20250530Direct Larkin.pdf

RECEIVED
May 30, 2025
IDAHO PUBLIC
UTILITIES COMMISSION
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION )
OF IDAHO POWER COMPANY FOR ) CASE NO. IPC-E-25-16
AUTHORITY TO INCREASE ITS RATES )
AND CHARGES FOR ELECTRIC SERVICE )
IN THE STATE OF IDAHO AND TO )
IMPLEMENT CERTAIN MEASURES TO )
MITIGATE THE IMPACT OF )
REGULATORY LAG. )
IDAHO POWER COMPANY
DIRECT TESTIMONY
OF
MATTHEW T . LARKIN

1 Q. Please state your name, business address, and
2 present position with Idaho Power Company ("Idaho Power" or
3 "Company") .
4 A. My name is Matthew T. Larkin. My business
5 address is 1221 West Idaho Street, Boise, Idaho 83702 . I am
6 employed by Idaho Power as the Revenue Requirement Senior
7 Manager in the Regulatory Affairs Department.
8 Q. Please describe your educational background.
9 A. I received a Bachelor of Business
10 Administration degree in Finance from the University of
11 Oregon in 2007 . In 2008, I earned a Master of Business
12 Administration degree from the University of Oregon. I have
13 also attended electric utility ratemaking courses,
14 including the Electric Rates Advanced Course, offered by
15 the Edison Electric Institute, and Estimation of
16 Electricity Marginal Costs and Application to Pricing,
17 presented by National Economic Research Associates, Inc.
18 Q. Please describe your work experience with
19 Idaho Power.
20 A. I began my employment with Idaho Power as a
21 Regulatory Analyst in January 2009 . As a Regulatory
22 Analyst, I provided support for the Company' s regulatory
23 activities, including compliance reporting, financial
24 analysis, and the development of revenue forecasts for
25 regulatory filings .
LARKIN, DI 1
Idaho Power Company

1 In January 2014, I was promoted to Senior Regulatory
2 Analyst where my responsibilities expanded to include the
3 development of complex cost-related studies and the
4 analysis of strategic regulatory issues .
5 Since becoming the Revenue Requirement Senior
6 Manager in March 2016, I have overseen the Company' s
7 regulatory activities related to revenue requirement, such
8 as power supply expense modeling, jurisdictional separation
9 studies, and Idaho Power' s Open Access Transmission Tariff
10 formula rate.
11 I . OVERVIEW
12 Q. What is the purpose of your testimony in this
13 proceeding?
14 A. The purpose of my testimony is to present the
15 methodology that was applied to the Company' s 2024
16 financial data to arrive at the 2025 Test Year ("2025 Test
17 Year" or "Test Year") . Further, my testimony will describe
18 the instructions that I provided to Company Witnesses Ms .
19 Jessica G. Brady, Ms . Kelley Noe, and Ms . Paula Jeppsen
20 with regard to the normalizing, annualizing, and other
21 regulatory adjustments required to arrive at the 2025 Test
22 Year revenue requirement.
23 Q. How is your testimony organized?
24 A. My testimony begins with an overview of the
25 direction I received from Vice President of Regulatory
LARKIN, DI 2
Idaho Power Company

1 Affairs Mr. Timothy E. Tatum regarding the development of
2 the Company' s 2025 Test Year. I then detail specific
3 adjustments related to revenue requirement associated with
4 the Jim Bridger Power Plant ("Bridger") and North Valmy
5 Power Plant ("Valmy") . Next, I discuss the broader
6 methodologies utilized by the Company to develop the
7 remainder of the Test Year components . My testimony
8 concludes with a summary of the direction I gave to other
9 Company witnesses in developing the 2025 Test Year, and a
10 quantification of the Company' s requested Idaho
11 jurisdictional revenue requirement.
12 Q. Did you consult with Mr. Tatum, Vice President
13 of Regulatory Affairs, regarding the development of the
14 2025 Test Year?
15 A. Yes . The 2025 Test Year methodology presented
16 in my testimony is a direct result of numerous discussions
17 with Mr. Tatum.
18 Q. Did Mr. Tatum provide you with any specific
19 instructions or guidance regarding the development of the
20 Test Year presented in this proceeding?
21 A. Yes . Mr. Tatum instructed me to develop a
22 2025 Test Year based on 2024 actual financial data in a
23 manner similar to that presented to the Idaho Public
24 Utilities Commission ("Commission") in the Company' s last
25 general rate case ("GRC") , Case No. IPC-E-23-11 ("2023
LARKIN, DI 3
Idaho Power Company

1 GRC") . However, Mr. Tatum instructed me to deviate from
2 the methodology used in the 2023 GRC in a number of
3 specific areas .
4 First, Mr. Tatum directed me to update cost recovery
5 related to Bridger and Valmy, incorporating adjustments
6 related to the current cost recovery mechanisms for each
7 facility as I will describe in more detail later in my
8 testimony. Second, with regard to wildfire mitigation, Mr.
9 Tatum instructed me to include an expectation of 2025 Test
10 Year wildfire mitigation costs by applying known and
11 measurable adjustments to 2024 actual wildfire mitigation
12 costs, and to include amortization into rates of deferred
13 amounts over a seven-year amortization period. Third, Mr.
14 Tatum directed me to remove the offset that currently
15 exists in customer rates of approximately $21 million
16 stemming from the settlement stipulation approved in the
17 2023 GRC.
18 Q. What is the regulatory history of the $21
19 million revenue requirement offset currently included in
20 rates?
21 A. The $21 million revenue requirement offset was
22 approved as part of the settlement stipulation in the 2023
23 GRC, reflecting an estimate of the annual revenue
24 requirement associated with a 120-megawatt ("MW") battery
25 energy storage system ("BESS") requested for recovery in
LARKIN, DI 4
Idaho Power Company

1 that case. The Company proposed to utilize accumulated
2 deferred investment tax credits ("ADITC") to temporarily
3 offset the revenue requirement of the BESS project as a
4 rate mitigation measure within its initial filing.
5 Q. Why is the Company removing the $21 million
6 revenue requirement offset in the current filing?
7 A. The revenue requirement offset was always
8 envisioned as temporary. As discussed in Mr. Tatum' s Direct
9 Testimony in the 2023 GRC, the amount of available ADITC
10 generated by the BESS project represented approximately two
11 years of annual revenue requirement related to the BESS
12 project . Therefore, in the current filing the Company has
13 removed the offset, which will have been in effect for two
14 years at the time rates go into effect as a result of this
15 case .
16 II . BRIDGER AND VALMY COST RECOVERY
17 Q. Please generally describe the currently
18 approved ratemaking treatment for Bridger and Valmy.
19 A. On May 31, 2017, the Commission authorized the
20 Company in Order No. 33771 to establish a balancing
21 account, with the necessary regulatory accounting, to track
22 the incremental costs and benefits associated with the
23 accelerated Valmy end-of-life as part of the Valmy
24 levelized revenue requirement mechanism. ' Similarly, on June
' Case No. IPC-E-16-24, Order No. 33771.
LARKIN, DI 5
Idaho Power Company

1 1, 2022, the Commission authorized the Company to establish
2 a balancing account, with the necessary regulatory
3 accounting, to track the incremental costs and benefits
4 associated with the Company' s cessation of coal-fired
5 operations at Bridger as part of the Bridger coal-related
6 levelized revenue requirement mechanism.z
7 Both mechanisms were implemented to smooth revenue
8 requirement impacts associated with the early cessation of
9 coal-fired operations at these facilities . While there are
10 nuanced differences between the two mechanisms, generally
11 speaking they are both structured as balancing accounts to
12 track the "return of" and "return on" coal-related capital
13 (including a forecast and true-up to actuals) , as well as
14 non-fuel operations and maintenance expense ("0&M") . Fuel
15 expense is excluded from these mechanisms and tracked
16 separately as part of the Company' s Power Cost Adjustment
17 ("PCA") . The recovery of these amounts is embedded in the
18 Company' s currently-approved base rates .
19 Q. Did Idaho Power comprehensively update costs
20 associated with the Valmy or Bridger mechanisms in its 2023
21 GRC or its limited issue rate filing in 2024, Case No . IPC-
22 E-24-07 ("2024 Limited Scope Rate Case") ?
23 A. No.
2 Case No. IPC-E-21-17, Order No. 35423.
LARKIN, DI 6
Idaho Power Company

1 Q. Is Idaho Power requesting to update rate
2 recovery associated with these mechanisms in the current
3 proceeding?
4 A. Yes . At a high level, Idaho Power is proposing
5 to update rate recovery associated with both the Valmy and
6 Bridger mechanisms to reflect current capital and O&M
7 expectations, and to true-up variances between prior
8 forecasts and actual costs .
9 Q. What components did Idaho Power update related
10 to the Bridger mechanism?
11 A. For Bridger, Idaho Power' s request in this
12 case updates actual coal-related capital investments
13 through year-end 2024, with updated expected coal-related
14 capital expenditures for 2025 through 2030, which reflects
15 the current life of the mechanism. The Company' s request
16 also updates 0&M to true-up past variances between the
17 prior forecast and actuals and updates the total plant O&M
18 forecast for 2026 through 2030 . Please see page 103 of
19 Exhibit No . 21 for a detailed list of all components of the
20 Bridger mechanism that were updated.
21 Q. What components did Idaho Power update related
22 to the Valmy mechanism?
3 Please note that the references in this testimony to page numbers in
Exhibit 21 rely on the pagination of the 2025 Methodology Manual as
opposed to the exhibit numbering.
LARKIN, DI 7
Idaho Power Company

1 A. For Valmy, Idaho Power' s request in this case
2 also updates actual coal-related capital investments
3 through year-end 2024, with an expectation of coal-related
4 capital investment through year-end 2025 . Coal-related
5 assets in the Valmy mechanism will continue to depreciate
6 through year-end 2028 in accordance with the currently
7 approved ratemaking treatment. 0&M and load variances from
8 prior periods are also folded into the requested recovery
9 in this case. Due to the conversion of the entirety of the
10 Valmy facility to natural gas operations, the Valmy
11 mechanism does not include an expectation of O&M beyond
12 2025 . Please see page 11 of Exhibit No. 21 for a detailed
13 list of all components of the Valmy mechanism that were
14 updated. As part of this case, Idaho Power is also
15 requesting the Commission confirm the update to the Valmy
16 mechanism and associated request for prudence of Valmy
17 coal-related investments made through December 31, 2024,
18 discussed in Mr. Adelman' s testimony, satisfies the 2024
19 annual reporting required by Order No. 34349 .
20 Q. How are Bridger and Valmy-related costs
21 addressed that are not subject to the respective
22 mechanisms?
23 A. Costs at Bridger and Valmy that are not
24 subject to the respective mechanisms are included in the
LARKIN, DI 8
Idaho Power Company

1 2025 Test Year in the same manner as costs associated with
2 other Company-owned facilities .
3 III . TEST YEAR METHODS
4 Q. Will you briefly summarize how the Company
5 developed its 2025 Test Year?
6 A. Yes . The development of the 2025 Test Year
7 began with 2024 actual financial data ("2024 Actuals") .
8 2024 Actuals were compiled and adjusted by Ms . Jeppsen to
9 reflect standard ratemaking and other adjustments and
10 arrive at 2024 adjusted actual financial information ("2024
11 Base") . The 2024 Base was then adjusted to reach 2025
12 financial levels ("2025 Unadjusted Test Year") . Finally,
13 annualizing adjustments were made to the 2025 Unadjusted
14 Test Year to reach the Company' s 2025 Test Year.
15 Q. Which methodologies were used to adjust the
16 2024 Base to the 2025 Unadjusted Test Year?
17 A. There were two primary methods applied to the
18 2024 Base to determine the 2025 Unadjusted Test Year.
19 First, the Company used the unchanged 2024 Base data when
20 the Company believed that certain amounts would continue to
21 remain at 2024 levels or if account balances were
22 relatively small . Alternatively, "Other Adjustments" were
23 applied based upon known and measurable factors for 2025
24 that relate to a particular account. Examples of these
25 factors include, but are not limited to, new billing and
LARKIN, DI 9
Idaho Power Company

1 volume contract terms, anticipated levels of economic
2 activity, and existing regulatory commission orders .
3 Q. Have you prepared exhibits that list all
4 accounts and identify the specific method used to develop
5 the 2025 Unadjusted Test Year?
6 A. Yes . I directed the preparation of Exhibit No .
7 20 to present a summarized list of all accounts to which
8 the previously discussed methods were applied. Each
9 methodology is described in more detail within the 2025
10 Methodology Manual, provided as Exhibit No. 21, which was
11 also prepared at my direction. To develop the 2025
12 Methodology Manual, the Company performed a review of each
13 group of accounts included within the Test Year.
14 Q. Are the data and the associated adjustments
15 made to your exhibits and supporting schedules calculated
16 on a total system basis?
17 A. Yes . Ms . Noe will address the determination of
18 the Idaho jurisdictional Test Year values in her testimony.
19 Q. What are the major areas or groupings of
20 financial accounts addressed by the methodologies included
21 in the 2025 Methodology Manual (Exhibit No. 21) ?
22 A. The major areas or groupings of financial
23 accounts addressed in Exhibit No. 21 include Other
24 Operating Revenues (Accounts 451, 454, and 456) , O&M
25 (Accounts 500 through 935) , Depreciation and Amortization
LARKIN, DI 10
Idaho Power Company

