HomeMy WebLinkAbout20260415Direct Brady.pdf RECEIVED
APRIL 15, 2026
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-26-10
COST ADJUSTMENT ("PCA") RATES )
FOR ELECTRIC SERVICE FROM JUNE )
1, 2026, THROUGH MAY 31, 2027 . )
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 Regulatory Consultant in the
7 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 . I was promoted to Senior Regulatory
23 Analyst in October 2023 and to Regulatory Consultant in
24 October 2025 . As a Regulatory Consultant, I am responsible
25 for running the AURORA model ("AURORA") to calculate net
BRADY, DI 1
Idaho Power Company
1 power supply expenses ("NPSE") for ratemaking purposes, as
2 well as the determination of the marginal cost of energy
3 used in the Company' s marginal cost analyses . My duties
4 also include providing analytical support for other
5 regulatory activities within the Regulatory Affairs
6 Department .
7 Q. What is the Company requesting in this case?
8 A. The Company is requesting approval of its
9 2026-2027 Power Cost Adjustment ("PCA") rates to become
10 effective June 1, 2026 . If approved, the 2026-2027 PCA
11 will result in an increase in total billed revenue of
12 approximately $51 . 6 million, or 3 . 02 percent.
13 Q. How is your testimony organized?
14 A. My testimony consists of four sections . In the
15 first section, I provide an overview of the PCA. In the
16 second section, I detail the 2026-2027 PCA amount in
17 comparison to last year' s PCA amount, identify and discuss
18 the main factors contributing to this change, which
19 includes a discussion regarding the Company' s proposal to
20 return the balance of the Boardman Balancing Account, and
21 present the quantification of the 2026-2027 PCA rates to
22 become effective June 1, 2026 . In the third section, I
23 discuss the additional PCA component related to revenue
24 sharing. In the fourth section, I detail the net customer
25 impact of the 2026-2027 PCA rates if approved as filed.
BRADY, DI 2
Idaho Power Company
1 Q. Are you sponsoring any exhibits?
2 A. Yes . I am offering the following exhibits :
3 Exhibit Description
4 Exhibit No. 1 2026-2027 PCA Forecast
5 Exhibit No. 2 2025 Balancing Adjustment
6 Exhibit No. 3 2025 ROE Determination Revenue Sharing
7 Exhibit No. 4 Confidential - Clean Energy Your Way
8 Generation and Expenses
9 I . PCA OVERVIEW
10 Q. What is the purpose of the PCA?
11 A. The PCA is a rate mechanism that quantifies
12 and tracks annual differences between actual NPSE and the
13 normalized or "base level" of NPSE recovered in the
14 Company' s base rates, resulting in a credit or surcharge
15 that is updated annually on June 1 . The PCA mechanism uses
16 a 12-month test period of April through March ("PCA Year")
17 and includes a forecast component and a Balancing
18 Adjustment . The forecast component represents the
19 difference between the Company' s NPSE forecast from the
20 March Operating Plan and base level NPSE recovered in the
21 Company' s base rates . The Balancing Adjustment reflects a
22 reconciliation of differences between forecast and actual
23 NPSE from the prior PCA year, including the collection of
24 the prior year' s Balancing Adjustment, as well as the
25 annual variance between actual and base-level wheeling
BRADY, DI 3
Idaho Power Company
1 revenues .
2 Q. How does the PCA mechanism function?
3 A. The PCA allows the Company to pass through to
4 customers 95 percent of the annual differences in actual
5 NPSE as compared with base level NPSE, whether positive or
6 negative, with the exception of three types of expenses .
7 For expenses associated with the Public Utility Regulatory
8 Policies Act of 1978 ("PURPA") , demand response incentive
9 payments, and capital lease payments associated with
10 battery energy storage systems ("BESS") , the Company is
11 authorized to pass 100 percent of the annual variance
12 through the PCA. The PCA is also the rate mechanism used by
13 the Company to provide customer benefits resulting from the
14 revenue sharing mechanism approved by the Commission in
15 Order No . 34071 .
16 Q. Does the revenue collected from customers
17 through the annual PCA rate contribute toward the Company' s
18 earnings?
