company took “only minor corrective actions for the first five 
months of the PCA year, thereby missing the opportunity for cost‐effective remedies.”3 At 
Valmy, on the other hand, Staff believes that the Company took reasonable actions to mitigate 
the shortfall, although the efforts were not successful.4 
Based on its assessment, Staff provides two recommendations, summarized as follows, for 
what the Company could have done differently to have prudently mitigated NPSE. 5  

1 In this document “2022 PCA Year” refers to the April 2022 through March 2023 time period that comprised the 
Balancing Adjustment portion of the PCA filed in Case No. IPC‐E‐23‐12. 
2 Confidential Staff Report – Page 7‐8 
3 Confidential Staff Report – Page 13 
4 Confidential Staff Report – Page 17 
5 Confidential Staff Report – Page 18 
Idaho Power Analysis of Coal Supply Issues in the 2022 PCA Year 
 Page 2 
1. If the Company had pursued a contract with Powder River Basin (“PRB”) in March 
instead of September, rail service may have been available, and the Company could 
have had additional coal as early as June 2022.  

2. If the Company had recognized in March that it could not procure the fuel needed to 
meet the generation requirements from the operating plan, it should have adjusted the 
forecast. This “would have triggered different decisions by the Company for hedging fuel 
or procuring long‐term power contracts at more favorable prices.” 
Idaho Power’s Response 
Global natural gas supply and demand disruptions stemming from the Russian invasion of 
Ukraine resulted in unprecedented price escalation and volatility in the natural gas and energy 
markets beginning in the spring of 2022. This resulted in the increased economic dispatch of 
Idaho Power’s two coal plants – Bridger and Valmy – in the Company’s March operating plan.  
In order to accommodate the increase in the economic dispatch of coal in the Company’s 
March operating plan, Idaho Power acted promptly to procure as much coal as possible for use 
in the 2022 PCA year.  
Idaho Power disagrees with Staff’s assertion that it did not take enough action to procure coal 
for Bridger early in the PCA year. To the contrary, Idaho Power’s additional coal procurements 
early in the PCA year allowed the Company to run Bridger unconstrained for the entirety of the 
summer season. In fact, in the first few months of the PCA year, Idaho Power procured all 
available coal from the two suppliers in the region – there was nothing more that could have 
been done to secure more coal from these sources.  
In addition, as system and market projections continued to indicate strong demand for coal into 
2023, the Company took the more extraordinary actions of drawing from its long‐term, 
contingency storage at Bridger and issuing a Request for Proposal (“RFP”) for coal from Powder 
River Basin.  
It is important to note that Bridger is designed to consume coal sourced specifically from 
southwest Wyoming with a heat content ranging between 9,000 and 10,000 British thermal 
units (“Btu”) per pound. The average heat content of coal from Powder River Basin ranges 
between 8,500 and 9,000 Btus per pound. In addition to its negative impacts to plant efficiency, 
PRB coal has a high propensity to spontaneously combust and is highly friable, therefore 
requiring additional care in unloading and handling. As a result, PRB coal had historically been 
considered only as an emergency fuel option. Rather than immediately attempt to procure coal 
that can only be handled on a limited basis due to plant design and blending limitations, Idaho 
Power chose to first monitor coal generation throughout the remainder of the spring and 
summer to determine if acquiring this non‐optimal coal supply would be necessary. Asserting 
that the Company should have issued an RFP immediately following the development of the 
Idaho Power Analysis of Coal Supply Issues in the 2022 PCA Year 
 Page 3 
March operating plan is based on the benefit of hindsight. In actuality, it was reasonable and 
prudent for the Company to defer pursuing PRB coal until circumstances warranted invoking 
this emergency fueling option. 
Ultimately, Idaho Power issued an RFP in September seeking coal from Powder River Basin to 
be delivered in Q4 2022. Unfortunately, securing railcars for delivery of PRB coal proved 
challenging. However, Staff’s argument that seeking railcar sets in March rather than 
September would have resulted in less lead time is purely speculative; the challenges the 
Company confronted in September would have likely existed in March.  
Lastly, Idaho Power disagrees with Staff’s statement that had it updated its coal forecast in 
March instead of September, it would have resulted in more favorable prices for hedging 
activity. While Idaho Power rejects this type of analysis on the basis of hindsight, it also found 
the opposite to be true. Had the Company updated its forecast in March, it would have likely 
resulted in less favorable prices for hedging activity, resulting in increased NPSE for the PCA 
year.  
Idaho Power provides additional detail on this analysis and its coal procurement actions 
throughout the 2022 PCA year in the following detailed report.   

Idaho Power Analysis of Coal Supply Issues in the 2022 PCA Year 
 Page 4 
Idaho Power’s Detailed Response 
Bridger Operational Requirements 
The Bridger plant, located near Rock Springs, Wyoming, consists of four generating units. 
PacifiCorp is the operator of the facility and has two‐thirds ownership. Idaho Power has one‐
third ownership.  
The plant was designed and constructed to burn sub‐bituminous coal sourced from southwest 
Wyoming with a heat content in the range of 9,000 to 10,000 Btus per pound. The Bridger plant 
is adjacent to Idaho Power and PacifiCorp’s co‐owned Bridger Coal Company mine, which 
currently supplies sub‐bituminous coal to the plant.  Aside from BCC, the only other significant 
source of fuel that is within the quality specifications for Bridger is the nearby Black Butte Coal 
Company (“Black Butte Coal”).  To supplement the Bridger plant’s fueling requirements, Idaho 
Power and PacifiCorp have historically relied on coal procured from Black Butte Coal, jointly 
entering into coal supply contracts which have ranged from 3 to 4‐year terms, or to 18‐month 
to two‐year terms most recently as planned exits of coal burning operations inch closer. 
Relying on BCC and Black Butte Coal as the traditional fuel sources at Bridger is not merely a 
matter of preference. Because the physical and chemical properties of coal can vary 
significantly, the type and source of coal are integral components of power plant operations 
and cannot be substituted without careful consideration of potential impacts to plant 
performance, cost, and need for facility modifications and/or operational changes.  
Coal from Powder River Basin has distinct properties compared to BCC and Black Butte Coal. 
Not only is PRB coal characterized by lower heating value due to its higher moisture content, 
but it is extremely friable, highly volatile, and particularly prone to spontaneous combustion. 
The specific attributes of PRB coal implicate issues with coal transport, handling, storage, 
combustion, ash deposits and other operational and maintenance matters as well as overall 
plant performance and costs, making it a suboptimal fueling option. Notwithstanding, Idaho 
Power determined that Bridger could safely and reliably use a limited amount of this particular 
coal each year if warranted by exigent circumstances. 

Monthly Operating Plan Process 
In order to consider the Company’s actions relative to the issues in this case, it is important to 
understand how the Company develops its monthly operating plan, which provides the basis for 
Idaho Power’s PCA forecast.   
Idaho Power’s monthly operating plan is developed in accordance with the Company’s Energy 
Risk Management Standards (“ERMS”), which define a systematic methodology to manage both 
the physical and financial exposures to business and market‐driven uncertainties within a 
defined and controlled framework and are intended to mitigate exposure to the volatility that 
Idaho Power Analysis of Coal Supply Issues in the 2022 PCA Year 
 Page 5 
can occur on a real‐time basis, while retaining necessary operational flexibility.  Among other 
things, the Company’s ERMS set forth guidelines for setting volumetric and financial exposure 
limits that dictate the Company’s allowed hedging activity, as well as the timing of when the 
Company can execute a hedge transaction.  
In accordance with the ERMS, the Company prepares mid‐term operational plans incorporating 
generation forecasts and associated fuel expense forecasts for its resources each month 
(beginning with the next month and extending at least 18 months). The procedures for 
developing the forecasts in accordance with the ERMS are prescriptive.  
After considering any minimum “must run” operational requirements and planned unit 
maintenance outages, economic coal generation is modeled by comparing reported 
Intercontinental Exchange (“ICE”) Mid‐Columbia (“Mid‐C”) forward power prices for the 
upcoming months to the projected coal unit dispatch price. If the operating cost of coal is less 
than the forward prices, the coal units are dispatched in the plan. 
Idaho Power’s Risk Management Committee (“RMC”) meets each month to review the 
operating plan, which includes any hedging transactions triggered by the market risk guidelines 
as defined in the ERMS. Since the inception of the ERMS, the Company has developed the 
operating plan based on an economic dispatch model, which includes an assumption that 
additional coal can be procured to meet the economic dispatch of its coal plants if needed. In 
addition, any hedging activity triggered from the risk guidelines was first reviewed against 
available coal capacity. If coal capacity was available, then it would not result in a firm hedge 
order.  

