20250415Direct Brady.pdf

RECEIVED
April 15, 2025
IDAHO PUBLIC
UTILITIES COMMISSION
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION )
OF IDAHO POWER COMPANY FOR )
AUTHORITY TO IMPLEMENT POWER ) CASE NO. IPC-E-25-20
COST ADJUSTMENT ("PCA") RATES )
FOR ELECTRIC SERVICE FROM JUNE )
1, 2025, THROUGH MAY 31, 2026 . )
IDAHO POWER COMPANY
DIRECT TESTIMONY
OF
JESSICA G. BRADY

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 Jessica G. Brady. My business
5 address is 1221 West Idaho Street, Boise, Idaho 83702 . I am
6 employed by Idaho Power as a Senior Regulatory Analyst in
7 the Regulatory Affairs Department.
8 Q. Please describe your educational background.
9 A. In May 2016, I received a Bachelor of Science
10 degree in Economics and a Bachelor of Arts degree in
11 Spanish from the University of Idaho . I have also attended
12 "The Basics : Practical Regulatory Training for the Electric
13 Industry, " an electric utility ratemaking course offered
14 through New Mexico State University' s Center for Public
15 Utilities, "Electric Utility Fundamentals & Insights, " an
16 electric utility course offered through the Western Energy
17 Institute, and Edison Electric Institute' s "Electric Rates
18 Course" offered at the University of Wisconsin-Madison .
19 Q. Please describe your work experience .
20 A. In September 2021, I accepted a position at
21 Idaho Power as a Regulatory Analyst in the Regulatory
22 Affairs Department. In October 2023, I was promoted to
23 Senior Regulatory Analyst. As a Senior Regulatory Analyst,
24 I am responsible for running the AURORA model ("AURORA") to
25 calculate net power supply expenses ("NPSE") for ratemaking
BRADY, DI 1
Idaho Power Company

1 purposes, as well as the determination of the marginal cost
2 of energy used in the Company' s marginal cost analyses . My
3 duties also include providing analytical support for other
4 regulatory activities within the Regulatory Affairs
5 Department .
6 Q. What is the Company requesting in this case?
7 A. The Company is requesting approval of its
8 2025-2026 Power Cost Adjustment ("PCA") rates to become
9 effective June 1, 2025 . If approved, the 2025-2026 PCA
10 will result in a decrease in total billed revenue of
11 approximately $94 . 8 million, or 5 . 89 percent.
12 Q. How is your testimony organized?
13 A. My testimony consists of four sections . In the
14 first section, I provide an overview of the PCA. In the
15 second section, I detail the 2025-2026 PCA amount in
16 comparison to last year' s PCA amount, identify and discuss
17 the main factors contributing to this change, and present
18 the quantification of the 2025-2026 PCA rates to become
19 effective June 1, 2025 . In the third section, I discuss the
20 additional PCA component related to revenue sharing. In the
21 fourth section, I detail the net customer impact of the
22 2025-2026 PCA rates if approved as filed.
23 Q. Are you sponsoring any exhibits?
24 A. Yes . I am offering the following exhibits :
25
BRADY, DI 2
Idaho Power Company

1 Exhibit Description
2 Exhibit No . 1 2025-2026 PCA Forecast
3 Exhibit No. 2 2024 Balancing Adjustment
4 Exhibit No. 3 2024 ROE Determination Revenue Sharing
5 Exhibit No. 4 Confidential - Clean Energy Your Way
6 Generation and Expenses
7 Exhibit No. 5 Confidential - Liquidated Damages
8 I . PCA OVERVIEW
9 Q. What is the purpose of the PCA?
10 A. The PCA is a rate mechanism that quantifies
11 and tracks annual differences between actual NPSE and the
12 normalized or "base level" of NPSE recovered in the
13 Company' s base rates, resulting in a credit or surcharge
14 that is updated annually on June 1 . The PCA mechanism uses
15 a 12-month test period of April through March ("PCA Year")
16 and includes a forecast component and a Balancing
17 Adjustment . The forecast component represents the
18 difference between the Company' s NPSE forecast from the
19 March Operating Plan and base level NPSE recovered in the
20 Company' s base rates . The Balancing Adjustment includes a
21 backward-looking tracking of differences between the prior
22 PCA Year' s forecast and actual NPSE incurred by the
23 Company, and also tracks the collection of the prior year' s
24 Balancing Adjustment. In addition, beginning with this
25 year' s PCA filing, the Balancing Adjustment tracks the
BRADY, DI 3
Idaho Power Company

1 annual variance between actual wheeling revenues and base-
2 level wheeling revenues . This is discussed in more detail
3 later in my testimony.
4 Q. How does the PCA mechanism function?
5 A. The PCA allows the Company to pass through to
6 customers 95 percent of the annual differences in actual
7 NPSE as compared with base level NPSE, whether positive or
8 negative, with the exception of Public Utility Regulatory
9 Policies Act of 1978 ("PURPA") expenses and demand response
10 incentive payments . With respect to PURPA expenses and
11 demand response incentive payments, as actual annual
12 expenses deviate from base level NPSE, the Company is
13 allowed to pass 100 percent of the difference for recovery
14 or credit through the PCA. In addition, beginning with this
15 year' s PCA filing, Idaho Power is requesting to include
16 recovery of the capital lease payments associated with the
17 Kuna Battery Energy Storage System ("BESS") at 100 percent.
18 I will discuss this in more detail later in my testimony.
19 The PCA is also the rate mechanism used by the Company to
20 provide customer benefits resulting from the revenue
21 sharing mechanism approved by the Commission in Order No.
22 34071 .
23 Q. Does the revenue collected from customers
24 through the annual PCA rate contribute toward the Company' s
25 earnings?
BRADY, DI 4
Idaho Power Company

1 A. No. The PCA mechanism provides for the annual
2 collection or refund of net power supply cost differences
3 between actual costs incurred by the Company and the base
4 level NPSE component of base rates . Aside from the 95
5 percent to 5 percent sharing component I just described,
6 the PCA provides for a one-for-one collection or refund of
7 actual net power supply expenses incurred, or to be
8 incurred, to provide safe, reliable electric service to
9 customers .
10 Q. What are the components of the PCA base level
11 NPSE?
12 A. The PCA base level NPSE includes the following
13 Federal Energy Regulatory Commission ("FERC") accounts :
14 Account 501, Fuel (steam) ; Account 536, Water for Power;
15 Account 547, Fuel (gas) ; Account 555, Purchased Power;
16 Account 565, Transmission of Electricity by Others; and
17 Account 447, Sales for Resale (typically referred to as
18 surplus sales) .
19 The PCA base level expense component for FERC
20 Account 555 includes costs of both PURPA and non-PURPA
21 (market) purchases . Per Order No. 32426, the Company
22 adjusts FERC Account 555 to also include demand response
23 incentive payments that the Company provides to customers
24 who participate in any of its three demand response
25 programs .
BRADY, DI 5
Idaho Power Company

1 Q. Is Idaho Power proposing to include a new FERC
2 account in the PCA NPSE beginning with this year' s filing?
3 A. Yes . Beginning with this year' s PCA filing,
4 Idaho Power is proposing to include FERC Account 577 . 4,
5 Energy Storage Rents, in the PCA base level NPSE in order
6 to collect expenses associated with the Kuna BESS Energy
7 Storage Agreement ("ESA") .
8 Q. Please provide additional information
9 regarding the Kuna BESS ESA.
10 A. On April 26, 2023, Idaho Power and Kuna BESS
11 entered into an ESA, whereby a battery storage facility
12 located in Kuna, Idaho, will supply 150 megawatts of
13 capacity on Idaho Power' s system for the period of 20 years
14 from a commercial operation date of June 1, 2025 . The ESA
15 acts as a type of lease through which Kuna BESS will
16 develop, design, construct, own, and operate the battery
17 storage system and, in accordance with the terms of the
18 agreement, Idaho Power will supply the charging energy for
19 the system and has the exclusive right to dispatch and use
20 the charging and discharging energy in exchange for a
21 monthly payment .
22 On November 27, 2023, in Order No. 36011, the
23 Commission approved the Company' s Application for a
24 Certificate of Public Convenience and Necessity for the
25 Kuna BESS, acknowledged the expenses as prudently incurred
BRADY, DI 6
Idaho Power Company

1 for ratemaking purposes, and acknowledged the lease
2 accounting necessary to facility the transaction. '
3 II . 2025-2026 PCA
4 Q. What is the total PCA collection that would
5 result under the 2025-2026 PCA rates proposed by the
6 Company in this case?
7 A. The 2025-2026 PCA rates would result in total
8 PCA collection of $21 . 0 million. This represents a
9 decrease in total billed revenue of $94 . 8 million for the
10 upcoming year, a decrease of 5 . 89 percent .
11 Q. Have you prepared a table that details the
12 $94 . 8 million revenue impact by component?
13 A. Yes . Table 1 presents a separation of the
14 $94 . 8 million decrease into each component included in the
15 Company' s proposed rates .
Table 1 Idaho Jurisdictional Revenue Impact by Component
Line
No. Rate Component 2024-2025 PCA 2025-2026 PCA Difference
1 PCA Forecast $ 23,342,867 $ 73,092,256 $ 49,749,389
2 PCA Balancing Adjustment $ 92,469,480 $ (52,064,539)2 $ (144,534,019)
3 PCA Total $ 115,812,347 $ 21,027,717 $ (94,784,630)
4 Revenue Sharing $ 0 $ 0 $ 0
5 Total Revenue Impact $ 115,812,347 $ 21,027,717 $ (94,784,630)
' In the Matter of the Application for CPCN to acquire resources to be
online in both 2024 and 2025 and for approval of an energy storage
agreement with Kuna BESS LLC. , Case No. IPC-E-23-20, Order No. 36011
(November 27, 2023) .
2 Will not tie to Balancing Adjustment in Exhibit No. 2 due to rounding
of Balancing Adjustment rate.
BRADY, DI 7
Idaho Power Company