1 Expense (Accounts 403 and 404) , and Electric Plant in
2 Service (Account 101) . A detailed discussion of the
3 individual accounts and methods used is provided in Exhibit
4 No . 21 .
5 Q. What methodology was used to determine 2025
6 Other Operating Revenues (Accounts 447, 451, 454, and 456) ?
7 A. Consistent with Mr. Tatum' s directive, Surplus
8 Sales Revenues (Account 447) were included in the Company' s
9 quantification of base net power supply expenses ("NPSE")
10 as further detailed in Ms . Brady' s testimony. The remaining
11 Other Operating Revenues (Accounts 451, 454, and 456) were
12 kept at year-end 2024 Actuals, with the exception of five
13 items : 1) cogeneration and small power production, 2)
14 facilities charges, 3) Sierra Pacific Power Company
15 ("SPPC") sales, 4) payments to water districts, and 5)
16 third-party transmission revenues .
17 Cogeneration and small power production revenues
18 were determined by adjusting year-end 2024 amounts to
19 reflect the impact of Idaho Power' s current filing to
20 update 0&M charges within Schedule 72 .4 Expected facilities
21 charge revenues were based on the Company' s proposed
22 facilities charge rate filed in this case applied to
23 applicable investment, as further addressed by Company
24 Witness Mr. Grant Anderson. SPPC sales were developed using
4 Case No. IPC-E-25-22
LARKIN, DI 11
Idaho Power Company

1 a five-year average from 2019-2023, as the 2024 actual
2 amount was an outlier due to an SPPC breach of contract
3 causing a large penalty assessment that is not expected to
4 recur. Payments from water districts were calculated based
5 on a five-year average, as these payments fluctuate based
6 on demand for water and availability. Network services and
7 other long-term firm and point-to-point transmission
8 revenues were projected based on information more
9 reflective of current circumstances and an anticipated Open
10 Access Transmission Tariff transmission rate update in
11 October 2025 .
12 Q. What methodology was used to determine 2025
13 0&M Expenses (Accounts 500 through 935) ?
14 A. Based on the instructions I received from Mr.
15 Tatum, the general process to determine 2025 Test Year 0&M
16 began with the separation of the majority of 0&M components
17 into two elements : labor and non-labor. Each element was
18 then calculated separately and allocated to the individual
19 Federal Energy Regulatory Commission ("FERC") accounts .
20 There were several 0&M accounts, however, that were
21 determined separately from this process . First, the base
22 NPSE accounts tracked through the PCA were updated by Ms .
23 Brady primarily utilizing the AURORA model . The PCA expense
24 accounts include Fuel Expense (Accounts 501 and 547) , Water
25 for Power Expense (Account 536 . 003) , Purchased Power
LARKIN, DI 12
Idaho Power Company

1 Expense (Account 555) , and Transmission of Electricity by
2 Others (Account 565) .
3 Idaho Energy Efficiency Rider Expense (Account 908)
4 was removed in its entirety from the 2025 Test Year.
5 Short-Term Incentive Expense (included in Account
6 920) was calculated for 2025 to include only the normalized
7 incentive components that are attributable to Customer
8 Satisfaction and Reliability, consistent with the
9 methodology utilized in the Company' s last several GRCs and
10 approved in the 2024 Limited Scope Rate Case . Short-Term
11 Incentive expense represents the "at-risk" portion of
12 employees' total compensation package.
13 Pension Expense (Account 926) for the Idaho
14 jurisdiction was left unchanged from currently approved
15 recovery levels .
16 Regulatory Commission Expenses (Account 928) were
17 adjusted to include known changes in amortizations for
18 recovery of Commission-ordered intervenor funding.
19 Q. What methodology was used to develop 2025 Test
20 Year O&M labor expense?
21 A. 2025 0&M labor expense was developed by
22 applying historical monthly labor cost relationships to the
23 first two calendar months of 2025 actual labor costs . More
24 specifically, 2025 0&M labor was developed by first
25 calculating the three-year historical average of February
LARKIN, DI 13
Idaho Power Company

1 year-to-date actual 0&M labor costs as a percentage of the
2 total year actual 0&M labor costs . The resulting
3 percentage was determined to be 16 . 6 percent . The Company
4 then took actual February 2025 year-to-date 0&M labor,
5 (excluding pension, short-term incentive and two-thirds of
6 long-term incentive expense) and applied this ratio to
7 calculate 2025 non-annualized labor expense of $207 . 8
8 million. Idaho Power then applied an annualizing adjustment
9 of $1 . 7 million and added the December 2025 general wage
10 adjustment ("GWA") of $6 . 3 million to arrive at a final
11 2025 Test Year 0&M labor amount of $215 . 8 million. This
12 amount was allocated to the applicable FERC accounts based
13 on 2024 actual labor charges to those same accounts .
14 Q. Does the 2025 Test Year O&M labor amount
15 include long-term pay-at-risk for officers and senior
16 managers?
17 A. Yes . As discussed in more detail in the Direct
18 Testimony of Company Witness Ms . Sarah Griffin, the 2025
19 Test Year 0&M labor includes approximately $3 . 5 million
20 related to the long-term incentive ("LTI") for officers and
21 senior managers . The 2025 Test Year 0&M labor only includes
22 the time-based component of LTI, and excludes amounts tied
23 to the financial performance of the Company. This treatment
24 aligns with the methodology reflected in the settlement
25 stipulation approved in the Company' s 2023 GRC.
LARKIN, DI 14
Idaho Power Company

1 Q. What methodology was used to develop 2025 Test
2 Year non-labor 0&M expenses?
3 A. 2024 non-labor O&M expenses, excluding the
4 accounts mentioned above, were set equal to the 2024 actual
5 expense level with adjustments only for relatively large
6 known changes . At my direction, the O&M expenses were
7 reviewed by subject matter experts to identify and adjust
8 those areas, based on specific knowledge, where expense
9 levels are expected to be materially different than those
10 included in the 2024 Base. The review identified specific
11 increases or decreases to the 2024 non-labor actual levels
12 in the following categories :
13 • Water for Power
14 • Wildfire Mitigation Costs
15 • BESS Maintenance
16 • Airplane Inspection Costs (removed)
17 Actual 2024 non-labor 0&M, excluding these items
18 listed for known changes, equaled $180 . 0 million.
19 Following the adjustments for these known changes, non-
20 labor 0&M is projected to increase by $19 . 5 million, to
21 $199 . 5 million. A more detailed discussion of the non-labor
22 0&M adjustments is provided in Exhibit No. 21, pages 7
23 through 9 .
LARKIN, DI 15
Idaho Power Company

1 Q. What methodology was used to determine 2025
2 Test Year Depreciation and Amortization Expense (Accounts
3 403 and 404) ?
4 A. The 2025 depreciation expense, amortization
5 expense, and related reserve accounts were calculated based
6 on monthly estimated 2025 plant balances . Depreciation
7 rates authorized by Commission Order No. 35272 were used
8 for the entire 2025 Test Year. The determination of the
9 Depreciation and Amortization Expense adjustments is
10 detailed in Exhibit No. 21, page 16 .
11 Q. What methodology was used to develop 2025 Test
12 Year Electric Plant in Service ("EPIS") (Account 101) ?
13 A. To develop 2025 Test Year construction
14 expenditures and closings of Construction Work in Process
15 ("CWIP") to EPIS, at Mr. Tatum' s instruction, the Company
16 first bifurcated its plant calculation into two separate
17 and distinct parts, those projects in excess of $2 million
18 and those under $2 million.
19 Projects in excess of $2 million were reviewed by
20 the individual project managers, who estimated the costs to
21 complete and the in-service date of each project. The
22 investment in projects under $2 million was determined
23 based on the five-year average of the percent of similar-
24 sized projects to the previous year' s CWIP balance
25 multiplied by the year-end 2024 CWIP balance. The
LARKIN, DI 16
Idaho Power Company

1 determination of the 2025 Test Year EPIS is detailed in
2 Exhibit No . 21, pages 22 and 23 .
3 Q. What level of recovery did Idaho Power assume
4 for collection of allowance for funds used during
5 construction ("AFUDC") associated with Hells Canyon
6 relicensing costs in CWIP?
7 A. Given the Company' s request to increase AFUDC
8 collection in Case No . IPC-E-25-13 ("HCC Filing") , the
9 Company' s 2025 Test Year assumes total Idaho jurisdictional
10 collection of $38 . 5 million as requested in that case . Due
11 to the proximity of the requested effective date of the HCC
12 Filing (June 1, 2025) , and the filing date of the Company' s
13 2025 GRC (May 30, 2025) , the Company assumed for the 2025
14 Test Year that its request in the HCC Filing was approved
15 as filed. This adjustment is explained in greater detail in
16 Exhibit No . 21, pages 20 and 21 .
17 IV. ADDITIONAL ADJUSTMENTS
18 Q. In Ms . Jeppsen' s testimony, she describes the
19 various adjustments that were made to 2024 Actuals to
20 arrive at the 2024 Base. Do these same adjustments need to
21 be made to the 2025 Test Year?
22 A. No. These adjustments are standard ratemaking
23 adjustments based on prior Commission orders and other
24 adjustments to charges included in the 2024 Actuals . These
25 adjustments are more fully described in Ms . Jeppsen' s
LARKIN, DI 17
Idaho Power Company

1 testimony. By adjusting them in the 2024 Actuals prior to
2 applying the various methodologies to arrive at the
3 Company' s proposed 2025 Unadjusted Test Year, the same
4 adjustments are already accounted for.
5 Q. Did Idaho Power make an adjustment stemming
6 from the passage of law in the state of Idaho related to
7 property tax collection?
8 A. Yes . As described in detail on page 18 of
9 Exhibit No. 21, a new law was passed in Idaho in 2025 that
10 replaces the existing property tax regime with a tax based
11 on kilowatt-hours ("kWh") sold. This law goes into effect
12 on January 1, 2026, and will be assessed to customers as a
13 separate cents-per-kWh charge on their bills . Consequently,
14 the Company removed Idaho property taxes from its 2025 Test
15 Year to reflect the change in collection method coincident
16 with its requested effective date in this case .
17 Q. Were the 2025 Test Year customer, sales, and
18 load figures prepared at your direction?
19 A. Yes . These amounts were utilized to determine
20 the billing components for 2025 Test Year retail revenues,
21 as well as the allocation factors utilized by Ms . Noe and
22 Mr. Maloney.
23 Q. What were your instructions to Ms . Brady with
24 regard to the determination of test year retail sales
25 revenues?
LARKIN, DI 18
Idaho Power Company

1 A. I instructed Ms . Brady to determine the 2025
2 Test Year retail sales revenues using the same methodology
3 applied in the Company' s 2011 and 2023 GRCs, with one
4 exception. That is, my instructions were to develop the
5 test year retail sales revenues based upon expected 2025
6 billing determinants under normal weather and precipitation
7 assumptions . As Ms . Brady will cover in greater detail in
8 her testimony, the 2025 Test Year billing determinants were
9 developed based on the Company' s energy sales and customer
10 count expectations for 2025 . To derive the demand-related
11 billing determinants, historical demand-to-energy
12 relationships were applied to expected energy sales .
13 Billing determinants were then applied to the rates
14 proposed in the Company' s HCC Filing to determine the 2025
15 Test Year retail sales revenues .
16 Q. Did you direct Ms . Brady to make any
17 adjustments to the 2025 Test Year revenue determination?
18 A. Yes . In March 2025, minimum charges associated
19 with the Brisbie special contract ("Schedule 33") became
20 effective . While this contract will only be in effect for
21 10 months of 2025, due to the nature of the special
22 contract' s minimum demand amounts, I directed Ms . Brady to
23 annualize these revenues as if they had been in place the
24 entire year. The effect of this adjustment is an
25 approximate $500, 000 decrease to net revenue requirement.
LARKIN, DI 19
Idaho Power Company

1 Q. Did you have any additional instructions for
2 Ms . Brady?
3 A. Yes . In addition to the development of 2025
4 Test Year retail revenues, Ms . Brady is also the Company' s
5 expert with regard to the modeling of LAPSE. As mentioned
6 earlier in my testimony, Mr. Tatum directed me to update
7 the PCA expense accounts to expected 2025 normalized
8 levels . Consistent with this directive, Ms . Brady updated
9 base NPSE as provided in Exhibit No. 24 to her testimony.
10 Q. When was base NPSE last updated in customer
11 rates?
12 A. Idaho Power last updated base NPSE in customer
13 rates through Order No. 36042 issued in the 2023 GRC.
14 Q. Did you direct Ms . Brady to make any
15 methodological changes to base NPSE relative to the
16 methodology used in the 2023 GRC?
17 A. Yes . Effective June 1, 2025, commercial
18 operation is expected to commence on a 150 MW BESS project
19 located in Kuna, Idaho ("Kuna BESS") . The Company has
20 entered into an Energy Storage Agreement ("ESA") that acts
21 as a type of lease through which Idaho Power has the
22 exclusive right to dispatch and use the charging and
23 discharging of energy in exchange for a monthly payment.
24 Because costs associated with this ESA effectively function
25 as a component of NPSE, I directed Ms . Brady to include
LARKIN, DI 20
Idaho Power Company