March 2022 Operating Plan 
The coal forecast prepared in mid‐March 2022 and included in the operating plan presented to 
the Risk Management Committee (“RMC”) at the March 31, 2022, RMC meeting was used to 
develop the 2022‐2023 PCA forecast for coal‐powered generation and fuel expense.   
During the first part of 2022, poor hydrological conditions coupled with global natural gas 
supply and demand disruptions from the Russian invasion of Ukraine led to price escalation and 
volatility in the natural gas and energy markets. This was documented in the Company’s 
operating plans in both February and March. More specifically, from the January to March 
operating plans, forward power prices had increased by 18 percent and gas prices at Sumas had 
increased by 24 percent. As a result, economic dispatch at Bridger and Valmy in the March 2022 
operating plan was relatively high compared to prior years. 
Pursuant to the ERMS framework, the Company included the higher level of economic coal 
generation in the March operating plan, despite coal inventory constraints, anticipating that 
additional coal could be obtained and that the natural gas and energy market volatility should 
stabilize in time, which would result in a natural (economic) reduction to coal generation in a 
future operating plan.  
Idaho Power Analysis of Coal Supply Issues in the 2022 PCA Year 
 Page 6 
Idaho Power’s Actions to Manage Coal Supply 
In the face of unprecedented volatile market conditions that drove an increase in coal 
generation and depletion of coal stockpiles, Idaho Power undertook prudent and appropriate 
steps to manage coal supply and procure additional coal to mitigate the impact to customers as 
summarized in the following timeline and detailed in the paragraphs that follow. 
TIME 
PERIOD 
ACTION TAKEN BY IDAHO POWER ADDITIONAL NOTES 
Mar‐22  
Apr‐22 
Bridger Coal Company 
 Idaho Power increased planned 
deliveries from BCC for 2022 by 
200,000 tons. 
Idaho Power’s prompt action to procure 292,333 
more tons than was contemplated in the original 
fueling plan allowed it to run Bridger unconstrained 
throughout the summer season, when market prices 
are generally highest. 
Jul‐22  Black Butte Coal 
 In finalizing contract negotiations with 
Black Butte Coal, Idaho Power secured 
92,333 more tons than was originally 
targeted. 
Aug‐22 Utilization of Long‐Term, Contingency Coal 
Storage 
 Idaho Power began utilizing coal 
inventory permitted for long‐term, 
contingency storage at Bridger. 

Inventory stockpiles ended in December 2022 and 
March 2023 at 8 and 6 days of full‐load operating 
supply, respectively. These are far below historical and 
optimal levels, which are 30 ‐ 45 days of supply.  
Sept‐22 Actions at Bridger – Powder River Basin 
 Idaho Power issued a Request for 
Proposal (“RFP”) for additional coal 
from Powder River Basin.  
As coal utilization continued to be higher than earlier 
projections, the Company pursued an emergency 
fueling option to incorporate PRB coal, which had 
never been used to fuel Bridger due to the significant 
care required to ship, receive, and handle the coal.   
Sept‐22 Optimization of Coal Generation 
 Idaho Power incorporated an 
optimization strategy in its operating 
plans after all reasonable efforts to 
procure additional coal had been 
exhausted. 
The Company adjusted the dispatch price of coal for 
forecasting purposes and optimally dispatched 
available coal to meet load during periods when 
forward market prices were highest, therefore 
allocating coal to times that are most economic. This 
optimization strategy resulted in additional hedge 
transactions in the fall. 
Idaho Power Analysis of Coal Supply Issues in the 2022 PCA Year 
 Page 7 
Bridger Coal Company 
The primary fuel source for Bridger is the BCC mine located adjacent to the plant. Previously the 
mine included both surface and underground mining operations, but underground operations 
ceased at the end of 2021.  
When coal generation stepped in as the less costly resource in 2022, Staff believes that the  
Company’s actions did not reflect the significance of this change, noting: “When the March 
2022 forecast called for 2.3 million tons of coal consumption, the Company didn’t take any 
extraordinary actions to procure additional coal.”6 Staff further asserted that the first clear 
change in the Company’s procurements did not occur until June.7  These characterizations, 
however, are not accurate.  
To the contrary, beginning in March 2022 and continuing over the ensuing months, Idaho 
Power quickly pivoted to address the changing circumstances and acted to procure all available 
coal from its sources. At BCC, rather than simply relying on planned operating levels of coal as 
Staff suggests, the Company ordered increases to planned deliveries, 133,000 tons in March 
and 67,000 tons in April. However, Staff incorrectly characterizes these deliveries as “essentially 
the amounts they intended to procure in its earlier plan.” 8  
The additional 200,000 tons of coal nominated from BCC for 2022 was provided from the 
mine’s stockpile of underground coal at BCC, which was originally earmarked for delivery to the 
plant through early 2024. The decision to accelerate the delivery of almost all remaining 
underground stockpile coal inventory at BCC was a clear change to the Company’s plan and was 
made in the spring of 2022 when it became apparent that demand for coal at Bridger was going 
to exceed earlier projections.  
Black Butte Coal 
In addition to accelerating the delivery of coal from BCC, during the spring of 2022, the 
Company was in the process of negotiating a new coal supply agreement with Black Butte Coal 
for deliveries beginning July 2022. While the original plan called for 179,000 tons, the contract 
executed on June 17, 2022,  was for all additional coal that Black Butte Coal could deliver to the 
plant for the July 2022 – December 2022 period, totaling 271,333 tons, which was 92,333 more 
than was originally targeted.  
The record reflects that the Company’s actions were commensurate with the circumstances; it 
secured all available coal from BCC and Black Butte Coal for use in the 2022 PCA year, which 
allowed Idaho Power to run Bridger unconstrained through the summer season. There were not 
additional actions that the Company could have taken, extraordinary or otherwise, to secure 
more coal from these sources.  

6 Confidential Staff Report – Page 12 
7 Confidential Staff Report – Page 12 
8 Confidential Staff Report – Page 12 
Idaho Power Analysis of Coal Supply Issues in the 2022 PCA Year 
 Page 8 
Utilization of Long‐Term, Contingency Coal Storage 
In August 2022, Idaho Power began utilizing coal from the sealed emergency stockpile 
inventory located at the Bridger plant, drawing from coal intended for long‐term, contingency 
storage to provide additional coal for economic dispatch.  As a result, inventory stockpiles at 
the plant ended December 2022 and March 2023 at 8 and 6 days of full‐load operating supply, 
respectively.  These levels are far below the optimal level of 30 – 45 days of full load operating 
days of supply that Idaho Power has historically maintained at the plant.     
Powder River Basin 
By September 2022, Idaho Power had secured all available coal that could operationally and  
logistically be provided, yet system and market projections continued to indicate strong 
demand for coal generation in 2023. As a result, the Company escalated its procurement 
efforts, issuing  an RFP to procure coal from the Powder River Basin, which was an emergency 
fueling option that had previously not been utilized due to its high propensity to spontaneously 
combust. At the same time, discussions were initiated with the railroads regarding the delivery 
of PRB coal and the availability of railroad owned rail sets.  
Securing railcars for delivery of PRB coal proved challenging. Both Union Pacific Railway (“Union 
Pacific”) and Burlington Northern Santa Fe (“BNSF”), the two railroad companies that haul coal 
out of PRB, were unable to provide service with their rail sets. As a result, PacifiCorp and Idaho 
Power began to explore options for leasing the required railcars.  
In September and October 2022, Idaho Power and PacifiCorp discussed with NV Energy the 
possibility of subleasing an extra set of railcars that NV Energy was leasing but was not using at 
that time. However, this ultimately was not a viable option because the leasing company was in 
the process of selling the cars and the new owner wouldn’t allow a sublease while the sale was 
pending.  
When this fell through, Idaho Power and PacifiCorp continued to search extensively for other 
options, reaching out to approximately 15 different utilities and railcar leasing companies 
during November and December. However, no available railcar sets were identified. Finally, in 
January 2023, Idaho Power and PacifiCorp located and leased a railcar set from Trinity Rail LLC, 
which could be dispatched to PRB beginning in the March and April 2023 timeframe.  
In suggesting that Idaho Power should have sought to augment coal inventory with PRB coal in 
March 2022,9 Staff’s report overlooks that PRB coal was considered by the Company to be an 
emergency fueling option to be pursued after other possibilities had been explored and 
exhausted. As more fully explained below, this approach was reasonable and appropriate under 
the circumstances. Even if the Company had pursued a contract with PRB earlier, it is entirely 
speculative to suggest that rail service would have been available. To the contrary, the 