1 Q. What are the main factors driving the revenue
2 change requested in this case?
3 A. The decrease in this year' s PCA is driven by a
4 decrease in the Balancing Adjustment, partially offset by
5 an increase in the forecast component . The decrease in this
6 year' s Balancing Adjustment is largely attributed to the
7 completed recovery of the 2023 PCA balancing adjustment,
8 which was recovered over two years per Order No. 35804 . 3
9 Additional factors include the Sales Based Adjustment
10 ("SBA") , which accounts for the variance in actual sales
11 and the sales used to set base level NPSE, an increase in
12 Renewable Energy Credit ("REC") sales, a credit for
13 liquidated damages associated with the delayed
14 commissioning of certain BESS resources, and a credit
15 related to the variance in actual wheeling revenues as
16 compared to the levels recovered in base rates .
17 A. PCA Forecast.
18 Q. How is the PCA forecast amount determined?
19 A. As described previously, the PCA forecast
20 component represents the difference between the Company' s
3 In the Matter of the Application For authority to implement Power Cost
Adjustment ("PCA") rates for electric service from June 1, 2023,
through May 31, 2024. , Case No. IPC-E-23-12, Order No. 35804 (May 31,
2023) .
BRADY, DI 8
Idaho Power Company

1 forecast of NPSE for the upcoming April - March test year
2 and base level NPSE recovered in the Company' s base rates . 4
3 Q. What is the Company' s determination of the
4 system-level difference between currently approved base
5 level NPSE and the forecast of NPSE for the 2025-2026 PCA
6 Year?
7 A. The system-level forecast of NPSE for the
8 2025-2026 PCA Year is $563, 563, 648, which is $78, 656, 404
9 higher than the currently approved base level NPSE of
10 $484, 907, 244 . Table 2 presents the system-level
11 differences between currently approved base level NPSE and
12 the forecast of NPSE for the 2025-2026 PCA Year by FERC
13 account .
14
15
16
17
18
19
20
21
22
23
4 In the Matter of the Application of Idaho Power Company for Authority
to Increase its Rates and Charges for Electric Service in the State of
Idaho and for Associated Regulatory Accounting Treatment, Case No. IPC-
E-23-11, Order No. 36042 (December 28, 2023) .
BRADY, DI 9
Idaho Power Company

Table 2 2025-2026 PCA FORECAST(Total System)
Line No. FERC Account Base NPSE Forecast Difference
95%Sharing Accounts
1 Account 501,Steam $ 65,523,000 $ 151,558,050 $ 86,035,050
2 Account 536,Water for Power $ 0 $ 0 $ 0
3 Account 547,Other Fuel $ 119,653,675 $ 129,974,528 $ 10,320,852
4 Account 555,Purchased Power Non-PURPA $ 99,465,021 $ 103,402,787 $ 3,937,767
5 Account 565,3rd Party Transmission $ 10,263,139 $ 11,925,403 $ 1,662,264
6 Account 447,Surplus Sales $ (34,686,350) $ (88,732,720) $ (54,046,370)
$ 260,218,486 $ 308,128,048 $ 47,909,562
100%Sharing Accounts
7 Account 555,PURPA $ 214,448,755 $ 227,069,067 $ 12,620,313
8 Account 555,Demand Response Incentives $ 10,240,003 $ 10,411,533 $ 171,530
9 Account 577.4,Energy Storage Rents $ 0 $ 17,955,000 $ 17,955,000
10 Total $ 484,907,244 $ 563,563,648 $ 78,656,404
1
2 Q. What is the basis for the forecast of NPSE for
3 the 2025-2026 PCA Year?
4 A. The forecast of NPSE for the 2025-2026 PCA
5 Year is based on the Company' s March 2025 Operating Plan .
6 Q. How is the NPSE forecast developed for the
7 Company' s Operating Plan?
8 A. The Operating Plan is prepared monthly and
9 represents a forecast of the Company' s monthly NPSE for the
10 following 18-month period; however, for the PCA, the
11 Company includes only the 12 months that correspond to the
12 PCA Year. The Operating Plan is developed by simulating
13 the dispatch of the Company' s generation resources for each
14 month, segmented by heavy load and light load hours . The
15 dispatch considers a current forecast of forward market
BRADY, DI 10
Idaho Power Company

1 energy prices, available hydro generation, coal and natural
2 gas prices, and any existing hedge transactions . The
3 system load forecast is then analyzed against the resulting
4 monthly heavy load and light load dispatch to determine a
5 monthly load and resource balance. Any identified resource
6 deficiency is assumed to be filled with market energy
7 purchases or natural gas to fuel either the Langley Gulch
8 power plant ("Langley Gulch") or Jim Bridger Units 1 and 2,
9 based on economics and available generating capacity at
10 each plant . Economically dispatched generation above the
11 system load forecast represents surplus energy sales . The
12 forecast of monthly NPSE and generation for the 2025-2026
13 PCA Year, as determined in the Company' s March 2025
14 Operating Plan, is provided in Exhibit No. 1 .
15 Q. How does the Company' s forecast of system-
16 level NPSE for the 2025-2026 PCA compare to the system-
17 level forecast included in last year' s PCA?
18 A. Table 3 below compares this year' s 2025-2026
19 PCA forecast of NPSE to last year' s PCA forecast by FERC
20 account . As detailed in this table, the PCA forecast on a
21 total system basis for the 2025-2026 PCA year is
22 $563, 563, 648, which is $54, 007, 658 higher than last year' s
23 forecast amount of $509, 555, 990 .
24
25
BRADY, DI 11
Idaho Power Company

Table 3 PCA Forecast Comparison Expenses(Total System)
Line No. FERC Account 2024-2025 Forecast 2025-2026Forecast Difference
95%Sharing Accounts
1 Account 501,Steam $ 154,419,821 $ 151,558,050 $ (2,861,771)
2 Account 536,Water for Power $ 0 $ 0 $ 0
3 Account 547,Other Fuel $ 109,958,254 $ 129,974,528 $ 20,016,274
4 Account 555,Purchased Power Non-PURPA $ 90,809,149 $ 103,402,787 $ 12,593,638
5 Account 565,3rd Party Transmission $ 10,419,009 $ 11,925,403 $ 1,506,394
6 Account 447,Surplus Sales $ (86,055,453) $ (88,732,720) $ (2,677,267)
$ 279,550,780 $ 308,128,048 $ 28,577,268
100%Sharing Accounts
7 Account 555,PURPA $ 219,593,677 $ 227,069,067 $ 7,475,390
8 Account 555,Demand Response Incentives $ 10,411,533 $ 10,411,533 $ 0
9 Account 577.4,Energy Storage Rents $ 0 $ 17,955,000 $ 17,955,000
$ 230,005,210 $ 255,435,600 $ 25,430,390
10 Total PCA Forecast $ 509,555,990 $ 563,563,648 $ 54,007,658
1
2 Q. What general conclusions can be drawn from the
3 information contained in Table 3?
4 A. When viewed by category, the 95 percent
5 sharing accounts have increased approximately $28 . 6 million
6 from last year' s forecast, while the 100 percent sharing
7 accounts have increased approximately $25 . 4 million over
8 last year' s forecast.
9 Q. How does the Company' s generation forecast for
10 the 2025-2026 PCA compare to the forecast included in last
11 year' s PCA?
12 A. Table 4 below compares this year' s 2025-2026
13 PCA generation forecast to last year' s PCA forecast by FERC
BRADY, DI 12
Idaho Power Company

1 account . As detailed in this table, the 520, 163 megawatt-
2 hour ("MWh") (3 percent) increase to load from the prior
3 year is forecast to be met with a 147, 810 MWh (2 percent)
4 increase to hydro generation, a 6, 981 MWh (0 . 2 percent)
5 increase to steam power generation, a 153, 494 MWh (5
6 percent) increase to natural gas-fired generation, and a
7 346, 999 MWh (22 percent) increase to non-PURPA market
8 purchases, which is largely due to the increase in forecast
9 power purchase agreement ("PPA") generation as a result of
10 Pleasant Valley Solar, a 200 megawatt alternating current
11 solar photovoltaic facility, coming online in March 2025 .
12 These increases in generation are partially offset by a
13 140, 881 MWh (11 percent) increase to surplus sales .
Table 4 PCA Forecast Comparison Generation(Total System-MWh)
Line No. FERC Account 2024-2025 Forecast 2025-2026 Forecast Difference
1 Hydro 7,293,179 7,440,989 147,810
95%Sharing Accounts
2 Account 501,Steam 3,787,742 3,794,723 6,981
3 Account 547,Other Fuel 2,913,524 3,067,019 153,494
4 Account 555,Purchased Power Non-PURPA 1,577,970 1,924,968 346,999
15,572,415 16,227,698 655,283
100%Sharing Accounts
5 Account 555,PURPA 2,921,156 2,926,917 5,761
2,921,156 2,926,917 5,761
6 Total Generation 18,493,571 19,154,615 661,044
95%Sharing Accounts
7 Less Account 447,Surplus Sales 1,306,125 1,447,006 140,881
8 Total Load 17,187,446 17,707,609 520,163
14
BRADY, DI 13
Idaho Power Company