19 A. No. The PCA mechanism provides for the annual
20 collection or refund of net power supply cost differences
21 between actual costs incurred by the Company and the base
22 level NPSE component of base rates . Aside from the 95
23 percent to 5 percent sharing component I just described,
24 the PCA provides for a one-for-one collection or refund of
25 actual net power supply expenses incurred, or to be
BRADY, DI 4
Idaho Power Company
1 incurred, to provide safe, reliable electric service to
2 customers .
3 Q. What are the components of the PCA base level
4 NPSE?
5 A. The PCA base level NPSE includes the following
6 Federal Energy Regulatory Commission ("FERC") accounts :
7 Account 501, Fuel (steam) ; Account 536, Water for Power;
8 Account 547, Fuel (gas) ; Account 555, Purchased Power;
9 Account 565, Transmission of Electricity by Others; Account
10 577 . 4, Energy Storage Rents; and Account 447, Sales for
11 Resale (typically referred to as surplus sales) .
12 The PCA base level expense component for FERC
13 Account 555 includes costs of both PURPA and non-PURPA
14 purchases . Per Order No . 32426, the Company adjusts FERC
15 Account 555 to also include demand response incentive
16 payments that the Company provides to customers who
17 participate in any of its three demand response programs .
18 II . 2026-2027 PCA
19 Q. What is the total PCA collection that would
20 result under the 2026-2027 PCA rates proposed by the
21 Company in this case?
22 A. The 2026-2027 PCA rates would result in total
23 PCA collection of $86 . 8 million. This represents an
24 increase in total billed revenue of $51 . 6 million for the
25 upcoming year, an increase of 3 . 02 percent.
BRADY, DI 5
Idaho Power Company
1 Q. Have you prepared a table that details the
2 $51 . 6 million revenue impact by component?
3 A. Yes . Table 1 presents a separation of the
4 $51 . 6 million increase into each component included in the
5 Company' s proposed rates .
Table 1 Idaho Jurisdictional Revenue Impact by Component
Line
No. Rate Component 2025-2026 PCA 2026-2027 PCA Difference
1 PCA Forecast $ 88,931,875 $ 165,106,470 $ 76,174,596
2 PCA Balancing Adjustment $ (53,722,317) $ (78,340,926)1 $ (24,618,609)
3 PCA Total $ 35,209,558 $ 86,765,544 $ 51,555,987
4 Revenue Sharing $ 0 $ 0 $ 0
5 Total Revenue Impact $ 35,209,558 $ 86,765,544 $ 51,555,987
6
7 Q. What are the main factors driving the revenue
8 change requested in this case?
9 A. The increase in this year' s filing is driven
10 by an increase to the forecast component, partially offset
11 by a decrease to the Balancing Adjustment.
12 The increase in the forecast component is largely
13 attributable to a 16 percent decrease in forecast hydro
14 generation compared to the prior PCA year. The decrease in
15 the Balancing Adjustment is driven primarily by increased
16 Renewable Energy Credit ("REC") sales, the Sales Based
17 Adjustment ("SBA") , which reflects variances between actual
18 sales and the sales used to establish base-level NPSE, and
1 The 2026-2027 Balancing Adjustment amount includes the Idaho-
jurisdictional Boardman Balancing Account over-collection amount of
$3,279,207.
BRADY, DI 6
Idaho Power Company
1 the inclusion of the Idaho-jurisdictional Boardman
2 Balancing Account over-collection amount of $3, 279, 2072,
3 which I describe in more detail later in my testimony.