9 Confidential Staff Report – Page 18 
Idaho Power Analysis of Coal Supply Issues in the 2022 PCA Year 
 Page 9 
Company believes it would have been presented with the same transportation challenges and 
lead time associated with transporting PRB coal had it pursued that option beginning March 
2022.  
In addition, both Union Pacific and BNSF have been criticized over the last few years for delays 
and failures to meet coal shipment terms. According to an article from Wyoming Public Media, 
railroads have cited labor issues and weather events as reasons for the delayed or reduced 
service to customers.10 In addition, an article from WyoFile from December 2022 states that 38 
out of 45 utilities reported that they had to reduce coal‐fired generation in 2022 due to issues 
with coal delivery.11  
Implementation challenges notwithstanding, it was reasonable and prudent for the Company to 
defer pursuing PRB coal until September 2022, when it determined that circumstances 
warranted invoking this emergency fueling option. With the benefit of hindsight, one might 
surmise that this option should have been pursued earlier. It is important to consider, however, 
the factors that would have been considered by the Company at the time it was making its 
decisions. At that point in time, PRB coal had never been utilized at Bridger as a base fuel 
supply source due to its high propensity to spontaneously combust, which requires significant 
care be taken to ship, receive, and handle. As a result, the plant is only capable of consuming 
PRB on a limited scale, safely, without significant incremental investments in coal handling 
modifications. Because the Company had procured enough coal to run Bridger unconstrained 
through the summer, it waited to take the more extreme measure of procuring coal from PRB 
until it saw what forward market conditions were in September.  
Actions at Valmy   
At Valmy, Staff believes that the Company acted prudently in its efforts to secure additional 
coal in a timely manner. Staff notes that, “the Company showed early awareness of the coal 
inventory problems at Valmy and pursued reasonable and timely actions to mitigate the 
shortfall”12. Staff remained concerned, however, with what it perceived to be a lack of 
attention to these circumstances at the RMC, believing that “earlier recognition of the coal 
situation at the proper level could have led to NPSE savings by putting appropriate mitigation in 
place.”13 The Company is assuming that the “appropriate mitigation” that Staff is referencing is 
a change to the coal forecast in the March operating plan. Idaho Power addresses this point 
later in this report.  

10 https://www.wyomingpublicmedia.org/natural‐resources‐energy/2023‐03‐29/bnsf‐has‐drawn‐criticism‐from‐a‐
wyoming‐lawmaker‐amid‐a‐decline‐in‐coal‐shipments 
11 https://wyofile.com/railroad‐under‐fire‐for‐costly‐decrease‐in‐coal‐shipments/ 
12 Confidential Staff Report – Page 17. 
13Id at 6.  
Idaho Power Analysis of Coal Supply Issues in the 2022 PCA Year 
 Page 10 
Optimization of Coal Generation 
In late September 2022, natural gas and energy prices remained high, below normal hydro 
conditions persisted, and coal supply constraints continued, prompting Idaho Power to pursue 
resource optimization strategies to mitigate the impact . To this end, the Company adjusted the 
dispatch price of coal for forecasting purposes and optimally dispatched available coal to meet 
load during periods when forward market prices were highest, therefore allocating coal to 
times that are most economic.  

This optimization strategy was incorporated in the Company’s operating plans after all 
reasonable efforts to procure additional coal had been exhausted. Ultimately, it resulted in 
additional hedge transactions in the fall. As detailed in the meeting minutes of the September, 
October, and November RMC meetings, the Company continued to monitor the impact that the 
revised coal forecast had on the resource stack, including the resulting increase in triggered 
hedging activity. In addition, on October 26, 2022, Idaho Power met with Commission Staff to 
discuss the coal supply situation. In its presentation, the Company informed Staff on the factors 
that led to the limited coal supply and the Company’s plan for coal dispatch going into 2023, 
including the recent change to the coal dispatch.  
Company Analysis – Financial Impact to 2022‐2023 NPSE 
Staff’s ultimate determination that the Company was not fully prudent is premised, in part, on 
its belief that if the Company recognized in March that it could not meet the coal generation 
requirements, it could have adjusted its forecasts accordingly.  “Reduced coal generation 
forecasts would have raised the forecast requirements for gas generation and market 
purchases, which would have triggered different decisions by the Company for hedging fuel or 
procuring long‐term power contracts at more favorable prices.”14 While retroactively 
deconstructing the series of events and decisions that influenced a particular outcome may be a 
valuable source of lessons learned, it does not provide a reasonable basis for evaluating the 
prudency of decisions that were made in real time without the benefit of hindsight.   
Moreover, even assuming, for the sake of argument, that the Company had adjusted its March 
operation plan to limit coal generation, it does not necessary follow that this change would 
have reduced NPSE.  
In order to determine the potential impact, if any, to NPSE had the Company updated its coal 
forecast in March instead of September, the Company performed an analysis using the 
methodology described in Attachment 5. The analysis itself is provided in Confidential 
Attachment 6. Ultimately, Idaho Power concluded that had it updated its coal forecast in March 
instead of September, it would have resulted in an overall increase to NPSE of $2.7 ‐ $5.6 
million. In other words, customers did not experience any financial harm as a result of the 
Company’s actual course of action.  

14 Confidential Staff Report – Page 18 
Idaho Power Analysis of Coal Supply Issues in the 2022 PCA Year 
 Page 11 
Conclusion 
While Staff’s report acknowledges the unique circumstances encountered by the Company 
during the 2022 PCA year, it does not adequately reflect the timing or scope of the proactive 
measures undertaken by the Company to address limited coal availability and turbulent market 
conditions. As demonstrated in this report, when Idaho Power became aware of the coal 
constraint issues, the Company took immediate action to procure more coal from its two 
suppliers, including accelerating the delivery of stockpiled coal at BCC and pursuing additional 
coal from Black Butte Coal. This resulted in 292,333 more tons than was contemplated in the 
fueling plan that was finalized in late 2021. The Company’s swift actions in this regard enabled 
it to run Bridger at full capacity throughout the summer.  
As price escalation and volatility in the gas and power markets continued to drive generation at 
Bridger and as coal supplies became more constrained, the Company escalated its response 
accordingly by drawing from coal intended for long‐term, contingency storage at the Bridger 
plant and issuing an RFP in September 2022 to procure coal from Powder River Basin. PRB coal 
had not historically been used to fuel the plant and was considered an emergency option due to 
the additional care required to ship, receive, and handle it. Arranging for delivery of the coal 
presented additional challenges, which Idaho Power and PacifiCorp worked diligently to 
address and ultimately were able to arrange rail transport for coal in the spring of 2023. In the 
meantime, while working to secure transportation of PRB coal, the Company took an additional 
initiative to mitigate the impact of limited coal inventories, employing an optimization strategy 
to ensure the most cost‐effective operation of the coal plants under the constrained 
circumstances.  
The volatile market conditions in the spring of 2022 were unprecedented in recent history. The 
March operating plan was developed just weeks after the Russian invasion of Ukraine, and 
Idaho Power could not predict how the conflict would play out over the next several months. As 
a result, it chose to leave the forecasted economic dispatch of coal in the March operating plan 
and continue to monitor conditions over the next few months. As illustrated by Idaho Power’s 
counterfactual analysis, keeping the economic dispatch of coal in the March operating plan 
ultimately led to lower NPSE than if the Company had updated coal dispatch levels as Staff 
recommended, and thus, no reasonably preventable financial harm was experienced by 
customers as a result of this approach. 
Overall, even in hindsight, Idaho Power believes its actions to mitigate NPSE in the 2022 PCA 
year were swift and prudent, despite the challenges that arose from sustained market volatility 
and limited coal inventories in the region. Therefore, Idaho Power does not believe that any 
adjustment to NPSE is reasonable.   

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-24-17

IDAHO POWER COMPANY

ATTACHMENT NO. 5

DESCRIPTION OF COUNTERFACTUAL
ANALYSIS
Counterfactual Analysis – Method 
1. Determine the additional hedge orders that would have been triggered. 
The first step of the analysis was to determine the additional firm hedge orders that would have been 
triggered in the March operating plan if Bridger’s generation was constrained to only coal supplies that 
were available.  
First, the Company compared the 2022 PCA coal generation forecast to the coal volume that ended up 
being procured for that period. A coal shortfall of approximately 775,000 tons or 1.6 million MWh was 
identified.  
Next, the Company determined which months that coal generation would have been reduced based on 
forward monthly Mid‐C heavy load (“HL”) and light load (“LL”) prices in March. Coal burn was restricted 
to the periods where the value of replacement energy was anticipated to be the highest.  
Lastly, the Company counterfactually identified the additional HL and LL hedge orders that would have 
been triggered in the March operating plan. The breakdown of HL and LL additional orders by month are 
included in Table 1 below.  
Table 1: Identified Tier 2 Firm HL and LL Hedges ‐ MWh 
 2022  2023   
  May June October November  March 
HL  33,148  162,987  116,986  0  47,985  
LL 0  0  123,611  161,193  78,302  

2. Determine the purchase price for the additional hedges. 
The next step of the analysis is to determine the estimated purchase price that Idaho Power would have 
paid for these March hedges. Because the Company could have hedged with either power or gas, it 
performed a counterfactual analysis for both scenarios.  
For power, Idaho Power calculated the average HL and LL forward market price for each month from 
trade dates spanning April 8 – May 31.1 The calculated average monthly HL and LL forward prices are 
provided in Table 2 below. 
Table 2: Average of Daily Forward Mid‐C Prices (Spring 2022) 
 2022 2023 
  May June October November  March 
HL  $55.36  $49.06  $83.68  $87.43  $62.82  
LL $43.38  $25.82  $75.66  $77.52  $50.78  

1 Idaho Power is assuming that the Merchant group would have realistically begun executing hedges from the 
March Op Plan beginning the second week in April. For the May forward month, prices from trade dates April 8 – 
April 29 were utilized.  