1 Q. Please provide additional information about
2 Pleasant Valley Solar.
3 A. Pleasant Valley Solar is a PPA that was
4 negotiated in conjunction with a new special contract with
5 Brisbie, LLC ("Brisbie") , as a part of the Company' s Clean
6 Energy Your Way ("CEYW") program. Meta Platforms, Inc. is
7 the parent company of Brisbie. Brisbie' s special contract
8 states that Idaho Power will procure renewable resources to
9 support 100 percent of Brisbie' s operations with renewable
10 energy on an annual basis . While Pleasant Valley Solar is
11 connected to the grid and therefore doesn' t serve Brisbie
12 directly, Brisbie will pay for the full cost of the PPA, as
13 well as Idaho Power retail electric service required to
14 serve their load. In addition, Brisbie will receive a
15 capacity credit for the value that Pleasant Valley Solar
16 provides to Idaho Power' s system and will be credited for
17 any PPA generation that exceeds their load in a given hour.
18 Per the terms of the contract, the value of the excess
19 generation is defined as the lower of 1) 85 percent of the
20 non-firm Mid-Columbia hourly price forecast, or 2) the
21 actual heavy or light load price in the hour of excess
22 generation.
23 Q. How are the Company' s CEYW resources, like
24 Pleasant Valley Solar, accounted for in the PCA forecast?
BRADY, DI 14
Idaho Power Company

1 A. Resources procured through the CEYW -
2 Construction Option are paid for by the participating
3 customer. Accordingly, the cost of the PPA is not included
4 in the forecast of NPSE for the PCA year. However, the
5 participating customer will be credited for the value of
6 the resource' s capacity contribution to the system and for
7 any PPA generation that exceeds their load in a given hour.
8 Both the forecast capacity credit and excess generation
9 credit amounts are included as expenses in the PCA
10 forecast .
11 Q. How are the Company' s marginal-cost priced
12 customers accounted for in the PCA forecast?
13 A. All forecast marginal-cost priced energy sales
14 are included in the PCA forecast as an offset to NPSE,
15 included in Account 447, Surplus Sales .
16 Q. Were any changes made to the Idaho
17 jurisdictional sales and system-level sales to account for
18 modifications related to CEYW or marginal cost-priced
19 customers?
20 A. Yes . All load forecast to be met with CEYW
21 resources or priced at a marginal cost-based rate are
22 excluded from total forecast sales and are not used in the
23 derivation of the PCA rate.
BRADY, DI 15
Idaho Power Company

1 Q. What is the Company' s forecast of system-level
2 firm sales and Idaho jurisdictional firm sales for the
3 2025-2026 PCA Year?
4 A. For the 2025-2026 PCA Year, Idaho Power has
5 forecast system-level firm sales to be 16, 226, 039 MWh and
6 Idaho jurisdictional firm sales to be 15, 551, 544 MWh, or
7 95 . 84 percent of the system level .
8 Q. What is the Company' s determination of the
9 2025-2026 PCA forecast component to be collected from Idaho
10 customers?
11 A. As shown in Table 1, the 2025-2026 PCA
12 forecast component to be collected from Idaho customers is
13 $73, 092, 256 .
14 B. Balancing Adjustment.
15 Q. What is this year' s quantification of the
16 Balancing Adjustment?
17 A. The Balancing Adjustment is detailed in the
18 PCA deferral report, attached hereto as Exhibit No. 2 . This
19 report compares actual NPSE amounts to actual power cost
20 collections monthly, with the differences accumulated as a
21 deferral balance. The balance at the end of March 2025,
22 with interest applied, is negative $52, 045, 994 as shown on
23 row 104 of Exhibit No . 2 . The approximate negative $52
24 million represents a decrease to customer rates in this
25 year' s PCA Balancing Adjustment.
BRADY, DI 16
Idaho Power Company

1 Q. To what factors do you attribute the
2 accumulation of the approximate negative $52 million
3 deferral balance?
4 A. Actual power supply expenses in the 2024-2025
5 PCA Year were just 2 percent lower than forecast expenses,
6 with load coming in 0 . 4 percent higher than forecast. As a
7 result, the variance between forecast and actual power
8 supply expenses for the 2024-2025 PCA Year had a relatively
9 small impact on this year' s deferral balance. See Table 5
10 below for the variance in actual versus forecast NPSE for
11 the 2024-2025 PCA Year.
12 However, this year' s deferral balance does include
13 increased benefits associated with the SBA, REC sales, and
14 wheeling revenues . In addition, it includes liquidated
15 damages associated with the delayed commissioning of
16 certain BESS resources, for which the amount is included in
17 Confidential Exhibit 5 .5
18
19
20
21
22
23
24
5 Liquidated damages are included in the balancing adjustment in Non-
Firm Purchases. See Exhibit No. 2, Line 9.
BRADY, DI 17
Idaho Power Company

Table
5 2024-2025 Forecast to Actual Expenses
Line 2024-2025 2024-2025
No. FERC Account Forecast Actuals Difference
95%Sharing Accounts
1 Account 501,Steam $ 154,419,821 $ 94,896,524 $ (59,523,297)
2 Account 536,Water for Power $ 0 $ 0 $ 0
3 Account 547,Other Fuel $ 109,958,254 $ 136,341,920 $ 26,383,666
4 Account 555,Purchased Power Non-PURPA $ 90,809,149 $ 141,511,695 $ 50,702,545
5 Account 565,3rd Party Transmission $ 10,419,009 $ 13,357,650 $ 2,938,640
6 Account 447,Surplus Sales $ (86,055,453) $ (113,124,433) $ (27,068,980)
$ 279,550,780 $ 272,983,355 $ (6,567,425)
100%Sharing Accounts
7 Account 555,PURPA $ 219,593,677 $ 219,689,249 $ 95,572
8 Account 555,Demand Response Incentives $ 10,411,533 $ 8,953,587 $ (1,457,946)
$ 230,005,210 $ 228,642,836 $ (1,362,374)
9 Total $ 509,555,990 $ 501,626,191 $ (7,929,799)
1
2 Q. Please explain the changes in actual versus
3 forecast generation and expense for the 2024-2025 PCA Year .
4 A. Table 6 below details the changes in actual
5 versus forecast generation for the 2024-2025 PCA Year .
6
7
8
9
10
11
12
13
14
15
BRADY, DI 18
Idaho Power Company

Table
6 2024-2025 Forecast to Actual Generation
Line 2024-2025 2024-2025
No. FERC Account Forecast Actuals Difference
1 Hydro 7,293,179 7,577,592 284,413
95%Sharing Accounts
2 Account 501,Steam 3,787,742 2,633,381 (1,154,361)
3 Account 547,Other Fuel 2,913,524 3,567,777 654,253
4 Account 555,Purchased Power Non-PURPA 1,577,970 3,250,943 1,672,973
95%Sharing Accounts 15,572,415 17,029,693 1,457,278
100%Sharing Accounts
5 Account 555,PURPA 2,921,156 2,937,191 16,035
100%Accounts 2,921,156 2,937,191 16,035
6 Total Generation 18,493,571 19,966,883 1,473,312
95%Sharing Accounts
7 Account 447,Surplus Sales 1,306,125 2,706,363 1,400,238
8 Total Load 17,187,446 17,260,520 73,074
1
2 Actual steam power generation for the 2024-2025 PCA
3 year totaled 2, 633, 381 MWh, which is 30 percent lower than
4 forecast . Actual steam fuel expense totaled $94, 896, 524,
5 which is 39 percent lower than forecast. The actual per-
6 unit cost of steam power generation was $36 . 04, a 12
7 percent decrease from forecast.
8 Actual natural gas-fired generation for the 2024-
9 2025 PCA year totaled 3, 567, 777 MWh, which is 22 percent
10 higher than forecast. Actual natural gas fuel expense
11 totaled $136, 341, 920, which is 24 percent higher than
12 forecast . The actual per-unit cost of natural gas
13 generation was $38 .21, a 1 percent increase from forecast.
BRADY, DI 19
Idaho Power Company

1 Actual non-PURPA purchased power totaled 3, 250, 943
2 MWh for the 2024-2025 PCA Year. This included 2, 042, 803 MWh
3 in market purchases and 1, 208, 140 MWh in PPA generation.
4 PPA generation was 1 percent higher than forecast, whereas
5 market purchase volumes were 440 percent higher than
6 forecast . Actual non-PURPA purchased power expense was
7 $141, 511, 695, which is 56 percent higher than forecast.
8 This includes $80, 569, 880 in market purchase expense (243
9 percent higher than forecast) and $60, 033, 683 in PPA
10 expenses (10 percent lower than forecast) .
11 Surplus sales totaled 2, 706, 363 MWh for the 2024-
12 2025 PCA Year, which is 107 percent higher than forecast.
13 Actual surplus sales revenue was $113, 124, 433, which is 31
14 percent higher than forecast.
15 Q. Can you elaborate on the differences between
16 forecast and actual purchases and sales?
17 A. Yes . Purchase volumes included in the PCA
18 forecast consist of the known power purchases executed in
19 accordance with the Energy Risk Managements Standards
20 ("ERMS") prior to the development of the March Operating
21 Plan. Sales volumes included in the forecast are, generally
22 speaking, based on the economics of the Company' s resources
23 compared to Mid-Columbia forward market prices in the March
24 Operating Plan, and also include any known sale
25 transactions executed in accordance with the ERMS .
BRADY, DI 20
Idaho Power Company