4 A. PCA Forecast.
5 Q. How is the PCA forecast amount determined?
6 A. As described previously, the PCA forecast
7 component represents the difference between the Company' s
8 forecast of NPSE for the upcoming April - March test year
9 and base level NPSE recovered in the Company' s base rates . 3
10 Q. What is the Company' s determination of the
11 system-level difference between currently approved base
12 level NPSE and the forecast of NPSE for the 2026-2027 PCA
13 Year?
14 A. The system-level forecast of NPSE for the
15 2026-2027 PCA Year is $649, 935, 889, which is $181, 095, 264
16 higher than the currently approved base level NPSE of
17 $468, 840, 625 . Table 2 presents the system-level differences
18 between currently approved base level NPSE and the forecast
19 of NPSE for the 2026-2027 PCA Year by FERC account.
20
21
2 Boardman Power Plant 2024 and 2025 Annual Review at Page 4, Case No.
IPC-E-12-09.
3 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 Authority to Implement Certain Measures to Mitigate the
Impact of Regulatory Lag, Case No. IPC-E-25-16, Order No. 36892
(December 30, 2025) .
BRADY, DI 7
Idaho Power Company
Table 2 2026-2027 PCA FORECAST(Total System)
Line No. FERC Account Base NPSE Forecast Difference
95%Sharing Accounts
1 Account 501,Steam $ 108,005,080 $ 140,827,611 $ 32,822,531
2 Account 536,Water for Power $ 0 $ 0 $ 0
3 Account 547,Other Fuel $ 50,540,155 $ 139,451,690 $ 88,911,536
4 Account 555,Purchased Power Non-PURPA $ 124,823,345 $ 135,649,035 $ 10,825,690
5 Account 565,3rd Party Transmission $ 12,357,059 $ 12,180,727 $ (176,331)
6 Account 447,Surplus Sales $ (84,493,217) $ (36,004,689) $ 48,488,528
$ 211,232,422 $ 392,104,375 $ 180,871,953
100%Sharing Accounts
7 Account 555,PURPA $ 226,719,444 $ 225,630,980 $ (1,088,465)
8 Account 555,Demand Response Incentives $ 9,342,758 $ 10,654,534 $ 1,311,776
9 Account 577.4,Energy Storage Rents $ 21,546,000 $ 21,546,000 $ 0
10 Total $ 468,840,625 $ 649,935,889 $ 181,095,264
1
2 Q. What is the basis for the forecast of NPSE for
3 the 2026-2027 PCA Year?
4 A. The forecast of NPSE for the 2026-2027 PCA
5 Year is based on the Company' s March 2026 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 36-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 using a
13 simulation of the dispatch of the Company' s generation
14 resources for each month, with the first 12 months
15 segmented into heavy-load and light-load hours . The
BRADY, DI 8
Idaho Power Company
1 dispatch considers a current forecast of forward market
2 energy prices, available hydro generation, coal and natural
3 gas prices, and any existing hedge transactions . The system
4 load forecast is then analyzed against the resulting
5 monthly dispatch to determine a monthly load and resource
6 balance . Any identified resource deficiency is assumed to
7 be filled with market energy purchases or natural gas to
8 fuel either the Langley Gulch power plant ("Langley
9 Gulch") , Jim Bridger Units 1 and 2, or Valmy Units 1 and 2,
10 based on economics and available generating capacity at
11 each plant . Economically dispatched generation above the
12 system load forecast represents surplus energy sales . The
13 forecast of monthly NPSE and generation for the 2026-2027
14 PCA Year, as determined in the Company' s March 2026
15 Operating Plan, is provided in Exhibit No. 1 .
16 Q. How does the Company' s forecast of system-
17 level NPSE for the 2026-2027 PCA compare to the system-
18 level forecast included in last year' s PCA?
19 A. Table 3 below compares this year' s 2026-2027
20 PCA forecast of NPSE to last year' s PCA forecast by FERC
21 account . As detailed in this table, the PCA forecast on a
22 total system basis for the 2026-2027 PCA year is
23 $649, 935, 889 which is $86, 372, 241 higher than last year' s
24 forecast amount of $563, 563, 648 .