For gas, Idaho Power calculated the average ICE forward price at Henry Hub, adjusted for the forecast 
Sumas basis, for the same trade dates. An estimated dispatch price was calculated based on Langley 
Gulch’s average heat rate of 6,800 Btu/kWh. The calculated average monthly forward gas dispatch 
prices are provided in Table 3 below. 
Table 3: Average of Daily Forecast Gas Dispatch Prices (Spring 2022) 
2022 2023 
May June October November  March 
$41.88  $51.02  $51.63  $57.53  $29.25  

3. Estimate cost actually incurred for the equivalent MWh. 
Next, Idaho Power determined the best way to estimate the actual costs incurred by the Company to 
procure the equivalent power or gas. For May, June, and October, the Company is assuming it would 
have procured the energy in the real time market. For November and March, the Company is assuming 
that it procured the energy via hedge transactions that were triggered in the September Op Plan.2 
To estimate the price of power that Idaho Power would have paid in the real‐time bilateral market in 
May, June, and October, Idaho Power calculated the average HL and LL daily index settlement price for 
each month. These are included in Table 4 below.  
Table 4: Monthly Average Daily Index Settlement Price ‐ Power 
  May June October 
HL  $61.87  $35.71  $72.05  
LL $48.31  $4.64  $63.04  

To estimate the price of gas that Idaho Power would have paid in the real‐time market in May, June, and 
October, Idaho Power calculated the average daily index settlement price at Sumas for each month. 
These are included in Table 5 below.  
Table 5: Monthly Average Daily Index Settlement Price ‐ Gas 
May June October 
$50.81  $46.90  $34.88  

As stated previously, Idaho Power is assuming that it procured the equivalent November and March 
energy via hedge transactions executed from the September Op Plan. Therefore, to estimate the prices 
that the Company actually paid for the equivalent energy, it utilized forward prices from trade dates 
October 7th – 26th.  

2 Idaho Power began optimizing coal generation in September 2022. As a result, the September Op Plan resulted in 
triggers for both November and March due to the reduction of forecast coal‐fired generation.  
Table 6: Average of Daily Forward Mid‐C Prices (Fall 2022) 
  November March 
HL  $70.48  $69.50  
LL $60.03  $73.23  

Table 7: Average of Daily Forecast Gas Dispatch Prices (Fall 2022) 
November March 
$40.82  $36.77  

4. Calculate the estimated impact that the additional hedges would have had on NPSE. 
By comparing the forward prices in Spring 2022 to the estimated prices that Idaho Power actually paid 
for the equivalent MWh, Idaho Power calculated the estimated impact that hedging the additional 
energy in Spring 2022 would have had on NPSE for the 2022 PCA year. Ultimately, Idaho Power 
concluded it would have resulted in an overall increase in NPSE . This is the case for both the power and 
gas scenario. Table 8 below shows the estimated financial impact of the additional hedges to NPSE. 
Table 8: Financial Impact of Increased Hedges to NPSE 
2022 2023 
  May June October November  March Total 
Power ($215,948) $2,176,385  $2,919,132  $2,820,525 ($2,078,217) $5,621,878 
Gas ($296,059) $671,224  $4,027,237  ($2,694,778) $948,894 $2,656,517 