1 On the other hand, actual power purchase and sales
2 include additional activity, such as transactions made in
3 the Energy Imbalance Market ("EIM") as well as bundled REC
4 sales that may result in actual purchases and sales being
5 different than the forecast. 6
6 Q. Please explain how Idaho Power implemented the
7 tracking of wheeling revenues into this year' s Balancing
8 Adjustment .
9 A. In accordance with Order No. 36502, the
10 wheeling revenue deferral was calculated by taking the
11 difference between actual Idaho-jurisdictional wheeling
12 revenues and base-level sales-adjusted wheeling revenues,
13 multiplied by the sharing percentage of 95 percent. ' See
14 Exhibit No . 2, Line 79 .
15 Q. How much is this year' s wheeling revenue
16 deferral, as shown on line 79 of Exhibit No. 2?
17 A. The wheeling revenue deferral for the 2024-
18 2025 PCA year is a credit to customers of approximately
19 $3 . 9 million.
6 Bundled REC sales refer to the sale of RECs together with the
electricity generated from renewable sources. This means that the
environmental attributes of the renewable energy are sold along with
the energy (either generated from Idaho Power's resources or purchased
on the market) .
7 In the Matter of Idaho Power Company's Filing in Compliance with Order
No. 36402 for Authority to Track Annual Wheeling Revenues in the Power
Cost Adjustment, Case No. IPC-E-24-38, Order No. 36502 (March 11,
2025) .
BRADY, DI 21
Idaho Power Company

1 Q. Did Idaho Power include its actual costs of
2 EIM participation in this year' s Balancing Adjustment?
3 A. No. Because EIM costs were included in base
4 rates resulting from the Company' s 2023 General Rate Case,
5 which went into effect on January 1, 2024, EIM costs are no
6 longer included in the PCA as of that date. Benefits
7 associated with EIM participation are embedded in actual
8 NPSE .
9 Q. Were there any other items included in this
10 year' s Balancing Adjustment in addition to what was already
11 discussed?
12 A. Yes . This year' s Balancing Adjustment includes
13 two additional items : 1) a one-time adjustment to recover
14 the conversion of accumulated kWh credits into a financial
15 credit for large general and irrigation customers and 2) a
16 one-time adjustment to credit the difference between
17 February and January base rates, as a result of the Errata
18 issued on January 21, 2025 in the Company' s 2024 filing to
19 recover incremental capital investments and certain ongoing
20 operations and maintenance expenses . 8 In total, these two
21 items result in an additional credit to customers of
22 $13, 372 .
8 kWh conversion per Order No. 36048 issued in Case No. IPC-E-23-14.
Errata to Order No. 36438 issued in Case No. IPC-E-24-07.
BRADY, DI 22
Idaho Power Company

1 Q. How were these amounts incorporated into this
2 year' s Balancing Adjustment?
3 A. A cents per kwh rate for these two adjustments
4 was calculated for each individual rate class and added to
5 the overall Balancing Adjustment Rate, as detailed later in
6 my testimony.
7 C. PCA Rate Determination.
8 Q. How is the rate for the forecast portion of
9 the PCA for April 2025 through March 2026 determined?
10 A. The rate for the forecast portion of the PCA
11 is equal to the sum of (1) 95 percent of the difference
12 between the non-PURPA expenses quantified in the Operating
13 Plan and those quantified in the Company' s last approved
14 update of LAPSE, divided by the Company' s forecast of system
15 firm sales for June 1, 2025, through May 31, 2026 ("System-
16 level Sales Forecast") ; (2) 100 percent of the difference
17 between PURPA-related expenses quantified in the Operating
18 Plan and those quantified in the Company' s last approved
19 update of NPSE, divided by the Company' s System-level Sales
20 Forecast; (3) 100 percent of the difference between the
21 Idaho jurisdictional demand response incentive payments
22 quantified in the Operating Plan and those quantified in
23 the Company' s last approved update of NPSE, divided by the
24 forecast of Idaho-jurisdictional firm sales for June 1,
25 2025, through May 31, 2026 ("Idaho-jurisdictional Sales
BRADY, DI 23
Idaho Power Company

1 Forecast") ; and (4) 100 percent of the difference between
2 the Energy Storage Rent expenses quantified in the
3 Operating Plan and those quantified in the Company' s last
4 approved update of NPSE, divided by the System-level Sales
5 Forecast .
6 Q. What is the rate for the forecast portion of
7 the PCA for April 2025 through March 2026?
8 A. The rate for non-PURPA expenses is 0 . 2805
9 cents per kilowatt-hour ("kWh") , which is calculated by
10 multiplying $47, 909, 562 from Table 2 by 95 percent and then
11 dividing it by the System-level Sales Forecast of
12 16, 226, 039 MWh ( ($47, 909, 562 * 0 . 95) / 16, 226, 039) _ $2 . 805
13 /MWh = 0 .2805 cents/kWh) . The rate for PURPA expenses is
14 0 . 0778 cents per kWh, which is calculated by dividing
15 $12, 620, 313 from Table 2 by the 16, 226, 039 MWh ($12, 260, 313
16 / 16, 226, 039 MWh = $0 . 778/MWh = 0 . 0778 cents/kWh) . The rate
17 for demand response incentive payments is 0 . 0011 cents per
18 kWh, which is calculated by dividing the $171, 530 from
19 Table 2 by the forecast of Idaho jurisdictional firm sales
20 of 15, 551, 544 MWh ($171, 530 / 15, 551, 544 MWh = $0 . 0110/MWh
21 = 0 . 0011 cents/kWh) . The rate for Energy Storage Rents is
22 0 . 1107 cents per kWh, which is calculated by dividing
23 $17, 955, 000 from Table 2 by the 16, 226, 039 MWh ($17, 955, 000
24 / 16, 226, 039 MWh = $1 . 107 /MWh = 0 . 1107 cents/kWh) . The
25 forecast portion of the PCA rate is 0 . 4700 cents per kWh,
BRADY, DI 24
Idaho Power Company

1 which is calculated by adding the non-PURPA expense of
2 0 .2805 cents per kWh to the PURPA expense of 0 . 0778 cents
3 per kWh to the demand response incentive payment of 0 . 0011
4 cents per kWh to the Energy Storage Rents expense of 0 . 1107
5 cents per kwh (0 .2805 + 0 . 0778 + 0 . 0011 + 0 . 1107 = 0 . 4700
6 cents/kWh) .
7 Q. How did you compute this year' s Balancing
8 Adjustment rate?
9 A. As shown in Exhibit No. 2, this year' s
10 Balancing Adjustment of the PCA is approximately negative
11 $52 million, which, when divided by the Company' s forecast
12 of Idaho jurisdictional sales of 15, 551, 544 MWh, results in
13 a rate of negative 0 . 3347 cents per kWh (-$52, 045, 994 /
14 15, 551, 544 = -$3 . 347/MWh = -0 . 3347 cents/kWh) .
15 Q. What is the resulting PCA rate when you
16 combine all the PCA components described previously?
17 A. The uniform PCA rate comprises (1) the 0 . 4700
18 cents per kWh for the 2025-2026 projected power cost of
19 serving firm loads under the current PCA methodology and 95
20 percent sharing, and (2) the negative 0 . 3347 cents per kWh
21 for the 2024-2025 Balancing Adjustment of the PCA. The sum
22 of these two components is a 0 . 1354 cents per kWh charge.
23 Q. How were the one-time adjustments you
24 discussed earlier in your testimony incorporated into this
25 year' s Balancing Adjustment Rate?
BRADY, DI 25
Idaho Power Company

1 A. The cents per kwh rates associated with the
2 two one-time adjustments were added to the Balancing
3 Adjustment Rate of negative 0 . 3347 cents per kwh to
4 determine class-specific Balancing Adjustment Rates . For
5 example, the total credit associated with the 2024 General
6 Rate Case Errata for Schedule 09S is $3, 818 . The total
7 expenses associated with kWh conversion for Schedule 09S is
8 $8, 625 . Based on the Idaho-jurisdictional Sales Forecast
9 for Schedule 09S of 3, 409, 784 MWh, the rate associated with
10 the adjustments is 0 . 0001 cents per kwh ( (-$3, 818 +
11 $8, 625) / 3, 409, 784 = $0 . 001/MWh = 0 . 0001 cents/kWh) . When
12 added to the initial Balancing Adjustment Rate of negative
13 0 . 3347 cents per kwh, the final Schedule 09S Balancing
14 Adjustment Rate is negative 0 . 3346 cents per kwh.
15 III . ADDITIONAL PCA RATE ADJUSTMENTS
16 A. Revenue Sharing.
17 Q. When was the revenue sharing mechanism
18 originally established?
19 A. The revenue sharing mechanism was originally
20 established in Case No. IPC-E-09-30 and approved in Order
21 No . 30978, effective for the years 2009-2011 . Since then,
22 the revenue sharing mechanism has been modified and
23 extended four times . 9 Order No . 34071 in Case No. GNR-U-18-
9 Order Nos. 32424, 33149, 34071, and 36042.
BRADY, DI 26
Idaho Power Company