1 these costs (FERC Account 577 . 4) in her quantification of
2 base NPSE .
3 Q. Did you provide any additional direction to
4 Ms . Brady with regard to the Company' s resource stack?
5 A. Yes . As noted in the testimony of Company
6 Witness Mr. Ryan N. Adelman, work on converting Valmy Unit
7 1 to natural gas operations is expected to complete on
8 December 30, 2025 . Because this date occurs within the
9 Company' s 2025 Test Year, I directed Ms . Brady to model
10 Valmy Unit 1 as natural gas operations in effect for the
11 entirety of the year. This is consistent with how Idaho
12 Power has typically treated new resources that come online
13 within a test year.
14 Q. Are there any additional adjustments you have
15 not yet discussed that need to be made to properly
16 determine the 2025 Test Year?
17 A. Yes . It is necessary for the Company to make
18 additional annualizing and known and measurable
19 adjustments .
20 Q. What other annualizing adjustments were made
21 under your direction to the 2025 Test Year?
22 A. I instructed Ms . Noe to make annualizing
23 adjustments to certain expense and rate base items to
24 reflect them as though they had been in existence for the
25 entire 2025 Test Year; that is, at year-end 2025 levels .
LARKIN, DI 21
Idaho Power Company

1 These include operating payroll, depreciation expense and
2 reserve, and plant placed in service during 2025 in excess
3 of $2 million. Such adjustments are appropriate to reflect
4 conditions that will be in effect at the time rates are
5 placed in effect. Ms . Noe provides additional detail
6 regarding the annualizing adjustments in her testimony.
7 Q. Has an exhibit been prepared that details each
8 of the adjustments that were made to move from the 2024
9 Actuals to the 2025 Test Year?
10 A. Yes . Ms . Noe' s Exhibit No . 28 summarizes the
11 adjustments that were made to each FERC Account to: 1) move
12 from the 2024 Actuals to the 2024 Base, 2) move from the
13 2024 Base to the 2025 Unadjusted Test Year, and 3) move
14 from the 2025 Unadjusted Test Year to the 2025 Test Year.
15 Q. Did you direct Ms . Noe to make any additional
16 adjustments prior to quantifying the Company' s requested
17 revenue requirement in this case?
18 A. Yes . I directed Ms . Noe to reflect the PCA-
19 related transfer adjustment in the body of the JSS .
20 Q. What is meant by transfer adjustment?
21 A. The Company' s proposed update to base NPSE in
22 this case will have a corresponding offsetting impact on
23 the PCA, thus reducing the net increase to customer bills .
24 The term "transfer adjustment" is in reference to the fact
25 that a portion of the recovery of these components of
LARKIN, DI 22
Idaho Power Company

1 revenue requirement is already reflected in customer rates,
2 and the Company' s request in this case merely reflects the
3 transfer of this recovery to base rates rather than a true
4 increase to customer bills .
5 Q. How will the PCA be reduced as a result of the
6 base NPSE update?
7 A. A primary component of PCA rates contained in
8 Schedule 55 is the difference between base NPSE and the
9 forecast of NPSE for the PCA year. Therefore, when base
10 NPSE are updated— and in this case, increased— the
11 difference between base NPSE and the forecast established
12 in the PCA is reduced, necessitating a reduction in
13 Schedule 55 PCA rates . Consequently, the increase in NPSE
14 proposed to be included in base rates is mostly offset by a
15 corresponding reduction in the PCA rate. The only net
16 impact to customers stems from the difference between full
17 recovery in base rates of base NPSE, as compared to 95
18 percent recovery of deviations between base NPSE and
19 forecast NPSE for certain accounts through the PCA. Ms .
20 Brady quantifies this component of the PCA transfer
21 adjustment in her testimony.
22 Q. What is the total amount of the PCA transfer
23 adjustment reflected in the presentment of the Company' s
24 2025 revenue requirement computation?
LARKIN, DI 23
Idaho Power Company

1 A. The total PCA transfer adjustment is
2 $46, 781, 308 .
3 Q. What direction did you provide Ms . Noe with
4 regard to the inclusion of the transfer adjustment?
5 A. To recognize that these costs are already
6 reflected in customer rates, I directed Ms . Noe to include
7 the transfer adjustment in 2025 Test Year operating
8 revenues .
9 Q. Are there any other mechanism-related
10 adjustments Idaho Power is requesting as part of this
11 filing?
12 A. Yes . In Order No. 36502 issued in Case No .
13 IPC-E-24-38, the Commission established a mechanism through
14 which Idaho Power is required to track the difference
15 between sales-adjusted third-party wheeling revenues
16 reflected in base rates and actual wheeling revenues
17 experienced by the Company. Because Idaho Power is
18 requesting to update third-party wheeling revenues in this
19 case, base wheeling revenue collection must be reset for
20 purposes of tracking through this mechanism.
21 Q. Have you quantified the new base level of
22 wheeling revenues?
23 A. Yes . The new baseline wheeling tracker level
24 of collection is $3 . 39 per megawatt-hour ("MWh") . This
25 reflects Idaho jurisdictional point-to-point wheeling
LARKIN, DI 24
Idaho Power Company

1 revenues of $52, 329, 3585 divided by Idaho jurisdictional
2 retail sales of 15, 451, 410 MWh.
3 V. REVENUE REQUIREMENT RESULTS
4 Q. According to Ms . Noe' s analysis using the 2025
5 Test Year and incorporating the adjustments she made at
6 your direction, what is the Company' s revenue requirement
7 on an Idaho jurisdictional basis?
8 A. Using the 2025 Test Year financial
9 information, Ms . Noe has calculated the Company' s revenue
10 requirement to be $1, 720 . 1 million on an Idaho
11 jurisdictional basis . Ms . Noe calculated the Company' s
12 annual revenue deficiency, the amount that the test year
13 revenue requirement exceeds the test year retail sales
14 revenue, to be $199 . 1 million on an Idaho jurisdictional
15 basis, which would result in an overall average increase to
16 customer rates of 13 . 09 percent.
17 Q. Is it appropriate for the Commission to
18 determine the Company' s Idaho-jurisdictional revenue
19 requirement to be $1, 720 . 1 million, its revenue deficiency
20 to be $199 . 1 million, and therefore, approve an overall
21 13 . 09 percent increase to customer rates?
22 A. Yes . The $1, 720 . 1 million figure is a
23 reasonable determination of the Company' s annual Idaho-
24 jurisdictional revenue requirement. The $199 . 1 million
5 Direct Testimony of Ms. Kelley Noe, Exhibit No. 29.
LARKIN, DI 25
Idaho Power Company

1 quantification of revenue deficiency is also reasonable .
2 It is in the best interest of the Company and its customers
3 for the Commission to approve a rate increase to provide an
4 13 . 09 percent increase to the Company' s Idaho
5 jurisdictional revenues .
6 Q. Does this conclude your direct testimony in
7 this case?
8 A. Yes, it does .
9
10
LARKIN, DI 26
Idaho Power Company

1 DECLARATION OF MATTHEW T. LARKIN
2 I, Matthew T . Larkin, declare under penalty of
3 perjury under the laws of the state of Idaho:
4 1 . My name is Matthew T. Larkin. I am employed
5 by Idaho Power Company as the Revenue Requirement Senior
6 Manager.
7 2 . On behalf of Idaho Power, I present this
8 pre-filed direct testimony and Exhibit Nos . 20 through 21
9 in this matter.
10 3 . To the best of my knowledge, my pre-filed
11 direct testimony and exhibits are true and accurate .
12 I hereby declare that the above statement is true to
13 the best of my knowledge and belief, and that I understand
14 it is made for use as evidence before the Idaho Public
15 Utilities Commission and is subject to penalty for perjury.
16 SIGNED this 30th day of May 2025, at Boise, Idaho.
17
18 Signed:
19 MATTHEW T . LARKIN
LARKIN, DI 27
Idaho Power Company

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-25-16
IDAHO POWER COMPANY
LARKIN , DI
TESTIMONY
EXHIBIT NO. 20

IDAHO POWER COMPANY
Methodology Summary - Exhibit 20
2025 Idaho Test Year
- 2024 Base
- Other Methodology
- Normalized
- Removed in its Entirety
(1) (2)
FERC
LINE ACCOUNT
NO Description NUMBER Methodology
Cost of Service Components
Other Operating Revenues
1 Miscellaneous Service Revenues 451 2024 Base
Rent from Electric Property
2 Substation equipment 454 2024 Base
3 Transformer & distribution rentals 454 2024 Base
4 Cogeneration and small power production 454 Other Methodology
5 Real estate rents 454 2024 Base
6 Joint pole attachments 454 2024 Base
7 Facilities charges 454 Other Methodology
8 Overnight park rents 454 2024 Base
9 Water district payments 454 Other Methodology
10 Miscellaneous 454 2024 Base
Other Electric Revenues
11 Network Service 456 Other Methodology
12 Point-to-Point and other services 456 Other Methodology
13 Photovoltaic 456 2024 Base
14 Antelope 456 2024 Base
15 Sierra Pacific Power Company sales 456 Other Methodology
16 Stand-by service 456 2024 Base
17 Energy Efficiency Rider 456 Removed in i�
18 Miscellaneous 456 2024 Base
Other Revenues and Expenses
Other Revenues
19 Power Solutions 415 2024 Base
20 Hydro Services 415 2024 Base
21 Water Management Services 415 2024 Base
22 Qualified Reporting Entity Svcs 415 2024 Base
23 Operating Agreements 415 2024 Base
24 Joint Use (Pole) - Idaho 415 Other Methodology
25 Joint Use (Pole) - Oregon 415 Other Methodology
Other Expenses
26 Power Solutions 416 2024 Base
27 Hydro Services 416 2024 Base
28 Water Management Services 416 2024 Base
29 Qualified Reporting Entity Svcs 416 2024 Base
30 Operating Agreements 416 2024 Base
31 Joint Use (Pole) - Idaho 416 Other Methodology
32 Joint Use (Pole) - Oregon 416 2024 Base
Exhibit No.20
Case No.IPC-E-25-16
M.Larkin,IPC
Page 1 of 4

IDAHO POWER COMPANY
Methodology Summary - Exhibit 20
2025 Idaho Test Year
- 2024 Base
- Other Methodology
- Normalized
- Removed in its Entirety
(1) (2)
FERC
LINE ACCOUNT
NO Description NUMBER Methodology
Operations and Maintenance Expenses
Power production expenses
Steam power generation 500-514
33 Oper and supv engineering 500 Other Methodology
34 Fuel expense 501 Normalized
35 Steam expenses, electric expenses 502-505 2024 Base
36 Misc steam power expenses 506 Other Methodology
37 Rents, maintenance 507-514 2024 Base
38 Hydraulic power generation (excluding 540) 535-545 Other Methodology
39 Rents 540 2024 Base
40 Other power generation(excluding 547.1) 546-554 Other Methodology
41 Fuel expense 547 Normalized
Other power supply expenses
42 Purchased power (including 555.050) 555 Normalized
43 System control and load dispatch 556 Other Methodology
44 Other expenses 557.000 Other Methodology
45 Other expenses 557.007 2024 Base
46 Other expenses - PCA, EPC and PCAM (excluding 557.050) 557 Removed in its entirety
47 Transmission expenses 560-563 Other Methodology
48 Transmission of electricity by others 565 Normalized
49 Rents 567 2024 Base
50 Maintenance 568-573 Other Methodology
Regional Market Expenses
51 Admin EIM 575 2024 Base
Energy storage expenses 577-578
52 Operation 577 2024 Base
53 Maintenance 578 Other Methodology
54 Distribution expenses 580-598 Other Methodology
Customer account, service and information expenses
55 Supervision, Meter reading, Cust records - collect exp 901-903 Other Methodology
56 Uncollectible accounts, Misc customer sects exp 904-905 2024 Base
57 Supervision, Customer assistance exp 907-908 Other Methodology
58 Energy Efficiency Rider expenses 908.1 Removed in its entirety
59 Info and instruct adv exp 909 2024 Base
60 Misc cust svc and inf exp 910 Other Methodology
61 Administrative & general expenses(excluding accts 920.1, 923, 926.2 and 930.1) 920-935 Other Methodology
62 Incentive 920.1 Normalized
63 Outside services employed 923 2024 Base
64 Emp pensions and benefits 926.2 2024 Base
65 General advertising expenses 930.1
Depreciation and Amortization Expense
66 Depreciation 403 Other Methodology
67 Amortization 404 Other Methodology
Electric Plant/Regulatory Assets - Amort, Adj, Gains 6 Losses
68 Amortization of electric plant acquisition adjustment-Asset Exchange 406 2024 Base
Regulatory Debits and Credits
69 Siemens LTP amort - Idaho 407.3/407.4 2024 Base
70 Cloud computing 407.3/407.4 Other Methodology
71 Wildfire Mitigation 407.3/407.4 Other Methodology Exhibit No.20
72 Deferred pension - Orgeon 407.3/407.4 2024 Base Case No.IPC-E-25-16
73 Siemens LTP amort - Oregon 407.3/407.4 2024 Base M.Larkin,IPC
Page 2 of 4