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-24-17

IDAHO POWER COMPANY

CONFIDENTIAL
ATTACHMENT NO. 6

COUNTERFACTUAL ANALYSIS

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-24-17
IDAHO POWER COMPANY
BRADY, DI
TESTIMONY
EXHIBIT NO. 1
Line No. FERC Account April May June July August September October November December January February March Annual
95% Sharing Accounts
1 Hydroelectric Generation (MWh)984,013 1,014,012 840,054 580,097 533,664 525,889 376,759 368,488 490,260 498,374 469,152 612,417 7,293,179
Account 536, Water for Power
2 Total Expense -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$
Account 501, Coal
Jim Bridger
3 Energy (MWh) 90,468 32,238 145,785 245,367 245,367 237,452 245,367 237,452 245,367 245,367 221,622 225,522 2,417,371
4 Total Expense 2,871,016$ 945,751$ 4,603,392$ 7,898,826$ 7,943,000$ 7,693,577$ 7,951,834$ 7,692,152$ 7,947,417$ 8,334,677$ 7,660,886$ 7,854,302$ 79,396,827$
North Valmy
5 Energy (MWh) (0) - - 56,892 87,108 80,561 87,104 84,294 87,104 87,104 78,674 (0) 648,841
6 Total Expense 332,698$ 332,698$ 332,698$ 3,293,293$ 4,877,353$ 4,505,872$ 4,860,741$ 4,682,835$ 4,825,208$ 4,855,438$ 4,447,480$ 332,698$ 37,679,017$
Account 547, Other Fuel
Langley Gulch
7 Energy (MWh) 174,453 28,052 207,200 210,704 211,056 208,320 41,718 215,505 227,040 226,896 202,080 120,492 2,073,516
8 Total Expense 2,613,583$ 741,628$ 3,069,456$ 5,672,395$ 5,410,032$ 5,221,659$ 1,061,272$ 7,844,304$ 10,443,023$ 11,057,701$ 9,613,294$ 3,649,775$ 66,398,122$
Bridger Gas
9 Energy (MWh) - - - 147,766 81,537 83,441 84,223 - 154,144 137,923 32,497 - 721,530
10 Total Expense -$33,476 -$33,476 -$33,476 $4,595,181 $2,828,501 $2,549,886 $2,486,104 $291,204 $11,604,917 $10,467,898 $2,318,886 $301,830 37,343,977$
Danskin
11 Energy (MWh) - - - 120,680 121,032 44,016 78,816 - 51,440 56,744 8,352 - 481,080
12 Total Expense 188,260$ 188,260$ 181,598$ 5,495,380$ 5,257,425$ 2,031,590$ 3,096,800$ 181,598$ 3,803,819$ 4,398,665$ 867,110$ 188,260$ 25,878,765$
Bennett Mountain
13 Energy (MWh) - - - 118,488 125,496 - 41,496 41,112 32,336 - - - 358,928
14 Total Expense 92,724.99$ 92,724.99$ 89,443.76$ 5,277,150.27$ 5,324,428.59$ 89,443.76$ 1,608,948.27$ 2,442,656.48$ 2,385,670.75$ 92,724.99$ 92,724.99$ 92,724.99$ 17,681,367$
Account 555, Purchased Power Non-PURPA
15 Energy (MWh) 154,437 95,729 206,462 203,717 138,109 89,501 77,522 169,317 100,158 92,938 121,704 128,377 1,577,970
16 Total Expense 7,247,733$ 3,873,409$ 8,205,246$ 12,155,377$ 7,780,932$ 4,681,890$ 5,038,880$ 13,197,004$ 8,771,299$ 6,679,661$ 8,160,739$ 5,016,979$ 90,809,149$
Account 565, 3rd Party Transmission
17 Total Expense 484,900$ 642,929$ 979,873$ 1,588,903$ 1,413,041$ 763,336$ 1,063,909$ 675,368$ 735,071$ 773,786$ 810,920$ 486,974$ 10,419,009$
Account 447, Surplus Sales
18 Energy (MWh) (504,188) (114,532) (114,102) (48,368) (49,256) (135,907) (57,956) (17,855) (68,817) (78,661) (56,303) (60,179) (1,306,125)
19 Total Expense (20,401,610)$ (4,333,683)$ (5,979,539)$ (4,029,466)$ (4,873,012)$ (12,237,123)$ (3,550,765)$ (2,821,347)$ (8,233,743)$ (7,219,658)$ (6,810,908)$ (5,564,599)$ (86,055,453)$
100% Sharing Accounts
Account 555, PURPA
20 Energy (MWh) 287,513 300,952 296,853 281,342 269,878 229,984 221,701 171,622 188,068 200,471 228,193 244,581 2,921,156
21 Total Expense 15,984,371$ 16,481,737$ 21,588,102$ 24,318,489$ 24,037,578$ 17,360,119$ 16,703,289$ 15,726,756$ 17,639,259$ 16,286,900$ 18,511,882$ 14,955,194$ 219,593,677$
Account 555, Demand Response Incentives
22 Total Expense -$ -$ 270,468$ 3,047,657$ 4,657,950$ 1,277,208$ 184,487$ 973,763$ -$ -$ -$ -$ 10,411,533$
95% Sharing Accounts (6,604,171)$ 2,450,240$ 11,448,693$ 41,947,040$ 35,961,700$ 15,300,131$ 23,617,722$ 34,185,774$ 42,282,682$ 39,440,893$ 27,161,132$ 12,358,944$ 279,550,780$
100% Sharing Accounts 15,984,371$ 16,481,737$ 21,858,570$ 27,366,146$ 28,695,528$ 18,637,327$ 16,887,776$ 16,700,519$ 17,639,259$ 16,286,900$ 18,511,882$ 14,955,194$ 230,005,210$
23 Total Net Power Supply Expense 9,413,676$ 18,965,452$ 33,340,739$ 64,718,005$ 61,828,727$ 31,387,572$ 38,019,395$ 50,595,089$ 48,317,024$ 45,259,895$ 43,354,129$ 27,012,309$ 509,555,990$
24 Total Generation (MWh) 1,690,885 1,470,982 1,696,354 1,965,052 1,813,247 1,499,162 1,254,705 1,287,790 1,575,915 1,545,816 1,362,273 1,331,390 18,493,571
25 Total Load (MWh) 1,186,696 1,356,450 1,582,253 1,916,684 1,763,991 1,363,255 1,196,749 1,269,935 1,507,098 1,467,155 1,305,970 1,271,211 17,187,446
APRIL 1, 2024 - MARCH 31, 2025
IDAHO POWER PCA FORECAST
Exhibit No. 1
Case No. IPC-E-24-17
J. Brady, IPC
Page 1 of 1
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-24-17
IDAHO POWER COMPANY
BRADY, DI
TESTIMONY
EXHIBIT NO. 2
Power Cost Adjustment
April 2023 thru March 2024
April May June July August September October November December January February March Totals
Idaho Jurisdiction Net Power Supply Expense (Non-QF)
Actual Non-QF
Fuel Expense-Coal 2,221,982.74 3,006,071.09 3,437,223.59 12,886,895.53 11,461,334.14 7,444,181.67 15,680,984.56 8,559,225.36 13,738,240.92 10,268,546.59 6,808,703.71 4,172,539.41 99,685,929.31
Fuel Expense-Gas 7,084,049.35 5,632,516.53 9,664,980.87 16,368,505.15 15,390,577.21 8,095,915.38 4,831,072.03 14,413,078.28 26,189,452.80 38,423,877.14 15,831,447.36 9,968,343.12 171,893,815.22
Non-Firm Purchases 13,612,936.00 12,063,983.02 17,058,770.81 30,288,116.14 26,184,632.46 11,304,712.44 11,979,506.45 17,926,344.45 15,702,529.69 38,520,410.04 15,102,861.53 8,985,321.92 218,730,124.95
Third Party Transmission 716,175.77 602,066.71 535,012.88 1,176,942.34 1,008,219.06 768,675.58 1,746,235.99 849,206.95 904,819.59 751,248.84 787,301.02 777,689.06 10,623,593.79
Surplus Sales & Transmission Losses (14,249,788.30) (13,613,311.21) (11,301,514.81) (1,879,447.33) (5,179,737.42) (5,343,609.05) (9,474,443.50) (14,859,598.98) (9,842,557.98) (42,573,490.54) (18,602,476.72) (13,835,943.58) (160,755,919.42)
Water for Power (Leases)- - - - - - - - - - - - -
Total Actual NPSE $ 9,385,355.56 7,691,326.14 19,394,473.34 58,841,011.83 48,865,025.45 22,269,876.02 24,763,355.53 26,888,256.06 46,692,485.02 45,390,592.07 19,927,836.90 10,067,949.93 340,177,543.85
Idaho Allocation 95.7% 95.8% 95.7% 96.4% 95.9% 96.2% 95.9% 95.4% 95.4% 95.5% 95.7% 95.9%
Net Idaho Jurisctional Actual Non-QF $ 8,981,785.27 7,368,290.44 18,560,510.99 56,722,735.40 46,861,559.41 21,423,620.73 23,748,057.95 25,651,396.28 44,544,630.71 43,348,015.43 19,070,939.91 9,655,163.98 325,936,706.50
Base Non-QF
Fuel Expense-Coal $ 7,525,242.00 7,487,643.00 9,019,153.00 11,385,255.00 12,185,412.00 10,796,845.00 7,781,442.00 7,302,324.00 8,455,019.00 5,483,866.09 5,225,193.36 4,796,697.48 97,444,091.93
Fuel Expense-Gas $ 2,314,209.00 2,302,646.00 2,773,625.00 3,501,263.00 3,747,333.00 3,320,312.00 2,392,997.00 2,245,656.00 2,600,139.00 10,014,265.74 9,541,895.08 8,759,404.84 53,513,745.65
Non-Firm Purchases $ 4,342,083.00 4,320,388.00 5,204,073.00 6,569,319.00 7,031,012.00 6,229,805.00 4,489,910.00 4,213,459.00 4,878,566.00 8,324,601.37 7,931,931.79 7,281,467.80 70,816,615.95
Third Party Transmission $ 378,398.00 376,507.00 453,517.00 572,494.00 612,729.00 542,907.00 391,281.00 367,189.00 425,151.00 858,960.68 818,443.70 751,326.61 6,548,904.00
Surplus Sales $(3,588,093.00) (3,570,166.00) (4,300,402.00) (5,428,577.00) (5,810,099.00) (5,148,019.00) (3,710,251.00) (3,481,805.00) (4,031,418.00) (2,903,030.97) (2,766,095.65) (2,539,259.91) (47,277,216.54)
Water for Power (Leases) $ 165,106.00 164,281.00 197,883.00 249,796.00 267,352.00 236,886.00 170,727.00 160,216.00 185,506.00 0.00 0.00 0.00 1,797,753.00
Idaho Base NPSE $ 11,136,945.00 11,081,299.00 13,347,849.00 16,849,550.00 18,033,739.00 15,978,736.00 11,516,106.00 10,807,039.00 12,512,963.00 21,778,662.91 20,751,368.28 19,049,636.81 182,843,894.00
Idaho Allocation 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.57% 95.57% 95.57%
Net Idaho Jurisdiction 95% Items $ 10,580,097.75 10,527,234.05 12,680,456.55 16,007,072.50 17,132,052.05 15,179,799.20 10,940,300.70 10,266,687.05 11,887,314.85 20,813,868.14 19,832,082.66 18,205,737.90 174,052,703.40
Idaho Jurisdiction Change From Base $ (1,598,312.48) (3,158,943.61) 5,880,054.44 40,715,662.90 29,729,507.36 6,243,821.53 12,807,757.25 15,384,709.23 32,657,315.86 22,534,147.29 (761,142.75) (8,550,573.92) 151,884,003.10
Sharing Percentage 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0%
Net Power Supply Expense Deferral ①$(1,518,396.86)(3,000,996.43) 5,586,051.72 38,679,879.76 28,243,031.99 5,931,630.45 12,167,369.39 14,615,473.77 31,024,450.07 21,407,439.93 (723,085.61) (8,123,045.22) 144,289,802.96
Idaho Jurisdictional Qualifying Facility NPSE
Actual QF (Includes Net Metering, Raft River 100% & Liquidated Damages)$ 16,401,337.57 13,300,989.58 17,636,195.14 23,467,171.34 22,980,416.01 17,241,806.00 16,357,011.20 13,643,091.85 15,759,446.92 17,281,218.32 16,967,890.11 12,465,314.51 203,501,888.55
Idaho Allocation 95.7% 95.8% 95.7% 96.4% 95.9% 96.2% 95.9% 95.4% 95.4% 95.5% 95.7% 95.9%
Idaho Jurisctional Actual QF $ 15,696,080.05 12,742,348.02 16,877,838.75 22,622,353.17 22,038,218.95 16,586,617.37 15,686,373.74 13,015,509.62 15,034,512.36 16,503,563.50 16,238,270.84 11,954,236.62 194,995,922.99
Base QF $ 9,283,440.00 9,237,057.00 11,126,388.00 14,045,307.00 15,032,413.00 13,319,420.00 9,599,498.00 9,008,440.00 10,430,450.00 17,948,022.13 17,101,417.96 15,699,003.40 151,830,856.49
Idaho Allocation 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.57% 95.57% 95.57%
Idaho Jurisdictional Base $ 8,819,268.00 8,775,204.15 10,570,068.60 13,343,041.65 14,280,792.35 12,653,449.00 9,119,523.10 8,558,018.00 9,908,927.50 17,152,924.75 16,343,825.15 15,003,537.55 144,528,579.80
Idaho Jurisdiction Change From Base $ 6,876,812.05 3,967,143.87 6,307,770.15 9,279,311.52 7,757,426.60 3,933,168.37 6,566,850.64 4,457,491.62 5,125,584.86 (649,361.25) (105,554.31) (3,049,300.93) 50,467,343.19
Sharing Percentage 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
QF Deferral ②$ 6,876,812.05 3,967,143.87 6,307,770.15 9,279,311.52 7,757,426.60 3,933,168.37 6,566,850.64 4,457,491.62 5,125,584.86 (649,361.25) (105,554.31) (3,049,300.93) 50,467,343.19
Idaho Revenue Adjustment (SBAR)
Actual Idaho Jurisdictional Billing Month Sales MWh 1,079,076 1,078,897 1,243,540 1,506,736 1,665,023 1,405,767 1,074,008 1,009,195 1,144,193 1,229,509 1,200,336 1,114,051 14,750,331
Normalized Idaho Jurisdictional Billing Month Sales MWh 947,192 953,286 1,131,686 1,370,142 1,428,766 1,300,608 1,045,495 957,864 1,081,014 1,263,248 1,210,192 1,106,864 13,796,357
Sales Change MWh 131,884 125,611 111,854 136,594 236,257 105,159 28,513 51,331 63,179 (33,739) (9,856) 7,187 953,974
% of Prior Period Billings at Old Rate-effective thru 12/2023 26.72$ 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 58.425% 0.786% 0.000%
% of Current Period Billings at New Rate-effective 01/2024 30.90$ 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 41.600% 99.200% 100.000%
Sales Adjustment Prior To Sharing @ $(3,523,950.16) (3,356,314.10) (2,988,746.58) (3,649,793.13) (6,312,780.62) (2,809,857.48) (761,859.82) (1,371,567.66) (1,688,151.06)960,407.85 304,189.30 (222,064.65) (25,420,488.11)
Sharing Percentage 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0%
Idaho Revenue Adjustment (SBAR) ③$(3,347,752.65) (3,188,498.40) (2,839,309.25) (3,467,303.47) (5,997,141.59) (2,669,364.61) (723,766.83) (1,302,989.28) (1,603,743.51)912,387.46 288,979.84 (210,961.42) (24,149,463.71)
Idaho Jurisdcitional Demand Response Incentive Payments
Idaho Actual Demand Response $ 90.32 103.84 190,860.22 2,459,729.26 2,713,656.90 1,850,742.44 1,212,407.52 27,315.09 - - - - 8,454,905.59
Idaho Base Demand Response $ 780,401.00 776,502.00 935,327.00 1,180,702.00 1,263,682.00 1,119,681.00 806,970.00 757,284.00 876,823.00 857,024.33 816,598.69 749,632.90 10,920,627.92
Change From Base $(780,310.68) (776,398.16) (744,466.78) 1,279,027.26 1,449,974.90 731,061.44 405,437.52 (729,968.91) (876,823.00) (857,024.33) (816,598.69) (749,632.90) (2,465,722.33)
Sharing Percentage 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
Change From Base ④$(780,310.68) (776,398.16) (744,466.78)1,279,027.26 1,449,974.90 731,061.44 405,437.52 (729,968.91) (876,823.00) (857,024.33) (816,598.69) (749,632.90) (2,465,722.33)
Idaho Miscellaneous Revenue
System Emission Allowance Sales Credit $ - - - - - - - - - - - - -
System Renewable Energy Credit Sales $(630,210.04) (259,069.46) 335.82 (364,192.90) (1,649,463.00) (84,934.41) (163,816.01) (28,547.22) (3,835,483.45) (6,144,859.78) (5,124,642.59) (159,687.15) (18,444,570.19)
Revenue Subtotal $(630,210.04) (259,069.46)335.82 (364,192.90) (1,649,463.00) (84,934.41) (163,816.01) (28,547.22) (3,835,483.45) (6,144,859.78) (5,124,642.59) (159,687.15) (18,444,570.19)
Idaho Allocation 95.7% 95.8% 95.7% 96.4% 95.9% 96.2% 95.9% 95.4% 95.4% 95.5% 95.7% 95.9%
Sharing Percentage 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0%
Miscellaneous Revenue Deferral ⑤$(572,955.46) (235,779.12)305.31 (333,527.86) (1,502,743.27) (77,621.56) (149,244.58) (25,872.35) (3,476,098.65) (5,574,924.04) (4,659,068.81) (145,482.98) (16,753,013.37)
Exhibit No. 2
Case No. IPC-E-24-17
J. Brady, IPC
Page 1 of 2
Idaho EIM Participation Costs
Return on EIM Capital Investment $ 28,871.58 28,222.16 27,572.73 26,923.30 26,273.88 25,624.45 24,975.02 24,325.60 23,676.17 - - - 236,464.90
Operating Expenses $ 167,711.80 184,168.76 174,913.14 183,130.19 215,392.32 262,228.23 212,616.66 155,300.39 164,197.09 - - - 1,719,658.58
Revenue Subtotal $ 196,583.38 212,390.91 202,485.87 210,053.50 241,666.20 287,852.68 237,591.68 179,625.99 187,873.26 0.00 0.00 0.00 1,956,123.47
Sharing Percentage 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 0.0% 0.0% 0.0%
EIM Revenue Requirement ⑥$ 186,754.21 201,771.37 192,361.58 199,550.82 229,582.89 273,460.05 225,712.10 170,644.69 178,479.60 0.00 0.00 0.00 1,858,317.31
TOTAL DEFERRAL (Sum of ①-⑥) $ 844,150.61 (3,032,756.87)8,502,712.73 45,636,938.03 30,180,131.52 8,122,334.14 18,492,358.24 17,184,779.54 30,371,849.37 15,238,517.77 (6,015,327.58) (12,278,423.45)153,247,264.05
PCA Forecasted Revenues