1 01 extended the revenue sharing mechanism indefinitely,
2 with modifications .
3 The mechanism was most recently modified in the
4 Company' s 2023 General Rate Case, effective January 1, 2024
5 (Order No . 36402) .
6 Q. What is the purpose of the Revenue Sharing
7 Mechanism?
8 A. The Revenue Sharing Mechanism includes
9 provisions for the accelerated amortization of Accumulated
10 Deferred Investment Tax Credits ("ADITC") to help achieve a
11 minimum specified percent Idaho-jurisdictional return on
12 year-end equity ("Idaho ROE") and also provides for the
13 potential sharing between Idaho Power and its Idaho
14 customers of Idaho jurisdictional earnings in excess of a
15 maximum specified Idaho ROE.
16 Q. Can you explain the modifications related to
17 the Revenue Sharing Mechanism from the 2023 General Rate
18 Case?
19 A. The Revenue Sharing Mechanism was modified to
20 include an additional amount of Investment Tax Credits
21 ("ITC") equal to the incremental ITC generated from the
22 Company' s investment in 2023 battery storage projects,
23 including augmentation costs . In addition, the ADITC cap
24 previously set at $25 million was removed.
BRADY, DI 27
Idaho Power Company

1 Effective January 1, 2024, potential revenue sharing
2 between Idaho Power and customers will occur if earnings
3 are in excess of a 9 . 6 percent Idaho ROE. In addition, all
4 revenue sharing will be implemented through the PCA, rather
5 than a portion offsetting customer-funded pension
6 obligations . Lastly, the minimum-specified Idaho ROE is
7 9 . 12 percent .10
8 Q. What have been the results of the revenue
9 sharing mechanism since it was implemented through 2023?
10 A. The Company' s earnings in each year from 2011
11 through 2015, as well as 2018 and 2021, resulted in revenue
12 sharing with customers totaling $126 . 7 million, either as a
13 direct rate offset in the PCA or as an offset to amounts
14 that would have otherwise been collected in rates . The
15 Company' s earnings in 2016, 2017, 2019, 2020, 2022, and
16 2023 were below the revenue sharing threshold. These
17 amounts are detailed in Table 7 below.
18
19
20
21
22
10 In the Matter of the Application of Idaho Power Company for Authority
to Increase its Rates and Charges for Electric Service in the State of
Idaho and for Associated Regulatory Accounting Treatment, Case No. IPC-
E-23-11, Order No. 36042 (December 28, 2023) .
BRADY, DI 28
Idaho Power Company

Table 7 2009-2024 Revenue Sharing and ADITC($ Millions)
Line No. Revenue Sharing/ADITC 2009-2011 2012-2014 2015-2019 2020-2023 2024
Component
1 Available ADITC For Use $45 Million $45 Million $45 Million $45 Million $107.03
Total ADITC
2 ADITC Used: $0.00 $0.00 $0.00 $0.00 $29.83 $29.83
3 Customer Benefits
4 Reduction to Rates: $27.10 $22.80 $8.20 $0.60 $0.00
Offset to Pension
5 $20.30 $47.80 $0.00 $0.00 $0.00 Total Sharing
Balancing Account:
6 Total Sharing $47.40 $70.60 $8.20 $0.60 $0.00 $126.70
1
2 Q. Did the Company' s year-end 2024 financial
3 results warrant any action related to the Revenue Sharing
4 Mechanism per the terms of the 2023 Stipulation?
5 A. Yes . The Company' s year-end 2024 financial
6 results yielded an actual Idaho ROE of 8 . 19 percent,
7 falling below the minimum specified Idaho ROE of 9 . 12
8 percent . As a result, $29, 831, 234 of ADITC was used to
9 achieve the minimum specified ROE of 9 . 12 percent.
10 Q. Did the Company use the same methodology to
11 determine the Idaho jurisdictional 2024 year-end ROE that
12 was used in prior PCA filings?
13 A. Yes . The methodology used to determine the
14 Company' s Idaho jurisdictional 2024 year-end ROE is
15 consistent with the methodology used for the year-end ROE
16 determinations since the inception of the mechanism.
17 Q. Do you have an exhibit demonstrating the
18 application of this methodology?
BRADY, DI 29
Idaho Power Company

1 A. Yes . Exhibit No. 3 provides a step-by-step
2 calculation of the Idaho jurisdictional ROE based on year-
3 end 2024 financial results utilizing the Commission-
4 approved methodology from previous PCA filings .
5 IV. NET CUSTOMER IMPACT
6 Q. What is the revenue impact of the requested
7 PCA rate when compared with PCA rates currently in effect?
8 A. Attachment 2 to the Application filed
9 contemporaneously with my testimony provides a detailed
10 description of the overall revenue impact of this filing on
11 each customer class . As shown in Attachment 2, applying the
12 requested PCA rates to expected customer sales for the June
13 2025 through May 2026 test year results in a PCA decrease
14 of $94 . 8 million, or 5 . 89 percent.
15 Q. What is the combined revenue impact of each of
16 the Company' s filings to be effective June 1, 2025?
17 A. If the proposed PCA, Fixed Cost Adjustment
18 ("FCA") , and Hells Canyon Complex Relicensing filings are
19 approved as filed, the combined impact is an overall
20 decrease in current billed revenue of $105 . 8 million, or
21 6 . 57 percent .
22 Q. Have you prepared a revised Schedule 55 that
23 includes the proposed PCA rates?
BRADY, DI 30
Idaho Power Company

1 A. Yes . Attachment 1 to the Application is a
2 revised Schedule 55 and includes the proposed PCA rates in
3 clean and legislative formats .
4 Q. Please summarize the Company' s request in this
5 filing.
6 A. If approved, the 2025-2026 PCA will result in
7 a decrease in total billed revenue of approximately $94 . 8
8 million, or 5 . 89 percent. The Commission should approve the
9 Company' s computation of the PCA rates, the calculation of
10 which follows the methodology that was approved in Order
11 Nos . 30715 .
12 Q. Does this conclude your testimony?
13 A. Yes, it does .
14
15
16
17
18
19
20
21
22
23
24
25
BRADY, DI 31
Idaho Power Company

1 DECLARATION OF JESSICA G. BRADY
2 I, Jessica G. Brady, declare under penalty of
3 perjury under the laws of the state of Idaho:
4 1 . My name is Jessica G. Brady. I am employed
5 by Idaho Power Company as a Regulatory Analyst in the
6 Regulatory Affairs Department.
7 2 . On behalf of Idaho Power, I present this
8 pre-filed direct testimony and Exhibit Nos . 1-5 in this
9 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 15th day of April 2025, at Boise, Idaho.
17
18 Signed:
19 Jessica G. Brady
BRADY, DI 32
Idaho Power Company