25
BRADY, DI 9
Idaho Power Company
Table 3 PCA Forecast Comparison Expenses(Total System)
Line No. FERC Account 2025-2026 Forecast 2026-2027 Forecast Difference
95%Sharing Accounts
1 Account 501,Steam $ 151,558,050 $ 140,827,611 $ (10,730,438)
2 Account 536,Water for Power $ 0 $ 0 $ 0
3 Account 547,Other Fuel $ 129,974,528 $ 139,451,690 $ 9,477,163
4 Account 555,Purchased Power Non-PURPA $ 103,402,787 $ 135,649,035 $ 32,246,248
5 Account 565,3rd Party Transmission $ 11,925,403 $ 12,180,727 $ 255,324
6 Account 447,Surplus Sales $ (88,732,720) $ (36,004,689) $ 52,728,031
$ 308,128,048 $ 392,104,375 $ 83,976,327
100%Sharing Accounts
7 Account 555,PURPA $ 227,069,067 $ 225,630,980 $ (1,438,087)
8 Account 555,Demand Response Incentives $ 10,411,533 $ 10,654,534 $ 243,001
9 Account 577.4,Energy Storage Rents $ 17,955,000 $ 21,546,000 $ 3,591,000
$ 255,435,600 $ 257,831,514 $ 2,395,914
10 Total PCA Forecast $ 563,563,648 $ 649,935,889 $ 86,372,241
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 $84 . 0 million
6 from last year' s forecast, while the 100 percent sharing
7 accounts have increased approximately $2 . 4 million over
8 last year' s forecast .
9 Q. How does the Company' s generation forecast for
10 the 2026-2027 PCA compare to the forecast included in last
11 year' s PCA?
12 A. Table 4 below compares this year' s 2026-2027
13 PCA generation forecast to last year' s PCA forecast by FERC
14 account . As detailed in this table, the 1, 234, 153 megawatt-
BRADY, DI 10
Idaho Power Company
1 hour ("MWh") (7 percent) increase to load from the prior
2 year is forecast to be met with a 532, 193 MWh (17 percent)
3 increase to natural gas-fired generation, a 51, 674 MWh (1
4 percent) increase to steam power generation, a 641, 137 MWh
5 (33 percent) increase to non-PURPA market purchases, and a
6 1, 281, 521 MWh (89 percent) decrease to surplus sales . These
7 are partially offset by a 1, 205, 849 MWh (16 percent)
8 decrease to hydro generation and a 66, 522 MWh (2 percent)
9 decrease to PURPA generation.
Table 4 PCA Forecast Comparison Generation(Total System-MWh)
Line No. FERC Account 2025-2026 Forecast 2026-2027 Forecast Difference
1 Hydro 7,440,989 6,235,140 (1,205,849)
95%Sharing Accounts
2 Account 501,Steam 3,794,723 3,846,397 51,674
3 Account 547,Other Fuel 3,067,019 3,599,211 532,193
4 Account 555,Purchased Power Non-PURPA 1,924,968 2,566,105 641,137
16,227,698 16,246,852 19,154
100%Sharing Accounts
5 Account 555,PURPA 2,926,917 2,860,395 (66,522)
2,926,917 2,860,395 (66,522)
6 Total Generation 19,154,615 19,107,247 (47,368)
95%Sharing Accounts
7 Less Account 447,Surplus Sales 1,447,006 165,484 (1,281,521)
8 Total Load 17,707,609 18,941,763 1,234,153
10
11 Q. How are the Company' s Clean Energy Your Way
12 ("CEYW") resources accounted for in the PCA forecast?
13 A. Resources procured through the CEYW -
14 Construction Option are paid for by the participating
BRADY, DI 11
Idaho Power Company
1 customer. Accordingly, the cost of the PPA is not included
2 in the forecast of NPSE for the PCA year. However, the
3 participating customer will be credited for the value of
4 the resource' s capacity contribution to the system and for
5 any PPA generation that exceeds their load in a given hour.