IDAHO POWER COMPANY
Methodology Summary - Exhibit 20
2025 Idaho Test Year
- 2024 Base
- Other Methodology
- Normalized
- Removed in its Entirety
(1) (2)
FERC
LINE ACCOUNT
NO Description NUMBER Methodology
Taxes Other Than Income
74 Real and personal property 600.6-600.6,601.1 Other Methodology
75 Kilowatt-hour tax - Idaho 601.3 Normalized
76 Idaho other assessments 600.6, 600.8, 601.2 Other Methodology
Licenses
77 Wyoming 601.9 2024 Base
78 Shoshone-Bannock 602 2024 Base
Regulatory commission
79 Idaho 601.5 Other Methodology
80 Oregon 601.5, 602.9 2024 Base
81 Franchise tax - Oregon 602.1 2024 Base
82 Nevada Commerce Tax 601.5 2024 Base
83 Idaho Energy Resources Statement of Income 418.1/419 Other Methodology
84 Allowance for Funds Used During Construction (AFUDC) Related to Hells Canyon Relicensing 440-444 2024 Base
Exhibit No.20
Case No.IPC-E-25-16
M.Larkin,IPC
Page 3 of 4

IDAHO POWER COMPANY
Methodology Summary - Exhibit 20
2025 Idaho Test Year
- 2024 Base
- Other Methodology
- Normalized
- Removed in its Entirety
(1) (2)
FERC
LINE ACCOUNT
NO Description NUMBER Methodology
Rate Base Components
Electric Plant-In-Service
85 Projects > $2 million 101 Other Methodology
86 Projects < $2 million 101 Other Methodology
Accumulated Reserve for Depreciation and Amortization
87 Depreciation reserve 108 Other Methodology
88 Amortization reserve ill Other Methodology
Materials and Supplies
89 Plant materials and operating supplies 154 2024 Base
90 Stores expense undistributed 163 2024 Base
91 Other Deferred Programs (excluding accts 182.312 and 254) 182/186 Other Methodology
92 OR Wildfire Mitigation, OR Bringer Depreciation 182.312/254 2024 Base
93 Plant Held for Future Use(excluding items listed below) 105 2024 Base
94 McDermott Substation 105
95 Pillar Falls Substation 105
96 Gem Substation 105 Other Methodology
97 Eisenman Substation 105 Other Methodology
98 Donnelly McCall Transmission Land R/W 105 Other Methodology
99 Mayfield Transmission Station 105 Other Methodology
100 Deferred Income Taxes 190/282/283 Other Methodology
101 Customer Advances For Construction 252 Other Methodology
102 IERCO-Subsidiary Rate Base Components 123.1/145 Other Methodology
Exhibit No.20
Case No.IPC-E-25-16
M.Larkin,IPC
Page 4 of 4

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-25-16
IDAHO POWER COMPANY
LARKIN DI
TESTIMONY
EXHIBIT NO. 21

MmIDAHO
iw�"
POWER®
An IDACORP Company
2025 Methodology Manual
2025 General Rate Case
Exhibit No.21
Case No. IPC-E-25-16
M. Larkin, IPC
Page 1 of 38

Exhibit No.21
Case No. IPC-E-25-16
M.Larkin, IPC
Page 2 of 38

Idaho Power Company Methodology Manual
TABLE OF CONTENTS
Tableof Contents............................................................................................................................. i
Cross-Reference List of Tables...................................................................................................... iv
Introduction......................................................................................................................................1
Known and Measurable Adjustments..............................................................................................2
CostOf Service Components...........................................................................................................3
Adjustment A—Other Operating Revenues ..............................................................................3
Description...........................................................................................................................3
Methodology........................................................................................................................3
Adjustments B & C—Other Revenues and Other Expenses.....................................................4
Description...........................................................................................................................4
Methodology........................................................................................................................4
Adjustment DOperations and Maintenance Expenses ("O&M")..........................................5
Overview..............................................................................................................................5
Labor ..............................................................................................................5
Non-Labor............................................................................................................................7
FERCAccount Development ..............................................................................................8
Exceptions to the Described O&M Methodology Above....................................................8
SteamPower Generation....................................................................................................10
Description...................................................................................................................10
Methodology................................................................................................................10
Hydraulic Power Generation..............................................................................................11
Description...................................................................................................................11
Methodology................................................................................................................11
OtherPower Generation ....................................................................................................12
Description...................................................................................................................12
Methodology................................................................................................................12
TransmissionExpenses......................................................................................................12
Page i Exhibit No.21
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Methodology Manual Idaho Power Company
Description...................................................................................................................12
Methodology................................................................................................................13
Regional Market Expenses ................................................................................................13
Description...................................................................................................................13
Methodology................................................................................................................13
EnergyStorage Expenses...................................................................................................13
Description...................................................................................................................13
Methodology................................................................................................................13
DistributionExpenses........................................................................................................14
Description...................................................................................................................14
Methodology................................................................................................................14
Customer Accounting and Customer Services and Information Expenses .......................14
Description...................................................................................................................14
Methodology................................................................................................................14
Administration and General Expenses ("A&G")...............................................................15
Description...................................................................................................................15
Methodology................................................................................................................15
Adjustment EDepreciation and Amortization Expense.......................................................16
Description.........................................................................................................................16
Methodology......................................................................................................................16
Adjustment FElectric Plant/Regulatory AssetsAmortization, Adjustments, Gains
andLosses.......................................................................................................................17
Description.........................................................................................................................17
Methodology......................................................................................................................17
Adjustment GRegulatory Debits and Credits ......................................................................17
Description.........................................................................................................................17
Methodology......................................................................................................................18
Adjustment H—Taxes Other than Income Taxes....................................................................18
Description.........................................................................................................................18
Page ii Exhibit No.21
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Idaho Power Company Methodology Manual
Methodology......................................................................................................................18
Real and Personal Property Taxes ...............................................................................18
IdahoOther Assessments.............................................................................................19
IdahokWh Taxes.........................................................................................................19
Regulatory Commission Fees......................................................................................19
Licenses ..............................................................................1 9
Franchises ....................................................................................................................19
NevadaCommerce Tax................................................................................................19
Adjustment I—Idaho Energy Resources Co. ("IERCO") Cost of Service Components.........19
Description.........................................................................................................................19
Methodology......................................................................................................................20
Adjustment JAllowance for Funds Used During Construction Related to Hells
CanyonRelicensing.........................................................................................................20
Description.........................................................................................................................20
Methodology......................................................................................................................21
RateBase Components..................................................................................................................22
Adjustment KElectric Plant in Service................................................................................22
Description.........................................................................................................................22
Methodology......................................................................................................................22
Adjustments for Bridger and Valmy Coal-Related Plant ..................................................22
Plant Additions to Electric Plant In Service ......................................................................22
Projected 2025 Plant Additions ...................................................................................22
Allocation to FERC Plant Account..............................................................................23
Retirements from Electric Plant In Service .......................................................................23
Adjustments L & MAccumulated Provision for Depreciation and Amortization...............24
Description.........................................................................................................................24
Adjustments for Bridger and Valmy Coal-Related Plant ..................................................24
Methodology......................................................................................................................24
Adjustment NMaterials and Supplies ..................................................................................25
Page III Exhibit No.21
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Methodology Manual Idaho Power Company
Description.........................................................................................................................25
Methodology......................................................................................................................25
Adjustment O—Other Deferred Programs ..............................................................................25
Description.........................................................................................................................25
Methodology......................................................................................................................25
Adjustment P—Plant Held for Future Use ..............................................................................28
Description.........................................................................................................................28
Methodology......................................................................................................................28
Adjustment QCustomer Advances for Construction ("CAC")............................................29
Description.........................................................................................................................29
Methodology......................................................................................................................29
Adjustment R—Idaho Energy Resources Co. Rate Base ........................................................29
Description.........................................................................................................................29
Methodology......................................................................................................................30
CROSS-REFERENCE LIST OF TABLES
Provided in Ms. Noe's Exhibits
Table 4—FERC Accounts 451-456 .............................................................................................3
Tables 4&5—FERC Accounts 415-416 (excluding 415.002 and 416.002).................................4
Table 5—FERC Accounts 500-935 .............................................................................................5
Table 6—FERC Accounts 403 and 404......................................................................................16
Table 6—FERC Accounts 406, 411.6, and 411.7.......................................................................17
Table8—FERC Account 407.3..................................................................................................17
Table7—FERC Account 408.1 ..................................................................................................18
FERCAccounts 418.1 and 419...................................................................................................19
FERCAccounts 107....................................................................................................................20
Table 1—FERC Account 101 .....................................................................................................22
Page iv Exhibit No.21
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Idaho Power Company Methodology Manual
Table 2—FERC Accounts 108 and 111......................................................................................24
Table 3—FERC Accounts 154 and 163......................................................................................25
Table 3—FERC Accounts 182.3 and 186...................................................................................25
Table3—FERC Account 105.....................................................................................................28
Table 3—FERC Account 252.....................................................................................................29
Table 3—FERC Accounts 123.1, 186, and 145..........................................................................29
PaCge V Exhibit No.21
ase No. IPC-E-25-16
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Exhibit No.21
Case No. IPC-E-25-16
M.Larkin, IPC
Page 8 of 38