Actual Idaho Jurisdictional Billing Month Sales MWh 1,079,076 1,078,897 1,243,540 1,506,736 1,665,023 1,405,767 1,074,008 1,009,195 1,144,193 1,229,509 1,200,336 1,114,051 14,750,331
% of Prior Period Billings at Old Rate 100.000% 100.000% 58.321% 1.563% 0.000% 0.000% 0.000% 0.000% 0.000% 58.425% 0.786% 0.000%
% of Current Period Billings at New Rate 0.000% 0.000% 41.700% 98.400% 100.000% 100.000% 100.000% 100.000% 100.000% 41.600% 99.200% 100.000%
Forecast Rate Revenues ⑦(12,259,386.52) (12,257,343.81) (15,642,099.90) (21,950,132.14) (24,262,717.74) (20,489,411.26) (15,652,952.14) (14,707,632.03) (16,673,307.14) (12,700,800.30) (4,216,873.09) (3,844,373.82) (174,657,029.89)
PCA Balancing Account Balance
Monthly Interest Rate 2% for 2023 and 5% for 2024 % 0.1667% 0.1667% 0.1667% 0.1667% 0.1667% 0.1667% 0.1667% 0.1667% 0.1667% 0.4167% 0.4167%0.4167% 2.7500%
Beginning Balance 190,205,568.62$ 176,366,072.47 158,628,085.50 146,720,978.03 161,097,764.80 156,699,273.09 135,654,963.94 131,890,644.72 128,177,579.55 134,815,898.27 130,106,737.33 112,709,561.34 190,205,568.62
2023-2024 Incremental Deferral (Sum of ①-⑥ above 844,150.61 (3,032,756.87)8,502,712.73 45,636,938.03 30,180,131.52 8,122,334.14 18,492,358.24 17,184,779.54 30,371,849.37 15,238,517.77 (6,015,327.58) (12,278,423.45) 153,247,264.05
2023-2024 PCA Forecast Revenues (Collections) ⑦ above (12,259,386.52) (12,257,343.81) (15,642,099.90) (21,950,132.14) (24,262,717.74) (20,489,411.26) (15,652,952.14) (14,707,632.03) (16,673,307.14) (12,700,800.30) (4,216,873.09) (3,844,373.82) (174,657,029.89)
2023-2024 PCA Prior Balance Revenues (Collections)(2,741,269.52) (2,741,829.74) (5,032,100.44) (9,554,554.08) (10,584,401.76) (8,938,397.49) (6,829,816.93) (6,410,030.42) (7,273,852.81)(7,808,611.32) (7,707,086.73) (7,085,199.72) (82,707,150.96)
Revenue Sharing - Order No. - - - - - - - - - - - - -
DSM Rider Forecasted Surplus Funds - Order No. - - - - - - - - - - - - -
2023-2024 Ending Balance Without Current Month Interest 176,049,063.19 158,334,142.05 146,456,597.89 160,853,229.84 156,430,776.82 135,393,798.48 131,664,553.11 127,957,761.81 134,602,268.97 129,545,004.42 112,167,449.93 89,501,564.35 86,088,651.82
Current Month Interest 317,009.28 293,943.45 264,380.14 244,534.96 268,496.27 261,165.46 226,091.61 219,817.74 213,629.30 561,732.91 542,111.41 469,623.17 3,882,535.70
2023-2024 Ending Deferral Balance 176,366,072.47$ 158,628,085.50 146,720,978.03 161,097,764.80 156,699,273.09 135,654,963.94 131,890,644.72 128,177,579.55 134,815,898.27 130,106,737.33 112,709,561.34 89,971,187.52 89,971,187.52
Tab is 100% locked down, with no manual inputs.
Idaho Billed Sales MWh 1,079,076 1,078,897 1,243,540 1,506,736 1,665,023 1,405,767 1,074,008 1,009,195 1,144,193 1,229,509 1,200,336 1,114,051 14,750,331
Oregon Billed Sales MWh 48,403 47,674 55,881 56,914 70,809 56,024 46,374 48,778 55,179 58,434 53,656 47,133 645,259
Total MWh 1,127,479 1,126,570 1,299,421 1,563,650 1,735,832 1,461,792 1,120,381 1,057,973 1,199,372 1,287,943 1,253,992 1,161,184 15,395,590
Idaho % Billed Sales 95.7% 95.8% 95.7% 96.4% 95.9% 96.2% 95.9% 95.4% 95.4% 95.5% 95.7% 95.9%
Oregon % Billed Sales 4.3% 4.2% 4.3% 3.6% 4.1% 3.8% 4.1% 4.6% 4.6% 4.5% 4.3% 4.1%
Exhibit No. 2
Case No. IPC-E-24-17
J. Brady, IPC
Page 2 of 2
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-24-17
IDAHO POWER COMPANY
BRADY, DI
TESTIMONY
EXHIBIT NO. 3
1
2
3
4
5
6
7 TOTAL TOTAL
8 SYSTEM IDAHO IDAHO %SYSTEM IDAHO IDAHO %
9 * * * SUMMARY OF RESULTS * * *
10 TOTAL COMBINED RATE BASE 4,206,978,903 4,022,103,489 95.606%
11
12 DEVELOPMENT OF NET INCOME
13 OPERATING REVENUES
14 RETAIL SALES REVENUES (Incl 449.1 Rev)1,131,444,961 1,084,202,950 Direct Assign 1,472,666,391 1,409,982,947 Direct Assign
15 OTHER OPERATING REVENUES 216,499,424 207,160,642 95.7%285,571,483 273,253,253 95.7%
16 TOTAL OPERATING REVENUES 1,347,944,384 1,291,363,592 1,758,237,874 1,683,236,200
17
18 OPERATING EXPENSES
19 OPERATION & MAINTENANCE EXPENSES 904,132,356 863,119,398 95.5%1,209,651,994 1,154,780,153 95.5%
20 DEPRECIATION EXPENSE 137,896,300 132,136,256 95.8%187,945,683 180,095,035 95.8%
21 AMORTIZATION OF LIMITED TERM PLANT 3,994,103 3,827,696 95.8%5,439,874 5,213,231 95.8%
22 TAXES OTHER THAN INCOME 21,599,657 19,903,828 92.1%25,081,924 23,112,696 92.1%
23 REGULATORY DEBITS/CREDITS 1,384,615 1,146,334 82.8%1,846,154 1,528,445 82.8%
24 PROVISION FOR DEFERRED INCOME TAXES (16,780,812) (16,131,902) 96.1%(22,518,627)(21,647,836) 96.1%
25 INVESTMENT TAX CREDIT ADJUSTMENT 10,660,148 10,204,953 95.7%50,193,136 48,049,858 95.7%
26 FEDERAL INCOME TAXES 32,639,240 31,794,214 97.4%(4,035,971)(3,931,480) 97.4%
27 STATE INCOME TAXES 8,535,520 8,344,625 97.8%319,336 312,194 97.8%
28 TOTAL OPERATING EXPENSES 1,104,061,128 1,054,345,402 1,453,923,503 1,387,512,294
29
30 OPERATING INCOME 243,883,256 237,018,190 304,314,371 295,723,906
31 ADD: IERCO OPERATING INCOME 5,742,172 5,490,626 95.6%8,033,987 7,682,044 95.6%
32
33 OPERATING INCOME BEFORE OTHER INCOME AND DEDUCTIONS 249,625,428 242,508,817 312,348,358 303,405,950 97.1%
34 ADD: AFUDC EQUITY 43,221,277 41,321,921 95.6% (L 10)
35 ADD: OTHER INCOME AND DEDUCTIONS 17,357,747 16,860,801 97.1% (L 33)
36
37 INCOME BEFORE INTEREST CHARGES 372,927,382 361,588,672
38 LESS: INTEREST CHARGES 116,116,912 111,014,162 95.6% (L 10)
39
40 NET INCOME 256,810,470 250,574,510
41
42 ACTUAL YEAR-END RESULTS - BEFORE ITC ADJUSTMENT
43 EARNINGS ON COMMON STOCK 256,810,470 250,574,510
44 COMMON EQUITY AT YEAR END 2,782,171,830 2,659,909,470 95.6% (L10)
45
46 RETURN ON YEAR-END COMMON EQUITY 9.23% 9.42%
47
48 EARNINGS ON COMMON STOCK @ 9.40 ROE 261,524,152 250,031,490 (L44 * 9.4%)
49 EARNINGS ON COMMON STOCK @ 10 ROE 278,217,183 265,990,947 (L44 * 10%)
50 EARNINGS ON COMMON STOCK @ 10.50 ROE 292,128,042 279,290,494 (L44 * 10.5%)
51
52
53 ACTUAL YEAR-END RESULTS - AFTER ITC ADJUSTMENT:
54 INVESTMENT TAX CREDIT ADJUSTMENT (599,360)(L48-L43) / (1-9.4%)
55 ADJUSTED EARNINGS ON COMMON STOCK 249,975,150
56 ADJUSTED COMMON EQUITY AT YEAR-END 2,659,310,110
57 ADJUSTED RETURN ON YEAR-END COMMON EQUITY 9.40%
58
59 IF IDAHO RETURN ON COMMON EQUITY (Line 46) <9.4%
60 ADDITIONAL ITC ADJUSTMENT (Annualized) If L 54 is negative, then 0; if positive, then smaller of L54 or $25,000,000 0
61
62 IF IDAHO RETURN ON COMMON EQUITY (Line 46) >10%
63 IDAHO EARNINGS GREATER THAN 10% ROE BUT LESS THAN 10.5%0 (L43-L49)/(1-10%)
64
65 IF IDAHO RETURN ON COMMON EQUITY (Line 46) >10.5%
66 INCREMENTAL IDAHO EARNINGS GREATER THAN 10.50% ROE 0 (L43-L50)/(1-10.5%)
67
68 Per Order #34071:After Tax Tax Gross Up
69 ROE between 10%-10.5% --CUSTOMER SHARE - 80% (Reduction to rates)0-
70 ROE between 10%-10.5% --COMPANY SHARE - 20% 0
71 ROE greater than 10.5% (Incremental) -- CUSTOMER SHARE - 55% (Reduction to rates)0-
ROE greater than 10.5% (Incremental) -- CUSTOMER SHARE - 25% (Offset to Pension balance)0-
72 ROE greater than 10.5% (Incremental) --COMPANY SHARE - 20% 0
73 0
74
September Allocations/Ratios
IDAHO POWER COMPANY
ADDITIONAL INVESTMENT TAX CREDIT ANALYSIS
For the Twelve Months Ended December 31, 2023
Actual September 30, 2023 Actual December 31, 2023
Exhibit No. 3
Case No. IPC‐E‐24‐17
J. Brady, IPC
Page 1 of 1
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-24-17
IDAHO POWER COMPANY
BRADY, DI
TESTIMONY
CONFIDENTIAL
EXHIBIT NO. 4
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-24-17
IDAHO POWER COMPANY
BRADY, DI
TESTIMONY
CONFIDENTIAL
EXHIBIT NO. 5
Idaho Power Files Annual
Power Cost Adjustment
Idaho Power has filed the final piece of its annual spring
cost adjustments with the Idaho Public Utilities Commission
(IPUC). Customers in every rate class will see a net price
decrease.
A typical Idaho residential customer will see an overall
monthly decrease of $0.55 — the combined impact of the
following two filings:
The Power Cost Adjustment (PCA), filed April 15, calls for a
decrease of $35.7 million, or 2.31%, for Idaho customers. It
is a cost-recovery tool that passes on both the benefits
and costs of supplying energy to Idaho Power customers.
This year’s PCA requests a monthly bill decrease of $2.24
for the average Idaho residential customer using 950
kilowatt-hours (kWh) per month.
The Fixed Cost Adjustment (FCA), filed on March 15,
requested an increase of $10.6 million. It is applicable only
to residential and small commercial customers and adjusts
prices based on changes in energy use per customer during
the previous year. For the average Idaho residential customer,
this year’s FCA requested a monthly bill increase of $1.69.
If approved as filed, the FCA and PCA combined rate
decrease will take effect June 1.
The impact of both filings for all Idaho customers is shown
in the table below. The actual percentage will depend on a
customer’s classification and the rate they pay.
Percentage Change from Current Billed Revenue
Filing
Revenue
Change
(millions)
Small
General
Service
Large
General
Service1
Large
Power 2
Irrigation
Overall
Percentage
Impact
Residential
PCA -$35.7 -2.31% -1.91%-1.57% -2.57% -2.33% -3.12%
FCA
Combined Impact 3
$10.6
-$25.1
0.68%
-1.63%
1.44%
-0.47%
1.39%
-0.17%
N/A
-2.57%
N/A N/A
-2.33% -3.12%
1 Includes lighting schedules; 2 Includes special contracts; 3 Totals may not sum due to rounding
©2024 Idaho Power
Printed on recycled paper.
31180-I-0273
The PCA has two main components: a balancing ac-
count for power costs incurred the previous year and an
estimate of what energy will cost in the coming year. The
balancing account brings last year’s anticipated costs
in balance with costs actually incurred the previous April
through March. The estimate reflects Idaho Power’s
anticipated fuel costs, purchased power costs, and
customer benefits from sales of surplus energy for the
coming April through March.
The decrease in this year’s PCA is primarily due to an
increase in forecasted hydro generation as well as a de-
crease to the balancing account. The balancing account
decrease is attributed primarily to the increase in actual
sales as compared to the level of sales used to set base
level power supply costs, as well as increased renewable
energy credit sales from energy generated at renewable
facilities.
Neither Idaho Power nor its shareholders receive any
financial return from the PCA — money collected is used
to recover costs or credit benefits associated with annual
fluctuations in power costs.
Opportunities for Public Review
Idaho Power’s proposal is subject to public review and
approval by the IPUC. Copies of the application are
available to the public at the IPUC offices (11331 W.
Chinden Blvd. Building 8, Suite 201-A, Boise, ID 83714),
Idaho Power offices, or at idahopower.com or
puc.idaho.gov. Customers also may subscribe to the
IPUC’s RSS feed to receive periodic updates via email
about the case. Written comments regarding Idaho
Power’s proposal (Case No. IPC-E-24-17) may be filed
with the IPUC.
Idaho Power Files Annual
Power Cost Adjustment
Idaho Power has filed the final piece of its annual
spring cost adjustments with the Idaho Public Utilities
Commission (IPUC). Customers in every rate class will see a
net price decrease.
A typical Idaho residential customer will see an overall monthly
decrease of $0.55 — the combined impact of the following
two filings:
The Power Cost Adjustment (PCA), filed April 15, calls for a decrease of
$35.7 million, or 2.31%, for Idaho customers. It is a cost-recovery tool that
passes on both the benefits and costs of supplying energy to Idaho Power
customers. This year’s PCA requests a monthly bill decrease of $2.24 for
the average Idaho residential customer using 950 kilowatt-hours (kWh)
per month.
The Fixed Cost Adjustment (FCA), filed March 15, requested an increase
of $10.6 million. It is applicable only to residential and small commercial
customers and adjusts prices based on changes in energy use per customer
during the previous year. For the average Idaho residential customer, this
year’s FCA requested a monthly bill increase of $1.69.
If approved as filed, the FCA and PCA combined rate decrease will take
effect June 1.
The impact of both filings for all Idaho customers is shown in the table to
the right. The actual percentage will depend on a customer’s classification
and the rate they pay.
Percentage Change from Current Billed Revenue
Filing
Revenue
Change
(millions)
Small
General
Service
Large
General
Service1
Large
Power 2
Irrigation
Overall
Percentage
Impact
Residential
PCA -$35.7 -2.31% -1.91%-1.57% -2.57% -2.33% -3.12%
FCA
Combined Impact 3
$10.6
-$25.1
0.68%
-1.63%
1.44%
-0.47%
1.39%
-0.17%
N/A
-2.57%
N/A N/A
-2.33% -3.12%
1 Includes lighting schedules; 2 Includes special contracts; 3 Totals may not sum due to rounding
P.O. Box 70 (83707)
1221 W. Idaho St.
Boise, ID 83702
The PCA has two main components: a balancing account
for power costs incurred the previous year and an estimate
of what energy will cost in the coming year. The balancing
account brings last year’s anticipated costs in balance with
costs actually incurred the previous April through March.
The estimate reflects Idaho Power’s anticipated fuel costs,
purchased power costs, and customer benefits from sales of
surplus energy for the coming April through March.
The decrease in this year’s PCA is primarily due to an increase
in forecasted hydro generation as well as a decrease to the
balancing account. The balancing account decrease is attribut-
ed primarily to the increase in actual sales as compared to
the level of sales used to set base level power supply costs, as
well as increased renewable energy credit sales from energy
generated at renewable facilities.
Neither Idaho Power nor its shareholders receive any financial
return from the PCA — money collected is used to recover
costs or credit benefits associated with annual fluctuations in
power costs.
Opportunities for Public Review
Idaho Power’s proposal is subject to public review and
approval by the IPUC. Copies of the application are available
to the public at the IPUC offices (11331 W. Chinden Blvd.
Building 8, Suite 201-A, Boise, ID 83714), Idaho Power offices,
or at idahopower.com or puc.idaho.gov. Customers also
may subscribe to the IPUC’s RSS feed to receive periodic
updates via email about the case. Written comments
regarding Idaho Power’s proposal (Case No. IPC-E-24-17) may
be filed with the IPUC.