6 Both the forecast capacity credit and excess generation
7 credit amounts are included as expenses in the PCA
8 forecast .
9 Q. How are the Company' s marginal-cost priced
10 customers accounted for in the PCA forecast?
11 A. All forecast marginal-cost priced energy sales
12 are included in the PCA forecast as an offset to NPSE,
13 included in FERC Account 447, Surplus Sales .
14 Q. Were any changes made to the Idaho
15 jurisdictional sales and system-level sales to account for
16 modifications related to CEYW or marginal cost-priced
17 customers?
18 A. Yes . All load forecasted to be met with CEYW
19 resources or priced at a marginal cost-based rate are
20 excluded from total forecast sales and are not used in the
21 derivation of the PCA rate.
22 Q. What is the Company' s forecast of system-level
23 firm sales and Idaho jurisdictional firm sales for the
24 2026-2027 PCA Year?
BRADY, DI 12
Idaho Power Company
1 A. For the 2026-2027 PCA Year, Idaho Power has
2 forecast system-level firm sales to be 16, 727, 802 MWh and
3 Idaho jurisdictional firm sales to be 16, 046, 892 MWh, or
4 95 . 93 percent of the system level .
5 Q. What is the Company' s determination of the
6 2026-2027 PCA forecast component to be collected from Idaho
7 customers?
8 A. As shown in Table 1, the 2026-2027 PCA
9 forecast component to be collected from Idaho customers is
10 $165, 106, 470 .
11 B. Balancing Adjustment.
12 Q. What is this year' s quantification of the
13 Balancing Adjustment, excluding amounts related to the
14 Boardman Balancing Account?
15 A. The Balancing Adjustment is detailed in the
16 PCA deferral report, attached hereto as Exhibit No. 2 . This
17 report compares actual NPSE amounts to actual power cost
18 collections monthly, with the differences accumulated as a
19 deferral balance . The balance at the end of March 2026,
20 with interest applied, is negative $75, 058, 413 as shown in
21 row 104 of Exhibit No. 2 .
22 Q. To what factors do you attribute the
23 accumulation of the approximate negative $75 million
24 deferral balance?
BRADY, DI 13
Idaho Power Company
1 A. Actual power supply expenses in the 2025-2026
2 PCA Year were just 1 . 1 percent lower than forecast
3 expenses, with load coming in 2 . 6 percent lower than
4 forecast . As a result, the variance between forecast and
5 actual power supply expenses for the 2025-2026 PCA Year had
6 a relatively small impact on this year' s deferral balance.
7 See Table 5 below for the variance in actual versus
8 forecast NPSE for the 2025-2026 PCA Year.
9 However, this year' s deferral balance does include
10 increased benefits associated with REC sales and the SBA.
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
BRADY, DI 14
Idaho Power Company
Table
5 2025-2026 Forecast to Actual Expenses
Line 2025-2026 2025-2026
No. FERC Account Forecast Actuals Difference
95%Sharing Accounts
1 Account 501,Steam $ 151,558,050 $ 101,221,778 $ (50,336,272)
2 Account 536,Water for Power $ 0 $ 0 $ 0
3 Account 547,Other Fuel $ 129,974,528 $ 145,225,588 $ 15,251,061
4 Account 555,Purchased Power Non-PURPA $ 103,402,787 $ 144,262,066 $ 40,859,279
5 Account 565,3rd Party Transmission $ 11,925,403 $ 12,101,956 $ 176,553
6 Account 447,Surplus Sales $ (88,732,720) $ (88,216,241) $ 516,479
$ 308,128,048 $ 314,595,148 $ 6,467,099
100%Sharing Accounts
7 Account 555,PURPA $ 227,069,067 $ 215,242,160 $ (11,826,908)
8 Account 555,Demand Response Incentives $ 10,411,533 $ 8,941,045 $ (1,470,488)
9 Account 577.4,Energy Storage Rents $ 17,955,000 $ 18,707,952 $ 752,952
$ 255,435,600 $ 242,891,156 $ (12,544,444)
9 Total $ 563,563,648 $ 557,486,304 $ (6,077,345)
1
2 Q. Please explain the changes in actual versus
3 forecast generation and expense for the 2025-2026 PCA Year.