Idaho Power Company Methodology Manual
INTRODUCTION
The 2025 Methodology Manual is a reference document that provides supporting detail for the
methodologies that have been used to set the values contained in Idaho Power Company's
("IPC")proposed 2025 test year. These values were provided to IPC witness Noe for appropriate
application to the Uniform System of Accounts for determination of revenue requirement in the
2025 test year. The manual is organized in three sections and includes:
• Known and Measurable Adjustments. Known and Measurable Adjustments includes a
description of the methodologies used to develop the 2025 unadjusted test year from the
2024 actual financial data.
• Cost of Service Components. Cost of Service Components includes a description of
the three-digit account number specified in the Uniform System of Accounts adopted by
the Commission and the Federal Energy Regulatory Commission("FERC") and the
method for each major account or account group.
• Rate Base Components. Rate Base Components includes a description of the three-digit
account number specified in the Uniform System of Accounts adopted by the
Commission and the FERC and the method applied for each major account or account
group.
Page 1 Exhibit No.21
Case No. IPC-E-25-16
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Methodology Manual Idaho Power Company
KNOWN AND MEASURABLE ADJUSTMENTS
Updates to the 2024 actual financial data to IPC's proposed 2025 unadjusted test year were
developed using one of the following two methods:
(1) 2024 Base. The 2024 Base refers to actual financial data from 2024, which was used in
cases where IPC determined that certain amounts were likely to remain consistent at 2024
levels or when account balances were immaterial.
(2) Other Adjustments. Other Adjustments are based on known and measurable factors
expected to impact specific accounts in 2025. These factors may include,but are not
limited to, new billing or volume contract terms, the discontinuation of certain services,
anticipated changes in economic activity, and existing orders issued by regulatory
commissions.
Page 2 Exhibit No.21
Case No. IPC-E-25-16
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Idaho Power Company Methodology Manual
COST OF SERVICE COMPONENTS
Adjustment A—Other Operating Revenues
Table 4—FERC Accounts 451-456
Description
Account 451 includes revenues for all miscellaneous services and charges billed to customers
that are not specifically provided for in other accounts. Miscellaneous service revenues include
continuous service reversion charges (Idaho only), field visit charges, return trip charges,
returned check fees, service connection charges, service establishment charges, and application
and processing fees collected for new permits, new leases, or requests for easement
relinquishments. Account 454 includes rents received for the use by others of land, buildings,
and other property devoted to electric operations by IPC such as joint pole attachments, facilities
charges, and line and substation rents. Account 456 includes revenues derived from electric
operations not includable in other revenue accounts. For example, compensation for minor
services provided for others, such as engineering and revenues from transmission of electricity of
others over transmission facilities of IPC, such as network and point-to-point wheeling.
Methodology
Adjustment A reduces Other Operating Revenue by $1,285,244 compared to the 2024 Base. The
2025 amounts for Accounts 451 through 456 were developed using a mix of methodologies,
detailed below by account:
Account 451—Miscellaneous Service Revenues. Revenues for this account are expected to
match the actual 12-month balance ending December 2024.
Account 454—Rent from Electric Property. Revenues for this account were based on one of
three methods-12-month actuals (ending December 2024),the 2020-2024 compound annual
growth rate ("CAGR"), or the five-year average—depending on the revenue type:
• Substation equipment, transformer/distribution rentals, real estate rents,joint pole
attachments, and overnight park rents: Reflect the 12-month actual ending December
2024.
• Cogeneration and small power production: Cogeneration and small power production
revenues were developed using different methods for each jurisdiction. For Idaho,
revenues were based on 2024 actuals plus the estimated impact of the Idaho Schedule 72
rate update of$4,824. For Oregon, the test year amount is consistent with the 2024 Base.
• Facilities Charges: Facility Charges were developed using the 12-month actuals ending
December 2024. For Idaho, this amount was adjusted upward by $545,415 to account for
the estimated 2025 Facility Charge rate increases included in this filing. The Oregon
amount is consistent with the 2024 Base.
• Water District payments: Applied the 2020-2024 five-year average due to annual
variability in water demand and availability.
Page 3 Exhibit No.21
Case No. IPC-E-25-16
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Methodology Manual Idaho Power Company
Account 456—Other Electric Revenues. Revenue amounts for 2025 used either the 12-month
actual ending December 2024 or the Other Adjustment methodology, depending on the revenue
category:
• Miscellaneous and stand-by service: Based on 12-month actuals through December
2024.
• Sierra Pacific Power Company("SPPC") sales: Developed using the 2019-2023 five-
year average. The 2024 actual amount was an outlier due to an SPPC breach of contract
terms resulting in a large penalty assessment, which is not expected to recur.
• Network Transmission Customer revenues: The 2025 Network Transmission
Customer revenues were calculated using the network customers' average load ratio
share applied to the in-effect FERC formula-based transmission revenue requirement.
This was done in two parts: nine months were based on the rate effective from October 1,
2024, through September 30, 2025, and the remaining three months used the rate
effective from October 1, 2025, through September 30, 2026matching the timing used
for point-to-point wheeling revenues. The estimated network customer megawatt demand
for 2025 was derived by taking the 2024 actual demand and applying a 0.9% annual
growth factor.
• Point-to-Point("PTP") Wheeling Revenues: The 2025 PTP wheeling revenues were
calculated using expected equivalent kilowatt-hours (kWh) and FERC formula-based
transmission rates. Specifically, nine months of revenue were based on 2025 equivalent
kWh multiplied by the transmission rate effective from October 1, 2024, to September
30, 2025, while the remaining three months used the expected rate effective from October
1, 2025, to September 30, 2026. To estimate 2025 equivalent kWh for third-parry OATT
non-firm and short-term firm transmission, the average of 2023 and 2024 kWh was used.
The 3rd party long-term firm PTP wheeling revenue for 2025 was based on 2024 actual
megawatt demand and represents a 32 megawatt("MW")year over year change. This
change was driven by a new 86 MW contract that began in May 2024, which added 50
MW to the total,partially offset by the expiration of a 71 MW contract in April 2024,
which reduced the total by 18 MW.
Adjustments B & C—Other Revenues and Other Expenses
Tables 4&5—FERC Accounts 415-416
Description
Accounts 415 through 416 include, respectively, all revenues derived from the sale of
merchandise and jobbing, or contract work and all expenses incurred in such activities. For
Idaho Power,jobbing and contract work revenues and expenses include activities related to
Idaho Power Solutions, water management services, hydro services, qualified reporting entity
services, operating agreements and joint pole use.
Methodology
Adjustment B for Other Revenues (Account 415)reflects an increase of$119,403 compared to
the 2024 Base, while Adjustment C for Other Expenses (Account 416) shows an increase of
Page 4 Exhibit No.21
Case No. IPC-E-25-16
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Idaho Power Company Methodology Manual
$128,655. Both accounts used a combination of methods to develop 2025 values, depending on
the nature of the individual revenue or expense category:
Account 415—Other Revenues. Amounts for Power Solutions, hydro services, water
management services, qualified reporting entity services, and operating agreements were based
on the actual revenues for the 12-month period ending December 2024. Revenues from joint use
(pole)—Idaho and joint use (pole)—Oregon were developed using the three-year average from
2022 to 2024, due to year-to-year variability in these accounts.
Account 416—Other Expenses. Power Solutions, hydro services, water management services,
qualified reporting entity services, operating agreements, and joint use (pole)—Oregon were also
based on actual results from the 12-month period ending December 2024. Expenses for joint use
(pole)—Idaho were developed using the average of actual expenses over the same 2022-2024
period due to year-to-year variability in this account.
Adjustment D—Operations and Maintenance Expenses
("O&M")
Table 5—FERC Accounts 500-935
Overview
Adjustment D reflects an increase of$32,477,237 in Operations and Maintenance (O&M)
Expenses for Accounts 500 through 935 compared to the 2024 Base. This adjustment excludes
any increases to the normalized amounts in Account 501 —Fuel,Account 547—Fuel, Account
555 —Purchased Power, and Account 565 —Transmission of Electricity by Others.
In developing the 2025 test year amounts, IPC separated historical O&M actuals into two
components—Labor and Non-Labor—and developed each element independently. These
amounts were then allocated separately to the applicable FERC accounts. Certain accounts were
excluded from this process, including the previously noted net power supply expense accounts as
well as Accounts 908.131 and 908.132 (Idaho and Oregon Energy Efficiency Riders), 920.001
(Incentive), 926.203, 926.204, and 926.303 (Pension Expense), 928.203 (Regulatory
Commission Expense) and 93 0.100 (Advertising Expense), all of which were addressed through
separate methodologies.
Labor
To determine 2025 O&M base labor costs, IPC began by calculating the average ratio of
February year-to-date actual O&M labor costs to full-year actual non-annualized O&M labor
costs over the prior three years. This ratio was determined to be 16.6%. IPC then applied this
percentage to the actual February 2025 year-to-date O&M labor amount of$34,587,092 to
calculate total non-annualized 2025 O&M base labor at $207,823,155.
The tables below detail the 2025 O&M base labor amount:
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Methodology Manual Idaho Power Company
2025 O&M Base Labor Expenses Total
February Y-T-D O&M Labor Excluding ST Incentive&Pension $34,587,092
Divided by the Historical February Y-T-D as a Percentage of Total Year Labor 16.6%
2025 O&M Base Labor Expense Excluding ST Incentive and Pension $207,823,155
IPC calculated an annualizing adjustment of$1,724,869 by multiplying December 2024 straight
time labor by 13 (there are 26 pay periods in the year) and comparing that total to the actual total
year 2024 straight time labor. Finally, IPC calculated the December 2025 general wage
adjustment("GWA") of$6,286,441 by multiplying the sum of the 2025 O&M base labor and the
annualizing adjustment by 3%.
The resulting sum of$215,834,465 (reflecting the 2025 O&M base labor, the annualizing
adjustment, and the December 2025 GWA) was then allocated across FERC accounts based on
the distribution of actual labor charges to those accounts in 2024.
2025 O&M Labor Expenses Total Allocated Direct
Assignment
2025 O&M Base Labor Expense Excluding ST Incentive and $207,823,155 $207,823,155 —
Pension
Payroll Annualizing Adjustment 1,724,869 1,724,869 —
December 2025 GWA 6,286,441 6,286,441 —
ST Incentive 11,949,316 — $11,949,316
Pension (Idaho and Oregon) 35,725,239 — 35,725,239
Total 2025 Labor Expenses $263,509,020 $215,834,465 $47,674,555
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Non-Labor
IPC calculated 2025 non-labor O&M expenses by starting with 2024 actual non-labor expenses
and making adjustments for significant known changes. The company reviewed these expenses
to identify areas where, based on specific knowledge, costs in 2025 are expected to differ
materially from 2024 actuals.
The table below outlines significant, specific increases or decreases included in 2025 test year
non-labor O&M:
2025 O&M Non-Labor Expenses Total Allocated Direct
Assignment
2024 Base O&M Non-Labor Actuals $180,041,590 $0 $180,041,590
2025 Identified Significant Known Adjustments
Water for Power Adjustment 1,125,686 — 1,125,686
Wildfire Mitigation Plan Adjustment 17,139,612 — 17,139,612
BESS Maintenance Adjustment 1,870,920 — 1,870,920
Airplane Inspection Adjustment (688,841) — (688,841)
Subtotal 2025 Identified Significant Known Adjustments 19,447,377 — 19,447,377
Total 2025 O&M Non-Labor Expenses $199,488,967 — $199,488,967
Does not include property insurance annualizing adjustment of$112,609 or intervenor funding increase of$53,887.
The following adjustments to the 2024 Base included in the table above have been directly
assigned to one or more FERC accounts:
• Water for Power Adjustment—Account 536 reflects an increase of$1,125,686 over the
2024 Base. This change is due to a $2,230,246 reduction in grant credits related to work
performed prior to 2024 that is not expected to recur in 2025. This increase is partially
offset by a $1,104,560 decrease resulting from the full amortization of the American Falls
Bond, completed in February 2025.
• Wildfire Mitigation Plan Adjustment—Accounts 571, 583, 593, 596, 924, and 925
were collectively increased by $17,139,612 in accordance with the 2025 Idaho Wildfire
Mitigation Plan Deferral filing. This adjustment reflects costs associated with wildfire
mitigation efforts as outlined in the plan.
• Battery Energy Storage System (`BESS") Maintenance—Account 578 was increased
by $1,870,920 to account for Long-Term Service Agreement payments related to battery
storage facilities that became or will become operational in 2023, 2024 and 2025 and are
expected to remain in service throughout 2025.
• Airplane Inspection—Account 921 was decreased by $688,841 from the 2024 Base due
to the exclusion of airplane inspection costs that were incurred in 2024 but are not
expected to recur in 2025.
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Once the O&M labor and non-labor increases or decreases were determined for each FERC
account, the results were combined to produce the total known and measurable adjustment,
reflecting the overall change in projected 2025 O&M expenses compared to the 2024 Base.
FERC Account Development
Because IPC does not develop test year values by individual FERC account,the following two
methods (Direct Assignment and Allocation)were used to assign both labor and non-labor to the
appropriate FERC accounts.
Direct Assignment Method—The adjustments listed in the direct assignment column in the
non-labor expenses above are charges that would occur in specific accounts and therefore were
directly assigned to the following accounts:
• Account 536—Water for Power Adjustment
• Account 571, 583, 593, 596, 924, and 925—Wildfire Mitigation Plan Adjustment
• Account 578—BESS Maintenance Adjustment
• Account 921—Airplane Inspection Adjustment
Allocation Method—The allocation method was applied in cases where identifying specific
accounts was not feasible or when the impact was expected to affect all accounts. O&M labor
was distributed across individual FERC accounts using the percentage of 2024 actual O&M
labor charges attributed to each account relative to total O&M labor charges incurred in 2024.
Exceptions to the Described O&M Methodology Above
FERC Accounts 501, 547, 555, 555.050, 557, 565, 908.131, 908.132, 920.001, 926.203,
926.204, 926.303, and 928.203
As stated earlier, the following were developed separately from the labor and non-labor O&M
adjustments described above and directly assigned to the FERC accounts they impact:
• Account 501—Fuel Expense. This account is determined using the AURORAxmp®
Model.
• Account 547—Fuel Expense (Excluding 547.000—Salmon Diesel). This account is
determined for the test year using the AURORAxmpo Model.
• Account 555—Purchased Power(Including 555.050). This account is determined for
the test year using the AURORAxmp®Model.
• Account 557—Other Expense (Excluding 557.000 and 557.007). The amounts in these
accounts have been removed in their entirety from the test year.
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• Account 565—Transmission of Electricity by Others. This account is determined for
the test year using the AURORAxmp®Model.
• Account 908.131 and 908.132—Idaho and Oregon Energy Efficiency Rider
Expenses. The amounts in these accounts have been removed from the 2024 Base in their
entirety per IPUC Order No. 30189.
• Account 920.001—Incentive Expense. This account was adjusted by removing the full