Idaho Power Files Annual Power Cost Adjustment
April 15, 2024
BOISE, Idaho — Idaho Power has filed the final piece of its annual spring cost adjustments with the
Idaho Public Utilities Commission (IPUC). Customers in every rate class will see a net price decrease.
A typical Idaho residential customer will see an overall monthly decrease of $0.55 — the combined
impact of the following two filings:
• The Power Cost Adjustment (PCA), filed today, calls for a decrease of $35.7 million, or 2.31%, for
Idaho customers. It is a cost-recovery tool that passes on both the benefits and costs of
supplying energy to Idaho Power customers. This year’s PCA requests a monthly bill decrease of
$2.24 for the average Idaho residential customer using 950 kilowatt-hours (kWh) per month.
• The Fixed Cost Adjustment (FCA), filed on March 15, requested an increase of $10.6 million. It is
applicable only to residential and small commercial customers and adjusts prices based on
changes in energy use per customer during the previous year. For the average Idaho residential
customer, this year’s FCA requested a monthly bill increase of $1.69.
If approved as filed, the FCA and PCA combined rate decrease will take effect June 1.
The impact of both filings for all Idaho customers is shown in the table below. The actual percentage will
depend on a customer’s classification and the rate they pay.
2024 RATE FILINGS
Percentage Change from Current Billed Revenue
Filing Revenue
Change
(millions)
Overall
Percentage
Impact
Residential Small
General
Service
Large
General
Service 1
Large Power
2
Irrigation
PCA -$35.7 -2.31% -1.91% -1.57% -2.57% -3.12% -2.33%
FCA $10.6 0.68% 1.44% 1.39% N/A N/A N/A
Combined
Impact 3
-$25.1 -1.63% -0.47% -0.17% -2.57% -3.12% -2.33%
1 Includes lighting schedules; 2 Includes special contracts; 3 Totals may not sum due to rounding