4 A. Table 6 below details the changes in actual
5 versus forecast generation for the 2025-2026 PCA Year.
6
7
8
9
10
11
12
13
14
BRADY, DI 15
Idaho Power Company
Table
6 2025-2026 Forecast to Actual Generation
Line 2025-2026 2025-2026
No. FERC Account Forecast Actuals Difference
1 Hydro 7,440,989 6,457,120 (983,869)
95%Sharing Accounts
2 Account 501,Steam 3,794,723 2,657,274 (1,137,449)
3 Account 547,Other Fuel 3,067,019 3,686,371 619,352
4 Account 555,Purchased Power Non-PURPA 1,924,968 3,771,175 1,846,207
95%Sharing Accounts 16,227,968 16,571,940 344,242
100%Sharing Accounts
5 Account 555,PURPA 2,926,917 2,727,746 (199,171)
100%Accounts 2,926,917 2,727,746 (199,171)
6 Total Generation 19,154,615 19,299,687 145,072
95%Sharing Accounts
7 Account 447,Surplus Sales 1,447,006 2,057,951 610,945
8 Total Load 17,707,609 17,241,736 (465,874)
1
2 Actual steam power generation for the 2025-2026 PCA
3 year totaled 2, 657, 274 MWh, which is 30 percent lower than
4 forecast . Actual steam fuel expense totaled $101, 221, 778,
5 which is 33 percent lower than forecast. The actual per-
6 unit cost of steam power generation was $38 . 09, a 5 percent
7 decrease from forecast.
8 Actual natural gas-fired generation for the 2025-
9 2026 PCA year totaled 3, 686, 371 MWh, which is 20 percent
10 higher than forecast. Actual natural gas fuel expense
11 totaled $145, 225, 558, which is 12 percent higher than
12 forecast . The actual per-unit cost of natural gas
13 generation was $39 . 40, a 7 percent decrease from forecast .
BRADY, DI 16
Idaho Power Company
1 Actual non-PURPA purchased power totaled 3, 771, 175
2 MWh for the 2025-2026 PCA Year. This included 2, 109, 433 MWh
3 in market purchases and 1, 661, 742 MWh in PPA generation.
4 PPA generation was 0 . 4 percent higher than forecast,
5 whereas market purchase volumes were 680 percent higher
6 than forecast . Actual non-PURPA purchased power expense was
7 $144, 262, 066, which is 40 percent higher than forecast.
8 This includes $71, 494, 938 in market purchase expenses (297
9 percent higher than forecast) and $72, 767, 128 in PPA
10 expenses (9 percent higher than forecast) .
11 Surplus sales totaled 2, 057, 951 MWh for the 2025-
12 2026 PCA Year, which is 42 percent higher than forecast.
13 Actual surplus sales revenue was $88, 216, 241, which is 1
14 percent lower 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 17
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.4
6 Q. Please explain how the tracking of wheeling
7 revenues are incorporated into the Balancing Adjustment.
8 A. In accordance with Order No. 36502, the
9 wheeling revenue deferral was calculated by taking the
10 difference between actual Idaho jurisdictional wheeling
11 revenues and base-level sales-adjusted wheeling revenues,
12 multiplied by the sharing percentage of 95 percent. 5 See
13 Exhibit No . 2, Line 79 .
14 Q. How much is this year' s wheeling revenue
15 deferral, as shown on line 79 of Exhibit No. 2?
16 A. The wheeling revenue deferral for the 2025-
17 2026 PCA year is $576, 370 .