actual 2024 incentive expense of$30,168,168 from the 2024 Base and replacing it with a
calculated 2025 incentive amount of$11,949,316. The 2025 test year amount includes
only those incentive elements related to Customer Satisfaction and Reliability. This
adjustment resulted in a net reduction of$18,218,852 in incentive expense.
• Accounts 926.203, 926.204 and 929.303—Pension Expense. In the Idaho jurisdiction,
per IPUC Order No. 36042, Idaho Power is currently recovering $35,182,378 of its cash
contributions to its defined benefit pension plan as reflected in the 2024 Base (Account
926.204). The amount was held equal to the 2024 Base, with no adjustments made.
Oregon pension expense (Accounts 926.203 and 926.303)was also held equal to the
2024 Base, with no adjustments made.
• Accounts 928.203—Regulatory Commission Expense. Intervenor Funding increased
by $53,887 for 2025, based on the assumption of a one-year amortization period,per the
following Orders:
• IPUC Order Nos. 36042IIPA for$30,693, CEO for$3,965,NWEC for $2,563, ICL
for$6,876.
• IPUC Order No. 36048—Vote Solar for$9,790.
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Methodology Manual Idaho Power Company
The following O&M discussion has been organized by functional account groups. Within each
account group, a general description of the accounts has been provided.
Steam Power Generation
FERC Accounts 500-514
Description
Accounts 500 through 514 include the labor, materials, and expenses incurred to operate and
maintain prime movers, generators, and their auxiliary apparatus, switch gear, and other electric
equipment used in steam power generation. Additionally, the labor and expenses incurred in the
general supervision and direction of maintenance of steam generation facilities are included in
these accounts.
Methodology
Accounts 500-514—Excluding Account 501,Fuel Expense.
Bridger Power Plant- Coal-related capital investment and all O&M associated with the Bridger
Power Plant were removed from IPC's 2024 Actuals as these costs are separately captured in the
Bridger balancing account mechanism established and approved by IPUC Order No. 35423.
The Bridger annual levelized revenue requirement with a proposed effective date of January 1,
2026, is a$17,629,326 increase from the annual levelized revenue requirement included in IPC-
E-23-11 primarily due to the following factors:
• Add into the mechanism the balance of the deferred O&M variance between O&M
forecasted in the mechanism and actuals from 2021 through 2024.
• Incorporate a full O&M forecast into the mechanism for 2025 through 2030.
• Update capital investment(coal-related only) actuals through year-end 2024 and forecast
(coal-related only) 2025 through 2030.
• Reduce carrying charge rate and jurisdictional split for Idaho, based on IPC-E-23-11,
effective 1/l/2024.
• Add into the mechanism the load variance balance at 12/31/24.
Valmy Power Plant- Coal-related capital investment associated with the Valmy Power Plant was
removed from IPC's 2024 Actuals as these costs are separately captured in the Valmy balancing
account mechanism established, approved, and updated through IPUC Order Nos. 34349 and
35494.
The Valmy annual levelized revenue requirement with a proposed effective date of January 1,
2026, is a$788,860 increase from the annual levelized revenue requirement included in IPC-E-
22-05 primarily due to the following factors:
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• Add into the mechanism the balance of the deferred O&M variance between O&M
forecasted in the mechanism and actuals from 2019 through 2024.
• Remove O&M forecast from 2026 through 2028.
• Update capital investment actuals (coal-related only)through 2024 and expected(coal-
related only) for 2025.
• Reduce carrying charge rate and jurisdictional split for Idaho,based on IPC-E-23-11,
effective 1/l/2024.
• Add into the mechanism the load variance balance at 12/31/24.
• Update decommissioning forecast for coal-yard reclamation.
Account 501—Fuel Expense. Fuel expense is determined for the test year using the
AURORAxmp®Model.
Hydraulic Power Generation
FERC Accounts 535-545
Description
Accounts 535 through 545 include the labor, materials used, and expenses incurred to operate
and maintain hydraulic works including structures, reservoirs, dams, waterways, generators,
roads and bridges, and expenses directly related to the hydroelectric development outside the
generating station, including fish and wildlife and recreational facilities. These accounts also
include the labor and expenses incurred in the general supervision and direction of maintenance
of hydraulic power generating stations, rents of property of others used, occupied, or operated in
connection with hydraulic power generation, including amounts payable to the United States for
the occupancy of public lands and reservations for reservoirs, dams, flumes, forebays, penstocks,
and power houses.
Methodology
Accounts 535-545—Amounts for Accounts 535-545 were developed using both labor and non-
labor methodologies described under the FERC Account Development approach. For the labor
component, these accounts were allocated a portion of the total 2025 O&M labor adjustment
based on the actual labor distribution recorded in 2024. For the non-labor component, the test
year amount was based on the 2024 Base, with an adjustment to Account 536 reflecting a net
increase of$1,125,686. This adjustment accounts for a $2,230,246 reduction in grant credits
related to pre-2024 work not expected to recur in 2025, partially offset by a $1,104,560 decrease
due to the full amortization of the American Falls Bond in February 2025.
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Other Power Generation
FERC Accounts 546-557
Description
Accounts 546 through 554 include the operation labor, materials used, and expenses incurred in
operating and maintaining prime movers, generators, and electric equipment in other power
generating stations. Labor and expenses incurred in the general supervision and direction of
maintenance of other power generating stations are also included in these accounts. Account 556
includes labor and expenses incurred in load dispatching activities for system control. System
control activities include the production and dispatching of electricity. Account 557 includes
production expenses incurred directly in connection with the purchase of electricity which is not
specifically provided for in other production expense accounts.
Methodology
Accounts 546-557—Excluding Account 547,Fuel Expense; Account 555, Purchased Power;
and Account 557, Other Expense.Accounts 546-557 were developed using both labor and
non-labor methodologies outlined under the FERC Account Development section above. For the
labor portion, these accounts were allocated their share of total 2025 O&M labor based on the
distribution of actual labor charges in 2024. For the non-labor portion, 2025 was held equal to
the 2024 Base, with no adjustments made.
Account 547—Fuel Expense and Account 555—Purchased Power (Including 555.050).
Fuel and purchased power were developed for the test year using the AURORAxmp®Model.
Account 557, Other Expense (Excluding 557.000 and 557.007—Other Power Production
Expense). These expenses are removed entirely from the test year.
Transmission Expenses
FERC Accounts 560-573
Description
Accounts 560 through 573 include the operation labor, materials used, and expenses incurred in
the system planning, operation, executing the reliability coordination function, monitoring,
assessing, and operating the power system and individual transmission facilities in real-time to
maintain safe and reliable operation of the transmission system specified. Additional activities
include: processing the hourly, daily, weekly, and monthly transmission service requests using
an automated system such as an Open Access Same-Time Information System ("OASIS");
billing to transmission owners for system control and dispatching service; and conducting
transmission services studies for proposed transmission interconnections and generation
interconnection with the transmission system. These accounts include the labor, materials used,
and expenses incurred in the operation of transmission substations, switching stations, and
transmission lines. The use of transmission facilities owned by others and rents of property used,
occupied, or operated in connection with the transmission system are also part of this account.
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The accounts also include the labor, materials used, and expenses incurred in the maintenance of
structures, computer hardware and software, communication equipment, miscellaneous
transmission plant, station equipment, and transmission plant serving the transmission function.
Methodology
Accounts 560-573—Excluding Account 565.000, Transmission of Electricity by Others.
Amounts for Accounts 560-573 were developed using both labor and non-labor methodologies
described under FERC Account Development. For the labor component, these accounts received
their allocated share of total 2025 O&M labor based on actual labor distributions from 2024. For
the non-labor component, the amount was based on the 2024 Base and included an adjustment of
$1,755,160 to Account 571 to reflect costs associated with the Wildfire Mitigation Program.
• Account 565—Transmission of Electricity by Others. This account was developed
using the AURORAxmp®Model.
Regional Market Expenses
FERC Accounts 575-576
Description
Accounts 575 through 576 include labor, materials used, and expenses incurred in the general
supervision and direction of the regional energy markets. These accounts also include the costs
billed to the transmission owner, load serving entity or generator for market administration,
monitoring and compliance services.
Methodology
Accounts 575-576.Accounts 575-576 were developed using both methods described under
FERC Account Development above. These accounts were set equal to the 2024 Base.
Energy Storage Expenses
FERC Accounts 577-578
Description
Accounts 577 through 578 include labor, materials used, and expenses incurred in the general
supervision and direction of the operation of energy storage plant. These accounts also include
the cost of labor, materials used, and expenses incurred in the maintenance of energy storage
structures, energy storage equipment, and other energy storage plant.
Methodology
Accounts 577-578—The amount for Accounts 577-578 is based on estimated new activities
related to BESS maintenance. Account 578 is set to $1,870,920 in 2025, reflecting anticipated
Long-Term Service Agreement costs associated with these facilities.
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Distribution Expenses
FERC Accounts 580-598
Description
Accounts 580 through 598 include labor, materials used, and expenses incurred in the general
supervision and direction of the operation of the distribution system such as station operation,
overhead and underground line operation, meter department operation of customer meters and
associated equipment, load dispatching operations, work on customer installations,
and inspecting premises. Also included in these accounts are the labor, materials used, and
expenses incurred in the general supervision and direction of the maintenance of the distribution
system, including maintenance of structures, distribution plant, overhead distribution line
facilities,underground distribution line facilities, distribution line transformers, meters,
and meter testing equipment.
Methodology
Accounts 580-598—Accounts 580-598 were developed using both labor and non-labor
methodologies outlined under FERC Account Development. For labor, these accounts received
their allocated portion of total 2025 O&M labor based on actual 2024 labor. The non-labor
component began with the 2024 Base and included an adjustment of$9,787,150 to Accounts
583, 593, and 596 to reflect costs associated with the Wildfire Mitigation Program.
Customer Accounting and Customer Services
and Information Expenses
FERC Accounts 901-905 and 907-912
Description
Accounts 901 through 905 include the labor, materials used, and expenses incurred in the general
direction and supervision of customer accounting and collecting activities, including reading
customer meters, work on customer applications, contracts, orders, credit investigations,
billing and accounting, collections, and complaints. These accounts also include the accounting
for losses from uncollectible utility revenues. Accounts 907 through 912 include the labor and
expenses incurred in customer service and informational activities to encourage safe and efficient
use of the utility's service, to encourage conservation of the utility's service, and answer specific
inquiries as to proper use of the service and equipment utilizing the service.
Methodology
Accounts 901-905 and 907-912—Excluding Account 908.131 and 908.132, Idaho and
Oregon Energy Efficiency Rider. Accounts 901-905 and 907-912, excluding the Idaho and
Oregon Energy Efficiency Rider(energy efficiency expenses), were developed using both
methods described under FERC Account Development above. For labor, these accounts received
their allocated portion of total 2025 O&M labor based on actual 2024 labor. The non-labor is set
to the 2024 Base.
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Account 908.131 and 908.132—Idaho and Oregon Energy Efficiency Rider. The expenses
associated with the Idaho and Oregon Energy Efficiency Riders have been excluded from the
2025 test year in their entirety (IPUC Order No. 30189).
Administration and General Expenses ("A&G')
FERC Accounts 920-935
Description
Accounts 920 through 935 include activities undertaken in connection with the utility's general
and administrative operations that are assignable to specific administrative or general
departments and are not specifically provided for in other accounts. A&G accounts include:
(1) compensation of officers, executives, and other employees of the utility which are properly
chargeable to utility operations but not chargeable directly to a particular operating function,
(2) office supplies and expenses, (3) fees and expenses of professional consultants and others for
general services which are not applicable to a particular operating function, (4) insurance or
reserve accruals to protect the utility against losses and damages to owned or leased property
used in its utility operations, (5)payments for employee accident, sickness, hospital, and death
benefits or insurance, (6) payments to municipal or other governmental authorities, (7)the cost
of materials, supplies, and services furnished to such authorities without reimbursement in
compliance with franchise, ordinance, or similar requirements, (8) expenses incurred by the
utility in connection with formal cases before regulatory commissions or other regulatory bodies,
(9)regulatory fees assessed against the utility, (10) commission expenses, (11)payments made
to the United States for the administration of the Federal Power Act, (12) materials used and
expenses incurred in advertising and related activities, (13) rents properly includable in operating
expenses for the property of others used, occupied, or operated in connection with customer
accounts, customer service, and informational sales and general and administrative functions of
the utility, and(14) operation and maintenance of transportation equipment and the maintenance
of utility property which is not chargeable directly to a particular operating function.
Methodology
Accounts 920-935—Excluding Account 920.001,Incentive Expense, 926.203, 926.204,
926.303, Pension Expense and 928.203,Regulatory Commission Expenses. The amount for
Accounts 920-935 was developed using both labor and non-labor methodologies outlined under
FERC Account Development. For the labor portion, these accounts received their allocated share
of total 2025 O&M labor based on actual 2024 labor distributions. The non-labor portion was set
to 2024 Base, with an adjustment of$5,597,303 to Accounts 924 and 925 to account for costs
associated with the Wildfire Mitigation Program.
Account 920.001—Incentive Expense. This account was adjusted by removing the full actual
2024 incentive expense of$30,168,168 from the 2024 Base and replacing it with the 2025 test
year incentive amount of$11,949,316. The 2025 projection includes only those incentive
elements related to Customer Satisfaction and Reliability. This adjustment resulted in a net
reduction of$18,218,852 in incentive expense.
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Accounts 926.203, 926.204, and 926.303—Pension Expense.In the Idaho jurisdiction,
pursuant to IPUC Order No. 36042, IPC is currently recovering $35,182,378 related to its cash
contributions to the defined benefit pension plan. Idaho Power is not requesting a change in
recovery for this account for 2025 (Account 926.204). For the Oregon jurisdiction, the accounts
remain consistent with the 2024 Base amount of$542,861 (Accounts 926.203 and 926.303).