The PCA has two main components: a balancing account for power costs incurred the previous year and
an estimate of what energy will cost in the coming year. The balancing account brings last year’s
anticipated costs in balance with costs actually incurred the previous April through March. The estimate
reflects Idaho Power’s anticipated fuel costs, purchased power costs, and customer benefits from sales
of surplus energy for the coming April through March.
The decrease in this year’s PCA is primarily due to an increase in forecasted hydro generation as well as
a decrease to the balancing account. The balancing account decrease is attributed primarily to the
increase in actual sales as compared to the level of sales used to set base level power supply costs,
as well as increased renewable energy credit sales from energy generated at renewable facilities.
Neither Idaho Power nor its shareholders receive any financial return from the PCA — money collected
is used to recover costs or credit benefits associated with annual fluctuations in power costs.
Opportunities for Public Review
Idaho Power’s proposal is subject to public review and approval by the IPUC. Copies of the application
are available to the public at the IPUC offices (11331 W. Chinden Blvd. Building 8, Suite 201-A, Boise, ID
83714), Idaho Power offices, or at idahopower.com or puc.idaho.gov. Customers also may subscribe to
the IPUC’s RSS feed to receive periodic updates via email about the case. Written comments regarding
Idaho Power’s proposal (Case No. IPC-E-24-17) may be filed with the IPUC.

About Idaho Power
Idaho Power, headquartered in vibrant and fast-growing Boise, Idaho, has been a locally operated
energy company since 1916. Today, it serves a 24,000-square-mile area in Idaho and Oregon.
The company’s goal to provide 100% clean energy by 2045 builds on its long history as a clean-energy
leader that provides reliable service at affordable prices. With 17 low-cost hydroelectric projects at the
core of its diverse energy mix, Idaho Power’s residential, business and agricultural customers pay among
the nation’s lowest prices for electricity. Its 2,100 employees proudly serve more than 630,000
customers with a culture of safety first, integrity always and respect for all.
IDACORP Inc. (NYSE: IDA), Idaho Power’s independent publicly traded parent company, is also
headquartered in Boise, Idaho. To learn more, visit idahopower.com or idacorpinc.com.
Jordan Rodriguez
Communications Specialist
[e-mail]
208-388-2460