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-25-20
IDAHO POWER COMPANY
BRADY, DI
TESTIMONY
EXHIBIT NO. 1

IDAHO POWER PCA FORECAST
APRIL 1,2025-MARCH 31,2026
Line No. FERC Account April May June July August September October November December January February March Annual
95%Sharing Accounts
1 Hydroelectric Generation(MWh) 962,069 1,111,750 909,370 620,080 503,020 488,126 418,443 364,935 445,869 556,009 465,999 595,318 7,440,989
Account 536,Water for Power
2 Total Expense $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
Account 501,Steam
Jim Bridget 3&4(Coal)
3 Energy(MWh) 136,981 23,808 84,846 243,149 243,149 235,306 243,149 235,633 243,149 243,149 219,619 243,149 2,395,088
4 Total Expense $ 4,666,796 $ 769,031 $ 2,910,432 $ 8,459,144 $ 8,476,778 $ 8,210,107 $ 8,490,005 $ 8,228,678 $ 8,495,883 $ 8,340,108 $ 7,438,728 $ 8,141,714 $ 82,627,408
North Valmy 2(Coal)
5 Energy(MWh) - - 18,000 48,240 43,560 50,000 48,360 59,122 - - - - 267,282
6 Total Expense $ 379,114 $ 379,114 $ 1,352,378 $ 2,993,949 $ 2,752,579 $ 3,065,322 $ 2,993,949 $ 3,571,785 $ 379,114 $ - $ - $ - $ 17,867,306
Jim Bridger 1&2(Gas)
7 Energy(MWh) - - - 150,247 208,200 99,180 128,469 183,101 132,692 199,743 9,792 20,928 1,132,353
8 Total Expense $ 113,036 $ 113,036 $ 113,036 $ 5,660,642 $ 11,324,804 $ 5,790,534 $ 205,695 $ 286,217 $ 10,375,563 $ 15,193,184 $ 802,517 $ 953,296 $ 50,931,559
North Valmy 1(Gas)
9 Energy(MWh) - - - - - - - - - - - - -
10 Total Expense $ - $ - $ - $ - $ - $ - $ - $ - $ - $ (33,476) $ (33,476) $ 198,729 $ 131,777
Account 547,Other Fuel
Langley Gulch
11 Energy(MWh) 76,759 133,245 207,200 210,704 211,120 180,475 125,155 215,681 226,896 226,896 194,863 - 2,008,994
12 Total Expense $ 3,116,235 $ 3,023,409 $ 4,895,065 $ 5,428,295 $ 5,393,985 $ 4,867,797 $ 2,855,593 $ 8,501,417 $ 11,783,226 $ 11,463,303 $ 8,080,557 $ 357,939 $ 69,766,821
Danskin
13 Energy(MWh) - - - 121,096 121,096 54,720 - 73,894 137,288 137,288 71,232 - 716,614
14 Total Expense $ 351,227 $ 351,227 $ 351,227 $ 5,056,186 $ 5,012,206 $ 2,402,680 $ 268,333 $ 4,580,430 $ 10,731,199 $ 10,437,756 $ 4,536,860 $ 362,437 $ 44,441,770
Bennett Mountain
15 Energy(MWh) - - - 105,592 77,696 7,040 67,176 - 29,952 - - 53,955 341,411
16 Total Expense $ 172,992.60 $ 172,992.60 $ 172,992.60 $ 4,250,265.56 $ 3,145,834.94 $ 437,344.60 $ 2,256,530.49 $ 132,164.01 $ 2,437,806.57 $ 132,164.01 $ 132,164.01 $ 2,322,685.49 $ 15,765,937
Account 555,Purchased Power Non-PURPA
17 Energy(MWh) 151,013 204,794 206,226 211,234 189,124 128,954 105,910 117,658 132,154 103,768 166,359 207,776 1,924,968
18 Total Expense $ 5,453,339 $ 6,886,585 $ 9,942,682 $ 12,574,112 $ 10,450,620 $ 5,717,860 $ 6,184,728 $ 9,269,018 $ 11,269,795 $ 7,105,009 $ 9,834,271 $ 8,714,766 $ 103,402,787
Account 565,3rd Party Transmission
19 Total Expense $ 674,709 $ 757,421 $ 1,368,386 $ 1,532,092 $ 1,368,713 $ 946,932 $ 1,389,807 $ 904,951 $ 783,381 $ 889,854 $ 595,030 $ 714,127 $ 11,925,403
Account 447,Surplus Sales
20 Energy(MWh) (386,475) (403,611) (111,647) (5) (65,390) (68,116) (105,457) (91,347) (32,805) (145,673) (5,253) (31,227) (1,447,006)
21 Total Expense $ (17,474,445) $ (11,986,551) $ (4,281,746) $ (1,079,525) $ (8,617,634) $ (6,409,488) $ (6,774,219) $ (6,871,989) $ (5,073,627) $ (14,682,149) $ (2,045,498) $ (3,435,848) $ (88,732,720)
100%Sharing Accounts
Account 555,PURPA
22 Energy(MWh) 294,023 315,287 298,997 281,166 272,853 228,596 215,290 172,832 184,782 194,865 226,513 241,713 2,926,917
23 Total Expense $ 16,905,658 $ 18,278,073 $ 22,695,665 $ 25,393,912 $ 25,311,877 $ 17,979,445 $ 16,811,282 $ 16,273,377 $ 17,804,998 $ 16,119,863 $ 18,808,009 $ 14,686,908 $ 227,069,067
Account 555,Demand Response Incentives
24 Total Expense $ $ $ 270,468 $ 3,047,657 $ 4,657,950 $ 1,277,208 $ 184,487 $ 973,763 $ $ $ $ $ 10,411,533
Account 577.4,Energy Storage Rents
25 Total Expense $ $ $ 1,795,500 $ 1,795,500 $ 1,795,500 $ 1,795,500 $ 1,795,500 $ 1,795,500 $ 1,795,500 $ 1,795,500 $ 1,795,500 $ 1,795,500 $ 17,955,000
95%Sharing Accounts $ (2,546,996) $ 466,265 $ 16,824,454 $ 44,875,161 $ 39,307,887 $ 25,029,088 $ 17,870,422 $ 28,602,673 $ 51,182,340 $ 38,845,755 $ 29,341,153 $ 18,329,846 $ 308,128,048
100%Sharing Accounts $ 16,905,658 $ 18,278,073 $ 24,761,633 $ 30,237,069 $ 31,765,327 $ 21,052,153 $ 18,791,269 $ 19,042,640 $ 19,600,498 $ 17,915,363 $ 20,603,509 $ 16,482,408 $ 255,435,600
26 Total Net Power Supply Expense $ 14,358,662 $ 18,744,338 $ 41,586,088 $ 75,112,230 $ 71,073,214 $ 46,081,241 $ 36,661,691 $ 47,645,313 $ 70,782,838 $ 56,761,118 $ 49,944,662 $ 34,812,254 $ 563,563,649
27 Total Generation(MWh) 1,620,845 1,788,885 1,724,639 1,991,508 1,869,818 1,472,397 1,351,951 1,422,856 1,532,782 1,661,718 1,354,377 1,362,839 19,154,615
28 Total Load(MWh) 1,234,371 1,385,273 1,612,992 1,991,504 1,804,428 1,404,280 1,246,494 1,331,510 1,499,977 1,516,045 1,349,123 1,331,612 17,707,609
Exhibit No. 1
Case No.IPC-E-25-20
J.Brady,IPC
Page 1 of 1