Account 928.203—Regulatory Commission Expenses. Intervenor Funding (as directed in
IPUC Order Nos. 36042 and 36048) is expected to increase by $53,887 for 2025,based on the
assumption of a one-year amortization period.
Adjustment E—Depreciation and Amortization Expense
Table 6—FERC Accounts 403 and 404
Description
Account 403 includes depreciation expense for all classes of depreciable electric plant in service
except such depreciation expense as is chargeable to clearing accounts or to account 416, Costs
and Expenses of Merchandising, Jobbing and Contract Work. Account 404 includes amortization
charges applicable to amounts included in the electric plant accounts for limited-term franchises,
licenses,patent rights, limited-term interest in land, and expenditures on leased property where
the service life of the improvements is terminable by action of the lease. The charges to this
account are such as to distribute the book cost of each investment as evenly as may be over the
period of its benefit to the utility.
Methodology
Adjustment E increases Depreciation and Amortization Expense (Accounts 403 and 404)by
$23,268,591 above the 2024 Base. The 2024 actual depreciation expense was adjusted to remove
$26,482,833 in Bridger coal-related depreciation and $23,132,116 in Valmy coal-related
depreciation.
Depreciation and amortization rates were then applied to monthly estimated plant balances,using
the updated rates established in IPUC Order No. 35272, which were used for the entire 2025 test
year. For plant accounts with sub-accounts, individual sub-account data was used to calculate
composite depreciation rates, which were then applied at the major account level.
It should be noted that for certain plant accounts—specifically Account 392 (Transportation
Equipment), Account 396 (Power Operated Equipment), and Account 312 (Boiler Plant
Equipment)—all or a portion of the depreciation expense is recorded to accounts other than
Account 403.
An annualizing adjustment of$7,381,223 was made and was calculated by multiplying
December 2025 depreciation and amortization expense by twelve and then comparing that
amount to the non-levelized 2025 depreciation and amortization expense.
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Adjustment F—Electric Plant/Regulatory Assets—
Amortization, Adjustments, Gains and Losses
Table 6—FERC Accounts 406, 411.6, and 411.7
Description
Account 406 is debited or credited, as the case may be, with amounts includable in operating
expenses,pursuant to approval or order of the Commission, for the purpose of providing for the
extinguishment of the amount in Account 114, Electric Plant Acquisition Adjustments. Accounts
411.6 and 411.7 include, as approved by the Commission, amounts relating to gains and losses
from the disposition of future use utility plant, including amounts which were previously
recorded in and transferred from Account 105, Electric Plant Held for Future Use.
Methodology
Adjustment F is $0, meaning there is no change to the Amortization of Electric Plant Acquisition
Adjustments (Account 406) or Gains and Losses from Disposition of Utility Plant(Accounts
411.6 and 411.7), which remain consistent with the 2024 Base. For 2025, Account 406 is
expected to continue at the same level, which includes the amortization of the acquisition
adjustment associated with the Exchange of Certain Transmission Assets with PacifiCorp. This
adjustment, approved by IPUC Order No. 33313, OPUC Order No. 15-184, and FERC Order No.
20150617-3060, represents amortizing the amount recorded in Account 114 over 50 years at an
annual rate of$15,018. The balance in Account 114 is scheduled to be fully amortized by
October 2065.
Adjustment G—Regulatory Debits and Credits
Table 8—FERC Account 407.3
Description
Account 407.3 is debited, when appropriate, with the amounts credited to account 254,
Other Regulatory Liabilities, to record regulatory liabilities imposed on the utility by the
ratemaking actions of regulatory agencies. This account is also debited, when appropriate,
with the amounts credited to Account 182.3, Other Regulatory Assets, concurrent with the
recovery of such amounts in rates.
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Methodology
Adjustment G increases Regulatory Debits (Account 407.3)by $10,402,322 above the 2024
Base. This adjustment primarily reflects the amortization of authorized deferred costs, and
projected deferred costs related to wildfire mitigation. As of December 2024, IPC had recorded a
regulatory asset in Accounts 182.310 (amounts deferred in 2023 and 2024) and 182.311
(amounts deferred as of December 2022) for deferred incremental wildfire mitigation expenses,
authorized by IPUC Orders No. 35077, 35717, and 36042. IPC is projecting to defer$32,998,000
in 2025 for incremental wildfire mitigation expenses that is pending an IPUC Order(see IPC-E-
25-05). For 2025, IPC is expects amortization of$14,289,451 related to deferred wildfire
mitigation expenses. This amount includes $3,811,175 in amortization of deferred amounts as of
December 2022 authorized by IPUC Order No. 36042 beginning January 2024 over a seven-year
period, and an additional $10,478,276 in new amortization of amounts deferred in 2023 through
2025, calculated to be amortized over a seven-year period.
Amortization of deferred cloud computing costs is $75,954 below the 2024 Base due to an
increase of$11,430 in the amortization of Zycus license costs partially offset by a decrease of
$87,384 in the amortization of Azure license costs.
All other Regulatory Debits are equal to 2024 Base amounts.
Adjustment H—Taxes Other than Income Taxes
Table 7—FERC Accounts 600-602
Description
Accounts 600-602 include those taxes other than income taxes which relate to utility operating
income. This account is maintained to allow ready identification of the various classes of taxes
relating to utility operation, plant leased to others, and other operating income.
Methodology
Adjustment H decreases Taxes Other Than Income by $12,637,610 compared to the 2024 Base.
The 2025 amounts for these taxes were developed using a combination of known adjustments
specific to individual account activities and a carry-forward of 2024 Base amounts where no
material changes were identified.
Real and Personal Property Taxes
In Idaho, a new law passed in 2025 replaces the property tax on electric utilities with a tax based
on kilowatt-hours sold. Beginning January 1, 2026, this new tax will be itemized and collected
directly from customers on their bills. Accordingly,the 2025 test year amount for Idaho property
taxes has been reduced to zero. In Oregon, Idaho Power and the Oregon Department of Revenue
settled four years of litigation in 2024. As a result, the valuation method for Idaho Power's
property was established for the next five years in accordance with ORS 309.115 and OAR 150-
309-0190(2). In Montana,property taxes are assessed biannually, and the 2025 assessment will
remain unchanged from the prior year. In Nevada, Idaho Power's assessed value had been
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declining due to the closure of the Valmy Power Plant; however, a three-year average was used
for the 2025 test year to reflect the impact of the gas conversion project and increased plant
investment.
Idaho Other Assessments
Idaho special assessments, such as those for landfill and irrigation districts, have historically
been billed through the property tax system. However, as a result of the new Idaho property tax
law, these special assessments will be billed separately.
Idaho kWh Taxes
Test Year 2025 kWh taxes were projected based on normalized hydro conditions and normalized
consumption.
Regulatory Commission Fees
The 2025 Idaho regulatory fee was calculated by applying the prior year's tax rate to known
Idaho gross intrastate revenues. For Oregon,both components of the regulatory fee—the Public
Utility Commission of Oregon fee and the Oregon Department of Energy fee—were set to
remain consistent with the 2024 Base.
Licenses
The 2025 Wyoming and Shoshone—Bannock license fees were estimated using the prior year's
actual amounts, which are consistent with the 2024 Base.
Franchises
The Oregon franchise tax was calculated using the prior year's actual amount, which is
consistent with the 2024 Base.
Nevada Commerce Tax
The Nevada Commerce tax was calculated using the prior year's actual amount, which is
consistent with the 2024 Base.
Adjustment 1—Idaho Energy Resources Co. ("IERCO") Cost
of Service Components
FERC Accounts 418.1 and 419
Description
Account 418.1 includes the utility's equity in the earnings or losses of subsidiary companies for
the year. Account 419 includes interest revenues on securities, loans, notes, advances, special
deposits, tax refunds, all other interest-bearing assets, and dividends on stocks of other
companies, whether the securities on which the interest and dividends are received are carried as
investments or included in sinking or other special fund accounts.
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Methodology
Adjustment I increases IERCO Cost of Service Components (Accounts 418.1 and 419) by
$742,413 above the 2024 actual amount of$2,180,587,resulting in 2025 net income of
$2,923,000. This estimate reflects activity for the Bridger Coal Company("BCC") mine, as well
as a$3.7 million earnings margin calculated using the most recent estimate of IERCO's rate base
and applying the Weighted Average Cost of Capital approved in Idaho Power's 2023 General
Rate Case.
IPC owns 100% of IERCO, which in turn holds a one-third joint venture interest in BCCa
mine that supplies coal to the Jim Bridger power plant. PacifiCorp owns the remaining two-
thirds interest and serves as the mine's operating partner. As a one-third owner of BCC, IERCO
is entitled to 33% of BCC's net income and associated cash flows.
IERCO receives overriding royalties based on the location and lease under which BCC is
mining, with the three leaseholders being the Bureau of Land Management(`BLM"), Union
Pacific Railroad, and the State of Wyoming. Each lease carries a different royalty rate. These
royalties were originally granted to BCC by IERCO, which had previously received them from
IPC as advance royalties. Because revenue is recognized when royalty payments are received
from BCC and expenses are recorded when remitted to IPC,these transactions have no impact on
IERCO's net income.
Income taxes are calculated using the federal corporate tax rate of 21%, as Wyoming imposes no
state income tax. Taxes are accrued and paid throughout the calendar year.
Additionally, as noted in the Rate Base Components section, IERCO maintains an intercompany
note with IPC that accrues interest monthly at IPC's short-term borrowing rate, expected to be
0.36%per month(or 4.36% annually) in 2025. For cost-of-service purposes, the intercompany
interest expense, net of income tax, is added back to IERCO's net income.
Adjustment J—Allowance for Funds Used During
Construction Related to Hells Canyon Relicensing
FERC Account 107
Description
Account 107 (Construction Work in Progress) includes the total of the balances of work orders
for electric plant in process of construction. Work orders shall be cleared from this account as
soon as practicable after completion of the job. Expenditures on research, development, and
demonstration projects for construction of utility facilities are to be included in a separate
subdivision in this account. Also included in this account is an Allowance for Funds Used
During Construction("AFUDC"). AFUDC includes the net cost for the period of construction
of borrowed funds used for construction purposes and a reasonable rate on other funds when
so used, not to exceed, without prior approval of the Commission. The rates shall be
determined annually.
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Methodology
Adjustment J increases the collection of AFUDC related to Hells Canyon Relicensing by
$29,708,787. IPC began incurring relicensing costs for the Hells Canyon Project in 1999. These
costs have been financed through a combination of internally generated funds, short-term and
long-term debt, and new equity. IPC accrues and capitalizes these financing costs to Account 107
as AFUDC during the construction phase, with the AFUDC calculated monthly using a rate
derived from a FERC-prescribed formula.
In the 2023 Idaho General Rate Case (IPUC Order No. 36042), the collection of annual Idaho
jurisdictional AFUDC associated with the Hells Canyon Relicensing was authorized at
$8,803,453.
In March 2025, Idaho Power filed an application(IPC-E-25-13) requesting authority to increase
the collection of AFUDC related to Hells Canyon Relicensing by$29,708,787, bringing the total
annual Idaho jurisdictional collection to $38,512,240.
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RATE BASE COMPONENTS
Adjustment K—Electric Plant in Service
Table 1—FERC Account 101
Description
This account includes the original cost of electric plant that is included in accounts 301 to 399
(referred to herein as plant accounts). It is described as being owned and used by the utility in its
electric utility operations and having an expectation of life in service of more than one year from
date of installation, including such property owned by the utility but held by nominees.
Methodology
Adjustment K increases Electric Plant In Service (Account 101)by $699,765,372 above the 2024
Base. Electric Plant In Service is presented using a thirteen-month average.
The methodologies used for plant additions and retirements are described below.
Adjustments for Bridger and Valmy Coal-Related Plant
The December 31, 2024, actual Electric Plant In Service balance was adjusted to exclude
$420,228,082 related to Bridger coal-related plant and$262,102,107 related to Valmy coal-
related plant. There were no dollars associated with Bridger or Valmy coal-related plant included
in the 2025 plant additions as discussed below.
Plant Additions to Electric Plant In Service
2025 additions to Electric Plant In Service were developed by analyzing actual project closings
as a percentage of Construction Work in Process ("CWIP") as of year-end 2024, combined with
expected 2025 capital expenditures. Capital projects were categorized into two pools: those
greater than$2 million and those less than $2 million. Projects exceeding $2 million were
included in the test year on a project-by-project basis, while additions for projects under$2
million were determined using a historical trend methodology.
Projected 2025 Plant Additions
Capital Projects Greater than $2 Million. Capital projects with total costs exceeding $2
million reflect known and measurable projects included in the 2025 unadjusted test year. To
determine the amount expected to close to plant by year-end 2025, IPC used actual capital
expenditures recorded in CWIP as of year-end 2024, along with projected 2025 capital
expenditures, including applicable AFUDC and overheads. AFUDC and overheads were accrued
on CWIP balances prior to their anticipated close dates. Additionally, the projected capital
account balances, planned expenditures, and timing of project closings were reviewed by
business unit managers with direct knowledge of the individual projects. The total plant additions
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within the over$2 million pool were then assigned project types based on the specific nature of
each project.
Capital Projects Less Than $2 Million. 2025 plant closings for projects under$2 million were
determined by applying the five-year historical average percentage of similar-sized project
closings to the prior year's CWIP balance,using the December 31, 2024, CWIP balance as the
base. Total plant additions for this pool were then allocated to specific project types based on a
five-year historical average.
Allocation to FERC Plant Account
The CWIP project type pools—those over and under$2 million—were combined for final
allocation to FERC plant accounts. To perform this allocation, IPC analyzed actual final closings
from CWIP (Account 107) into Electric Plant In Service (Account 101) over the five-year period
from 2020 through 2024. Final closing data from the PeopleSoft Asset Management system was
used for this analysis, as it reflects the "as built"property units after construction completion and
reconciliation of individual work orders. This approach provides a more accurate representation
of plant account distribution compared to pre-close data, which is based on estimated work order
assignments and may not align with final outcomes. For each CWIP project type, the percentage
allocation to FERC plant accounts 301 through 399 was determined by calculating the ratio of
final plant account closings over the five-year historical period for that specific project type.
Retirements from Electric Plant In Service
Retirements were analyzed for the previous five-year period 2020 through 2024. Retirements by