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-25-20
IDAHO POWER COMPANY
BRADY, DI
TESTIMONY
EXHIBIT NO. 2

Power Cost Adjustment
April 2024 thru March 2025
April May June July August September October November December January February March Totals
Idaho Jurisdiction Net Power Supply Expense(Non-QF)
Actual Non-OF
Fuel Expense-Coal $ 1,179,263.10 2,020,383.43 2,660,584.17 8,276,217.38 8,214,487.25 5,427,737.37 4,591,973.37 5,886,796.66 7,166,727.02 8,863,012.76 7,479,870.26 6,785,498.76 68,552,551.53
Fuel Expense-Gas $ 3,105,500.83 2,045,522.45 7,402,724.83 20,890,491.28 19,449,759.20 11,102,585.98 9,113,568.82 16,694,639.91 26,676,433.00 26,814,879.16 15,052,547.31 4,246,714.20 162,595,366.97
Non-Firm Purchases $ 6,656,403.76 6,010,904.13 14,375,782.67 17,532,267.74 11,224,012.78 7,279,802.76 15,352,454.19 15,298,338.72 15,781,881.54 14,256,189.94 14,167,759.71 (3,307,706.78) 134,628,091.16
Third Party Transmission $ 716,985.04 664,439.29 2,204,857.03 1,503,513.56 1,307,907.49 1,053,138.16 1,538,346.15 1,183,539.33 623,185.17 965,091.75 854,311.26 742,335.38 13,357,649.61
Surplus Sales B Transmission Losses $ (15,013,723.41) (11,093,728.13) (4,977,163.03) (3,642,120.11) (3,859,600.11) (3,098,189.78) (8,674,380.21) (8,765,004.92) (8,492,038.53) (13,033,218.13) (16,750,820.05) (15,724,694.50) (113,124,680.91)
Water for Power(Leases) $
Total Actual NPSE $ (3,355,570.68) (352,478.83) 21,666,785.67 44,560,369.85 36,336,566.61 21,765,074.49 21,921,962.32 30,298,309.70 41,756,188.20 37,865,955.48 20,803,668.49 (7,257,852.94) 266,008,978.36
Idaho Allocation 95.6% 95.7% 95.9% 96.0% 96.0% 96.0% 95.7% 95.3% 95.6% 95.5% 95.5% 96.1
Net Idaho Jurisctional Actual Non-QF $ (3,207,925.57) (337,322.24) 20,778,447.46 42,777,955.06 34,883,103.95 20,894,471.51 20,979,317.94 28,874,289.14 39,918,915.92 36,161,987.48 19,867,503.41 (6,974,796.68) 254,615,947.38
Base Non-QF
Fuel Expense-Coal $ 4,321,401.00 4,578,880.00 5,597,322.00 7,146,746.00 7,643,877.00 6,655,023.00 4,655,438.00 4,397,909.00 5,020,646.00 5,483,866.00 5,225,193.00 4,796,697.00 65,522,998.00
Fuel Expense-Gas $ 7,891,450.00 8,361,642.00 10,221,452.00 13,050,904.00 13,958,732.00 12,152,953.00 8,501,447.00 8,031,165.00 9,168,364.00 10,014,266.00 9,541,895.00 8,759,405.00 119,653,675.00
Non-Firm Purchases $ 6,559,959.00 6,950,818.00 8,496,830.00 10,848,881.00 11,603,535.00 10,102,437.00 7,067,034.00 6,676,100.00 7,621,425.00 8,324,601.00 7,931,932.00 7,281,468.00 99,465,020.00
Third Party Transmission $ 676,879.00 717,209.00 876,732.00 1,119,424.00 1,197,292.00 1,042,404.00 729,201.00 688,863.00 786,405.00 858,961.00 818,444.00 751,327.00 10,263,141.00
Surplus Sales $ (2,287,649.00) (2,423,953.00) (2,963,092.00) (3,783,321.00) (4,046,491.00) (3,523,014.00) (2,464,481.00) (2,328,151.00) (2,657,813.00) (2,903,031.00) (2,766,096.00) (2,539,260.00) (34,686,352.00)
Water for Power(Leases) $ 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00
Idaho Base NPSE $ 17,162,040.00 18,184,596.00 22,229,244.00 28,382,634.00 30,356,945.00 26,429,803.00 18,488,639.00 17,465,886.00 19,939,027.00 21,778,663.00 20,751,368.00 19,049,637.00 260,218,482.00
Idaho Allocation 95.57% 95.57% 95.57% 95.57% 95.57% 95.57% 95.57% 95.57% 95.57% 95.57% 95.57% 95.57
Net Idaho Jurisdiction 95%Items $ 16,401,761.63 17,379,018.40 21,244,488.49 27,125,283.31 29,012,132.34 25,258,962.73 17,669,592.29 16,692,147.25 19,055,728.10 20,813,868.23 19,832,082.40 18,205,738.08 248,690,803.25
Idaho Jurisdiction Change From Base $ (19,609,687.20) (17,716,340.64) (466,041.03) 15,652,671.75 5,870,971.61 (4,364,491.22) 3,309,725.65 12,182,141.89 20,863,187.82 15,348,119.25 35,421.01 (25,180,534.76) 5,925,144.13
Sharing Percentage 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0
Net Power Supply Expense Deferral(1) $ (18,629,202.84) (16,830,523.61) (442,738.98) 14,870,038.16 5,577,423.03 (4,146,266.66) 3,144,239.37 11,573,034.80 19,820,028.43 14,580,713.29 33,649.96 (23,921,508.02) 5,628,886.93
Idaho Jurisdictional Qualifying Facility NPSE
Actual OF(Includes Net Metering,Raft River 100%8.Liquidated Damages) $ 18,465,796.01 21,121,427.39 23,883,265.91 25,495,769.78 23,624,763.79 16,900,807.35 15,467,343.46 20,278,316.74 16,413,427.77 14,034,010.11 16,509,338.73 13,940,441.73 226,134,708.77
Idaho Allocation 95.6% 95.7% 95.9% 96.0% 96.0% 96.0% 95.7% 95.3% 95.6% 95.5% 95.5% 96.1
Idaho Jurisctional Actual OF $ 17,653,300.99 20,213,206.01 22,904,052.01 24,475,938.99 22,679,773.24 16,224,775.06 14,802,247.69 19,325,235.85 15,691,236.95 13,402,479.66 15,766,418.49 13,396,764.50 216,535,429.44
Base OF $ 14,143,416.00 14,986,115.00 18,319,351.00 23,390,424.00 25,017,474.00 21,781,075.00 15,236,680.00 14,393,818.00 16,431,959.00 17,948,022.00 17,101,418.00 15,699,003.00 214,448,755.00
Idaho Allocation 95.57% 95.57% 95.57% 95.57% 95.57% 95.57% 95.57% 95.57% 95.57% 95.57% 95.57% 95.57
Idaho Jurisdictional Base $ 13,516,862.67 14,322,230.11 17,507,803.75 22,354,228.22 23,909,199.90 20,816,173.38 14,561,695.08 13,756,171.86 15,704,023.22 17,152,924.63 16,343,825.18 15,003,537.17 204,948,675.17
Idaho Jurisdiction Change From Base $ 4,136,438.32 5,890,975.90 5,396,248.26 2,121,710.77 (1,229,426.66) (4,591,398.32) 240,552.61 5,569,063.99 (12,786.27) (3,750,444.97) (577,406.69) (1,606,772.67) 11,586,754.27
Sharing Percentage 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0
OF Deferral(2) $ 4,136,438.32 5,890,975.90 5,396,248.26 2,121,710.77 (1,229,426.66) (4,591,398.32) 240,552.61 5,569,063.99 (12,786.27) (3,750,444.97) (577,406.69) (1,606,772.67) 11,586,754.27
Idaho Revenue Adjustment(SBAR)
Actual Idaho Jurisdictional Billing Month Sales MWh 1,028,112 1,089,783 1,309,703 1,675,693 1,744,131 1,452,517 1,142,179 1,049,305 1,179,618 1,235,496 1,275,661 1,162,831 15,345,030
Normalized Idaho Jurisdictional Billing Month Sales MWh 1,017,495 1,092,040 1,256,135 1,544,353 1,630,099 1,445,881 1,124,956 1,049,883 1,166,688 1,263,248 1,210,192 1,106,864 14,907,834
Sales Change MWh 10,617 (2,257) 53,568 131,340 114,032 6,636 17,223 (578) 12,930 (27,752) 65,469 55,967 437,196
•of Prior Period Billings at Old Rate-effective thru 12/2023 $26.72 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000
•of Current Period Billings at New Rate-effective 01/2024 $30.90 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000
Sales Adjustment Prior To Sharing @ $ (328,071.69) 69,733.11 (1,655,240.60) (4,058,421.30) (3,523,579.41) (205,062.97) (532,199.98) 17,874.39 (399,542.80) 857,547.30 (2,023,002.64) (1,729,379.40) (13,509,345.99)
Sharing Percentage 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0
Idaho Revenue Adjustment(SBAR)(3) $ (311,668.11) 66,246.45 (1,572,478.57) (3,855,500.24) (3,347,400.44) (194,809.82) (505,589.98) 16,980.67 (379,565.66) 814,669.94 (1,921,852.51) (1,642,910.43) (12,833,878.70)
Idaho Jurisdcitional Demand Response Incentive Payments
Idaho Actual Demand Response $ - - 236,321.59 2,511,013.89 3,000,465.39 2,342,359.16 784,667.28 61,236.69 14,519.40 3,553.70 (550.20) - 8,953,586.90
Idaho Base Demand Response $ 675,353.00 715,592.00 874,755.00 1,116,901.00 1,194,593.00 1,040,054.00 727,557.00 687,310.00 784,632.00 857,024.00 816,599.00 749,633.00 10,240,003.00
Change From Base $ (675,353.00) (715,592.00) (638,433.41) 1,394,112.89 1,805,872.39 1,302,305.16 57,110.28 (626,073.31) (770,112.60) (853,470.30) (817,149.20) (749,633.00) (1,286,416.10)
Sharing Percentage 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0
Change From Base(4) $ (675,353.00) (715,592.00) (638,433.41) 1,394,112.89 1,805,872.39 1,302,305.16 57,110.28 (626,073.31) (770,112.60) (853,470.30) (817,149.20) (749,633.00) (1,286,416.10)
Idaho Miscellaneous Revenue
System Emission Allowance Sales Credit $ - - - - - - - - - - - - -
System Renewable Energy Credit Sales $ (4,120.00) 612.89 100.87 202.86 (37,249.32) (15,795.54) (1,442,033.63) (562,115.94) 2,575.00 (20,660.63) (21,207,968.38) (339,315.91) (23,625,767.73)
Revenue Subtotal $ (4,120.00) 612.89 100.87 202.86 (37,249.32) (15,795.54) (1,442,033.63) (562,115.94) 2,575.00 (20,660.63) (21,207,968.38) (339,315.91) (23,625,767.73)
Idaho Allocation 95.6% 95.7% 95.9% 96.0% 96.0% 96.0% 95.7% 95.3% 95.6% 95.5% 95.5% 96.1
Sharing Percentage 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0
Miscellaneous Revenue Deferral(5) $ (3,741.78) 557.21 91.90 185.01 (33,971.38) (14,405.53) (1,311,024.87) (508,911.67) 2,338.62 (18,744.36) (19,240,929.31) (309,778.46) (21,438,334.62)
E o.
Idaho PTP Wheeling Revenues Case No.IPC-E-25-20
J.Brady,IPC
1of2