FERC plant account were determined and compared to the final closings by FERC plant account
for the same period. Retirements by FERC plant account were estimated by calculating the
historical percentage of retirements to additions for the five-year period.
The following FERC plant accounts have known retirement dates based on vintage layers and
were not estimated:
• Account 302 Franchises and consents
• Account 303—Miscellaneous intangible plant
• Account 391 Office furniture and equipment
• Account 393—Stores equipment
• Account 394—Tools, shop, and garage equipment
• Account 395Laboratory equipment
• Account 397Communication equipment
• Account 398—Miscellaneous equipment
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Adjustments L & M—Accumulated Provision for Depreciation
and Amortization
Table 2—FERC Accounts 108 and 111
Description
Account 108 is credited for amounts charged to account 403, Depreciation Expense, or to
clearing accounts for current depreciation expense for electric plant in service. At the time of
retirement of depreciable electric utility plant, this account is charged with the book cost of the
property retired and cost of removal and then credited with the salvage value and any other
amounts recovered, such as insurance.
Account I I I is credited with amounts charged to account 404, Amortization of Limited-Term
Electric Plant, for the current amortization of limited-term electric plant investments.
Adjustments for Bridger and Valmy Coal-Related Plant
The December 31, 2024, actual Accumulated Provision for Depreciation balance was adjusted to
exclude $327,754,520 related to Bridger coal-related plant and$224,110,326 related to Valmy
coal-related plant.
Methodology
Adjustments L and M increase the Accumulated Provision for Depreciation and Amortization by
$70,925,932 and $6,619,735, respectively, above the 2024 Base. These adjustments apply to
Accounts 108 and I I I and are presented using a thirteen-month average. The 2025 test year was
developed by first establishing the 2024 monthly balances, which were then used as the
foundation to calculate the 2025 test year thirteen-month average balances for the accumulated
provision accounts.
The process began with the year-end 2024 accumulated depreciation and amortization account
balances, which were then rolled forward on a monthly basis using estimated 2025 depreciation
and amortization expense accruals, retirements, salvage, and removal costs. See Accounts 403
and 404 in the Cost of Service Components section for a detailed discussion of the depreciation
and amortization accrual calculation. Additionally, refer to Electric Plant In Service, Account
101, in the Rate Base Components section for a discussion of the methodology used to determine
retirements. To estimate salvage and removal costs, IPC calculated the five-year(2020-2024)
average for salvage, removal costs, and retirements by functional area—Steam Production,
Hydraulic Production, Other Production, Transmission Plant, Distribution Plant, and General
Plant. The average salvage and removal costs were then expressed as a percentage of the average
retirements, and these ratios were applied to determine monthly salvage and removal costs for
2025. These estimates were allocated to FERC plant accounts in proportion to the corresponding
estimated retirements.
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Adjustment N—Materials and Supplies
Table 3—FERC Accounts 154 and 163
Description
Account 154 includes the cost of materials purchased primarily for use in the utility business for
construction, operation, and maintenance purposes. Materials and supplies issued are credited
hereto and charged to the appropriate construction, operating expense, or other account on the
basis of a unit price determined by the method of inventory accounting. Account 163 includes
the cost of supervision, labor, and expenses incurred in the operation of general storerooms,
including purchasing, storage, handling, and distribution of materials and supplies. This account
is cleared by adding to the cost of materials and supplies issued a suitable loading charge which
distributes the expense equitably over stores issues. The balance in the account at the close of the
year shall not exceed the amount of stores expenses reasonably attributable to the inventory of
materials and supplies.
Methodology
Adjustment N reflects no adjustment, with Materials and Supplies (Accounts 154 and 163)
remaining consistent with the 2024 Base.
Adjustment O—Other Deferred Programs
Table 3—FERC Accounts 182.3 and 186
Description
This account includes the amounts of regulatory assets not includable in other accounts resulting
from the ratemaking actions of regulatory agencies.
Methodology
Adjustment O increases Other Deferred Programs (Accounts 182.3 and 186)by $17,997,821
above the 2024 Base.
Accounts 186.722 and 186.770—American Falls Bond Refinancing, IPUC Order No. 25880.
These deferred costs are financing costs related to American Falls Bond issuances. The total
monthly amortization of these two bonds is $5,213 per month. IPC has reduced the 2024 Base
for two months of additional amortization for$10,426, bringing the balance to zero, reflecting
the costs being fully amortized in 2025.
Accounts 182.410 and 182.411—Siemens Long-term Program Contract, IPUC Order No.
33420. Idaho Power entered into a long-term program contract under which Siemens Energy
agrees to maintain the Company's three gas plants. A deferral was set up to account for the sale
of the spare parts inventory, initialization fees and associated deferred income taxes. The
Company established two Idaho jurisdictional regulatory assets, one labeled"Rate Based" and
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one labeled "Deferred Rate Base". The deferral will be amortized over the remaining life of each
asset in accordance with IPUC Order No. 33420 and 36042. The 2024 Base was reduced by
$1,075,354 for one year of additional amortization, resulting in a test year deferral balance of
$18,238,003.
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Account 182.315—Cloud Computing,IPUC Order No. 34707. This account includes the
unamortized balance of the Idaho-only portion of prepaid licensing costs associated with cloud
computing arrangements meeting the requirements of IPUC Order no. 34707. Included in the
2024 Base is $883,247 associated with cloud computing agreements for Zycus and Azure. Idaho
Power has included an additional $91,606 to its 2024 Base, bringing the test year deferral
balance to $974,853. The additional $91,606 consists of a final payment in January 2025 for
Zycus (additional $382,487), one year of additional amortization for Zycus (reduced by
$212,695), and a partial year of additional amortization for Azure (reduced by$78,186).
Account 182.310—Wildfire Mitigation, IPUC Order Nos. 35077, 35717, 36042.These
deferred costs relate to the Idaho-only portion of incremental wildfire mitigation costs associated
with IPC's Wildfire Mitigation Plan, for years 2023, 2024, and 2025. The 2024 Base was
increased by $22,519,724,bringing the test year deferral balance to $62,869,655. The increase of
$22,519,724 consists of an estimated 2025 deferral of$32,998,000 reduced by one-year of
amortization of$10,478,276 assuming a seven-year amortization period.
Account 182.31I—Wildfire Mitigation, IPUC Order No. 36042. These deferred costs relate to
the Idaho-only portion of incremental wildfire mitigation costs associated with IPC's Wildfire
Mitigation Plan, authorized for amortization in Order No. 36042. The 2024 Base was reduced by
$3,811,175 for one year of additional amortization, resulting in a test year deferral balance of
$19,055,877.
Account 182.345—Western Resource Adequacy Program ("WRAP"), IPUC Order No.
35920. This account includes the unamortized balance of the Idaho-only portion of WRAP
costs. The 2024 Base was increased by $386,558, bringing the test year deferral balance to
$1,021,778. The additional $386,558 is the estimated Idaho-only portion of the deferral for 2025.
Account 182.387 and 182.388—Idaho Intervenor Funding,IPUC Order Nos. 36042, 36048.
Account 182.387 consist of deferred costs, including carrying charges, associated with intervenor
funding payments per IPUC Order Nos. 36042 and 36048. The 2024 Base was increased by
$2,829 for 2025 carrying charges then reduced by $53,887 for an assumed one-year
amortization, resulting in a test year deferral balance of zero. Account 182.388 deferred costs
relate to the unamortized balance of Idaho intervenor funding authorized for amortization in
Order No. 36042. The 2024 Base was reduced by $38,340 for one year of additional
amortization, resulting in a test year deferral balance of$191,697.
Account 182.385 and 182.386—Citizens Utility Board ("CUB") Fund Grant, OPUC Order
No. 24-006, 23-185, 24-153. IPC was ordered in Docket UM 2126, Order No. 24-006, to fund
$33,000 to CUB pursuant to the terms of the Intervenor Funding Agreement by and among IPC
and CUB and approved by the OPUC in Order Nos. 23-185 and 24-153 to amortize. IPC has
assumed a one-year amortization period for recovery of these costs through the Power Cost
Adjustment Mechanism ("PCAM", Oregon Tariff Schedule 56). This reduced the deferral by the
2024 Base of$64,072 ($37,450+ $26,621) including accrued interest, resulting in a test year
deferral balance of zero.
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Accounts 182.412 and 182.413—Siemens Long-term Program Contract, OPUC Order Nos.
15-387 and 15-388. As part of the long-term program contract with Siemens discussed above,
the Company established two Oregon jurisdictional regulatory assets, one labeled"Rate Based"
and one labeled"Deferred Rate Base". The deferral will be amortized over the remaining life of
each asset in accordance with OPUC Order No. 15-387. The 2024 Base was reduced by $83,362
for one year of additional amortization, resulting in a test year deferral balance of$399,568.
Account 182.339—SFAS 87 Capitalized Pension Costs, OPUC Order No. 10-064. The 2024
Base increased by $133,719, which consists of a$377,710 estimated deferral for 2025 and one
year of additional amortization of$243,991, resulting in a test year deferral balance of
$7,364,273.
Account 182.312—Wildfire Mitigation, OPUC Order No. 24-010. These deferred costs relate
to the Oregon-only portion of incremental wildfire mitigation costs associated with IPC's
Wildfire Mitigation Plan. No adjustment was made to the 2024 Base.
Adjustment P—Plant Held for Future Use
Table 3—FERC Account 105
Description
This account includes the original cost of electric plant owned and held for future use in electric
service under a definite plan for such use and includes property acquired but never used by the
utility in electric service but held for such service in the future under a definite plan, and property
previously used by the utility in service,but retired from such service and held pending its reuse
in the future,under a definite plan, in electric service.
Methodology
Adjustment P increases Plant Held for Future Use (Account 105)by $2,705,786 above the 2024
Base.
IPC established its 2024 Base by removing from the actual 2024 balance any properties that have
an uncertain future use or are pending a Request for Proposal ("RFP") or Certificate of Public
Convenience and Necessity("CPCN") filing.
Plant Held for Future Use includes $2,705,786 for the planned acquisition of two additional
parcels of land associated with the Mayfield Transmission Station and the Eisenman Substation,
expected to be completed by year-end 2025, partially offset by the removal of$1,593,640 from
this account for amounts that will be transferred to Electric Plant In Service and $574 for a
partial land disposal.
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Adjustment Q—Customer Advances for Construction
("CAC")
Table 3—FERC Account 252
Description
Account 252 includes advances by customers for construction which are to be partially or wholly
refunded. When a customer is refunded the entire amount to which he or she is entitled according
to the agreement or rule under which the advance was made, any remaining balance is credited to
the appropriate plant account.
Methodology
Adjustment Q decreases the Customer Advances for Construction 2024 Base by $17,450,604,
based on an estimated thirteen-month average balance.
The Account 252 estimated thirteen-month average balance utilized a 5-year(2020-2024)
average methodology to determine the estimated balances for unusual conditions, substation
allowances, and transmission network upgrades. The tax gross-up portion was excluded from the
substation allowances' estimate. For unusual conditions the balance was estimated based on
average refund amounts. Please see the analysis in the table below:
2025 Test Year Customer Advances (13-Month Average) Total
2020-2024 5-year Average Unusual Conditions Refunds $8,069,204
2020-2024 5-year Average Substation Allowances(Excluding Tax Gross-up) 2,550,503
2020-2024 5-year Average Transmission Network Upgrades 11,396,284
12/31/25 Estimate for Unusual Conditions Refunds,Substation Allowances,&Network
Upgrades(Excluding Tax Gross-up) $22,015,9911
' IPC has estimated the thirteen-month balance of$22,015,991 based on the shape of the 2024 actual thirteen-month
average balance.
Adjustment R—Idaho Energy Resources Co. Rate Base
Table 3—FERC Accounts 123.1, 186, and 145
Description
Account 123.1 includes the cost of investments in securities issued or assumed by subsidiary
companies and investment advances to such companies, including interest accrued thereon when
such interest is not subject to current settlement plus the equity in undistributed earnings or
losses of such subsidiary companies since acquisition. This account is credited with any
dividends declared by such subsidiaries. This account is maintained in such a manner as to show
separately for each subsidiary: (1)the cost of such investments in the securities of the subsidiary
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at the time of acquisition, (2) the amount of equity in the subsidiary's undistributed net earnings
or net losses since acquisition, and(3) advances or loans to such subsidiary. Account 145
represents notes receivable from associated companies. Account 186 includes all debits not
elsewhere provided for, such as miscellaneous work in progress, and unusual or extraordinary
expenses, not included in other accounts, which are in process or amortization and items the
proper final disposition of which is uncertain.
Methodology
Adjustment R increases IERCO 2025 rate base (Accounts 123.1, 186, and 145)by$4,562,652
above the 2024 Base. The IERCO rate base is presented on a thirteen-month average basis.
IPC's 2025 investment in IERCO is based on actual 2024 activity at the BCC mine, which
supplies coal to the Jim Bridger thermal plant. As a one-third owner of BCC, IERCO is entitled
to 33% of BCC's net income and cash flows.
• Account 123.1—Investment in IERCO. Investment in IERCO is expected to increase
by $2,027,644 in 2025, with the thirteen-month average balance rising from $23,501,862
in 2024 to $25,529,506. IERCO's investment in BCC is accounted for using the equity
method. Under this method, the investment balance increases with BCC income, IERCO
income, and capital contributions to BCC, while dividend distributions from BCC to
IERCO reduce the balance. For the 2025 test year, no dividends are assumed; instead,
any excess cash remaining after covering operating expenses and capital investments is
returned to IPC through the intercompany note, as detailed below in the discussion of
Account 145.
• Account 186—Prepaid Coal Royalties. Prepaid Coal Royalties are expected to decrease
by $260,562 with the thirteen-month average balance falling from $398,686 in 2024 to
$138,124 in 2025. These overriding coal royalties are determined based on the lease
under which BCC is mining and were originally granted by IPC to IERCO as advance
royalties, then passed on to BCC. Although the royalty payments do not affect IERCO's
net income—since revenue is recognized when paid by BCC and the expense is recorded
when remitted back to IPC—the flow of these payments serves to reduce the Account
186 balance.
• Account 145—Notes Payable To/Receivable from Subsidiary.Notes Payable
To/Receivable from Subsidiary is expected to increase by $2,795,569 from a thirteen-
month average balance of$12,685,613 in 2024 to $15,481,182 in 2025. This
intercompany note serves as the funding mechanism through which IERCO receives
distributions from and makes capital contributions to BCC and facilitates payments of
income taxes and dividends to IPC. Activity in this account is based on BCC's 2025
operating and capital budgets. Interest accrues monthly on the intercompany note based
on IPC's short-term borrowing rate, which is projected to average 0.36%per month, or
4.36% annually.
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