Actual PTP Revenue Booked $ (4,359,217.44) (3,635,946.28) (4,447,738.64) (4,928,396.77) (4,904,003.55) (4,627,236.44) (4,384,215.31) (4,535,577.98) (4,673,856.36) (4,264,695.00) (5,166,433.48) (4,228,015.54) (54,155,332.79)
Idaho Allocation 95.6% 95.7% 95.9% 96.0% 96.0% 96.0% 95.7% 95.3% 95.6% 95.5% 95.5% 96.1
ID PTP Revenue $ (4,167,411.87) (3,479,600.59) (4,265,381.36) (4,731,260.90) (4,707,843.41) (4,442,146.98) (4,195,694.05) (4,322,405.81) (4,468,206.68) (4,072,783.73) (4,933,943.97) (4,063,122.93) (51,849,802.28)
•of Prior Period Billings at Old Rate-effective N/A 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000
•of Current Period Billings at New Rate-effective 04/2024 $ 3.11 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000
GATT Revenue Credited in Base Rates $ (3,197,428.96) (3,389,225.95) (4,073,175.26) (5,211,406.77) (5,424,246.47) (4,517,328.93) (3,552,177.62) (3,263,337.12) (3,668,612.56) (3,842,391.50) (3,967,306.77) (3,616,404.32) (47,723,042.25)
OATT Revenue Difference (969,982.91) (90,374.64) (192,206.10) 480,145.87 716,403.06 75,181.95 (643,516.43) (1,059,068.69) (799,594.12) (230,392.23) (966,637.20) (446,718.61) (4,126,760.03)
Sharing Percentage 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0
GATT Revenue Deferral(6) $ (921,483.76) (85,855.90) (182,595.79) 456,138.58 680,582.90 71,422.86 (611,340.61) (1,006,115.25) (759,614.41) (218,872.62) (918,305.34 424,382.68( ) (3,920,422.02)
TOTAL DEFERRAL(Sum of 1-6) $ (16,405,011.17) (11,674,191.95) 2,560,093.41 14,986,685.17 3,453,079.84 (7,573,152.31) 1,013,946.80 15,017,979.23 17,900,288.11 10,553,850.98 (23,441,993.09) (28,654,985.26) (22,263,410.24)
PCA Forecasted Revenues
Actual Idaho Jurisdictional Billing Month Sales MWh 1,028,112 1,089,783 1,309,703 1,675,693 1,744,131 1,452,517 1,142,179 1,049,305 1,179,618 1,235,496 1,275,661 1,162,831 15,345,030
•of Prior Period Billings at Old Rate 0.000% 0.000% 56.299% 0.3101% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000
•of Current Period Billings at New Rate 100.000% 100.000% 43.700% 99.700% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000
Forecast Rate Revenues(7) (3,546,987.19) (3,759,752.71) (3,044,896.98) (2,523,391.49) (2,617,940.25) (2,180,228.64) (1,714,411.11) (1,575,006.14) (1,770,606.89) (1,854,479.01) (1,914,767.67) (1,745,383.27) (28,247,851.35)
PCA Balancing Account Balance
Monthly Interest Rate 5%for 2024/2025 % 0.4167% 0.4167% 0.4167% 0.4167% 0.4167% 0.4167% 0.4167% 0.4167% 0.4167% 0.4167% 0.4167% 0.4167% 5.0000
Beginning Balance $ 89,971,187.52 63,860,297.09 41,765,119.97 32,919,115.95 35,522,952.82 25,921,257.69 7,839,425.61 379,441.39 7,585,144.45 16,732,381.45 18,157,352.76 (14,668,450.65) 89,971,187.52
2024-2025 Incremental Deferral(Sum of 1-6 above) (16,405,011.17) (11,674,191.95) 2,560,093.41 14,986,685.17 3,453,079.84 (7,573,152.31) 1,013,946.80 15,017,979.23 17,900,288.11 10,553,850.98 (23,441,993.09) (28,654,985.26) (22,263,410.24)
2024-2025 PCA Forecast Revenues(Collections)7 above (3,546,987.19) (3,759,752.71) (3,044,896.98) (2,523,391.49) (2,617,940.25) (2,180,228.64) (1,714,411.11) (1,575,006.14) (1,770,606.89) (1,854,479.01) (1,914,767.67) (1,745,383.27) (28,247,851.35)
2024-2025 PCA Prior Balance Revenues(Collections) 6,533,772.02 6,927,317.03 8,535,221.78 9,996,619.79 10,584,847.02 8,436,456.37 6,792,184.18 6,238,851.04 7,014,048.99 7,344,118.92 7,544,698.29 6,916,056.02 92,864,191.45
2024-2025 Ending Balance Without Current Month Interest 63,485,417.14 41,499,035.40 32,745,094.62 35,385,789.84 25,773,245.39 7,731,420.37 346,777.12 7,583,563.44 16,700,776.68 18,087,634.50 (14,744,106.29) (51,984,875.20) (53,404,265.52)
Current Month Interest 374,879.95 266,084.57 174,021.33 137,162.98 148,012.30 108,005.24 32,664.27 1,581.01 31,604.77 69,718.26 75,655.64 61,118.54 1,358,271.78
2024-2025 Ending Deferral Balance $ 63,860,297.09 41,765,119.97 32,919,115.95 35,522,952.82 25,921,257.69 7,839,425.61 379,441.39 7,585,144.45 16,732,381.45 18,157,352.76 14,668,450.65 52,045,993.74 52,045,993.74
Tab is 100%locked down,with no manual inputs.
Idaho Billed Sales MWh 1,028,112 1,089,783 1,309,703 1,675,693 1,744,131 1,452,517 1,142,179 1,049,305 1,179,618 1,235,496 1,275,661 1,162,831 15,345,030
Oregon Billed Sales MWh 47,563 49,345 56,090 69,291 72,841 59,784 51,811 51,890 54,890 57,683 60,097 47,432 678,716
Total MWh 1,075,675 1,139,128 1,365,793 1,744,984 1,816,971 1,512,301 1,193,990 1,101,195 1,234,508 1,293,179 1,335,758 1,210,263 16,023,746
Idaho%Billed Sales 95.6% 95.7% 95.9% 96.0% 96.0% 96.0% 95.7% 95.3% 95.6% 95.5% 95.5% 96.1%
Oregon%Billed Sales 4.4% 4.3% 4.1% 4.0% 4.0% 4.0% 4.3% 4.7% 4.4% 4.5% 4.5% 3.9%
Exhibit No.2
Case No.IPC-E-25-20
J.Brady,IPC
2of2

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-25-20
IDAHO POWER COMPANY
BRADY, DI
TESTIMONY
EXHIBIT NO. 3

1 IDAHO POWER COMPANY
2
3 ADDITIONAL INVESTMENT TAX CREDIT ANALYSIS
4 For the Twelve Months Ended December 31,2024
5
6 Actual September 30,2024 Actual December 31,2024
7 TOTAL TOTAL
8 SYSTEM IDAHO IDAHO% SYSTEM IDAHO IDAHO%
9 "'SUMMARY OF RESULTS"'
10 TOTAL COMBINED RATE BASE 4,750,866,989 4,546,034,817 95.7% Sept Allocations/Ratios
11
12 DEVELOPMENT OF NET INCOME
13 OPERATING REVENUES
14 RETAIL SALES REVENUES(Ind 449.1 Rev) 1,217,132,286 1,168,693,704 Direct Assign 1,552,780,508 1,487,976,576 Direct Assign
15 OTHER OPERATING REVENUES 205,023,767 196,465,546 95.8% 265,808,787 254,713,242 95.8%
16 TOTAL OPERATING REVENUES 1,422,156,052 1,365,159,250 1,818,589,295 1,742,689,818
17
18 OPERATING EXPENSES
19 OPERATION&MAINTENANCE EXPENSES 955,477,260 916,556,286 95.9% 1,253,874,561 1,202,798,496 95.9%
20 DEPRECIATION EXPENSE 158,762,555 152,277,981 95.9% 214,706,954 205,937,360 95.9%
21 AMORTIZATION OF LIMITED TERM PLANT 4,883,630 4,684,267 95.9% 6,857,622 6,577,675 95.9%
22 TAXES OTHER THAN INCOME 21,837,808 20,002,572 91.6% 16,155,738 14,798,020 91.6%
23 REGULATORY DEBITS/CREDITS 4,250,230 4,004,715 94.2% 5,389,668 5,078,333 94.2%
24 PROVISION FOR DEFERRED INCOME TAXES (62,769,404) (60,511,358) 96.4% (74,296,567) (71,623,847) 96.4%
25 INVESTMENT TAX CREDIT ADJUSTMENT 12,434,372 11,912,994 95.8% 94,674,793 90,705,046 95.8%
26 FEDERAL INCOME TAXES 66,789,566 64,580,552 96.7% 5,421,813 5,242,491 96.7%
27 STATE INCOME TAXES 20,219,388 19,569,449 96.8% 8,877,729 8,592,360 96.8%
28 TOTAL OPERATING EXPENSES 1,181,885,405 1,133,077,459 1,531,662,311 1,468,105,935
29
so OPERATING INCOME 240,270,647 232,081,790 286,926,984 274,583,884
31 ADD:IERCO OPERATING INCOME 1,202,994 1,152,790 95.8% 1,651,182 1,582,273 95.8%
32
33 OPERATING INCOME BEFORE OTHER INCOME AND DEDUCTIO 241,473,641 233,234,580 288,578,166 276,166,157 95.7%
34 ADD:AFUDC EQUITY 53,238,345 50,942,990 95.7%(L 10)
35 ADD:OTHER INCOME AND DEDUCTIONS 44,473,493 42,560,648 95.7%(L 33)
36
37 INCOME BEFORE INTEREST CHARGES 386,290,005 369,669,795
38 LESS:INTEREST CHARGES 135,516,528 129,673,775 95.7%(L 10)
39
4o NET INCOME 250,773,476 239,996,020
41
42 ACTUAL YEAR-END RESULTS-BEFORE ITC ADJUSTMENT
43 EARNINGS ON COMMON STOCK 250,773,476 239,996,020
44 COMMON EQUITY AT YEAR END 3,060,764,881 2,928,800,942 95.7%(L10)
45
46 RETURN ON YEAR-END COMMON EQUITY 8.19% 8.19%
47
48 EARNINGS ON COMMON STOCK @ 9.12 ROE 279,141,757 267,106,646 (L44'9.12%)
49 EARNINGS ON COMMON STOCK @ 9.6 ROE 293,833,429 281,164,890 (L44'9.6%)
51
52
53 ACTUAL YEAR-END RESULTS-AFTER ITC ADJUSTMENT:
54 INVESTMENT TAX CREDIT ADJUSTMENT 29,831,234 (1-48-1.43)/(1-9.12%)
55 ADJUSTED EARNINGS ON COMMON STOCK 269,827,254
56 ADJUSTED COMMON EQUITY AT YEAR-END 2,958,632,176
57 ADJUSTED RETURN ON YEAR-END COMMON EQUITY 9.12%
58
59 IF IDAHO RETURN ON COMMON EQUITY(Line 46)<9.12%
60 ADDITIONAL ITC ADJUSTMENT(Annualized) If L 54 is negative,then 0(no cap on ADITC per Order 36042) 29,831,234
61
62 IF IDAHO RETURN ON COMMON EQUITY(Line 46)>9.6%
63 IDAHO EARNINGS GREATER THAN 9.6%ROE 0 (1-43-1.49)/(1-9.6%)
64
67
68 Per Order#36042: After Tax Tax Gross Up
69 ROE Greater than 9.6%--CUSTOMER SHARE.80%(Reduction to rates) 0
71 ROE Greater than 9.6%--COMPANY SHARE 0
73 0
74
Exhibit No.3
Case No.IPC-E-25-20
J.Brady,IPC
1of1

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-25-20
IDAHO POWER COMPANY
BRADY, DI
TESTIMONY
CONFIDENTIAL
EXHIBIT NO. 4

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-25-20
IDAHO POWER COMPANY
BRADY, DI
TESTIMONY
CONFIDENTIAL
EXHIBIT NO. 5