18 Q. Did Idaho Power include its actual costs of
19 EIM participation in this year' s Balancing Adjustment?
4 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) .
5 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 18
Idaho Power Company
1 A. No. Because EIM costs were included in base
2 rates resulting from the Company' s 2023 General Rate Case,
3 which went into effect on January 1, 2024, EIM costs are no
4 longer included in the PCA as of that date.
5 C. Boardman Balancing Account Credit
6 Q. What is the Boardman Balancing Account and why
7 was it established?
8 A. The Boardman Balancing Account was established
9 pursuant to Commission Order No. 32457 in Case No .
10 IPC-E-11-18 in connection with the planned early retirement
11 of the Boardman Power Plant. Idaho Power, as a minority
12 owner of Boardman, developed a regulatory and accounting
13 plan to respond to the plant' s early closure, which
14 included establishment of a balancing account to track, on
15 a cumulative basis, both customer revenues and the actual
16 costs and credits associated with the plant' s accelerated
17 depreciation, decommissioning, asset disposition, and
18 related activities . The balancing account was designed to
19 reconcile amounts collected from customers with actual
20 Boardman-related costs and credits over time .
21 Q. What Boardman-related activities have occurred
22 since the plant ceased operations, and what was the impact
23 on the balancing account?
24 A. Boardman ceased operations in October 2020,
25 with decommissioning, demolition, and site restoration
BRADY, DI 19
Idaho Power Company
1 completed in 2023 and remaining asset disposition and
2 closure-related transactions finalized during 2025 . With all
3 Boardman-related activities completed and recorded, the
4 Boardman Balancing Account now reflects a final Idaho
5 jurisdictional over-collection, as summarized below in Table
6 7 and further described in the Company' s 2024 and 2025
7 Boardman Power Plant Annual Review Compliance Filing in
8 Case No . I PC-E-12-0 9 .
Table 7
Idaho Jurisdictional Boardman Balancing Account
Line No.
1 Decommissioning Costs $ 3,108,402
2 Materials and Supplies Write-off $ 920,138
3 Total Decommissioning Expenditures $ 4,028,540
4 Collection of Costs $ (5,116,957)
5 Load Variance True-Up $ (3,950)
6 Asset Purchase Agreement Proceeds $ (2,186,840)
7 Under(Over)Collection $ (3,279,207)
9
10 Q. What is Idaho Power requesting in this case
11 with respect to the Boardman Balancing Account?
12 A. Idaho Power proposes that the net balance of
13 $3, 279, 207 be returned to customers as a one-time giveback
14 amortized over a 12-month period and included as a credit
15 in this year' s PCA Balancing Adjustment.
16 D. PCA Rate Determination.
17 Q. How is the rate for the forecast portion of
18 the PCA for April 2026 through March 2027 determined?
BRADY, DI 20
Idaho Power Company
1 A. The rate for the forecast portion of the PCA
2 is equal to the sum of (1) 95 percent of the difference
3 between the non-PURPA expenses quantified in the Operating
4 Plan and those quantified in the Company' s last approved
5 update of NPSE, divided by the Company' s forecast of system
6 firm sales for June 1, 2026, through May 31, 2027 ("System-
7 level Sales Forecast") ; (2) 100 percent of the difference
8 between PURPA-related expenses quantified in the Operating
9 Plan and those quantified in the Company' s last approved
10 update of NPSE, divided by the Company' s System-level Sales
11 Forecast; (3) 100 percent of the difference between the
12 Idaho jurisdictional demand response incentive payments
13 quantified in the Operating Plan and those quantified in
14 the Company' s last approved update of NPSE, divided by the
15 forecast of Idaho jurisdictional firm sales for June 1,
16 2026, through May 31, 2027 ("Idaho Jurisdictional Sales
17 Forecast") ; and (4) 100 percent of the difference between
18 the Energy Storage Rent expenses quantified in the
19 Operating Plan and those quantified in the Company' s last
20 approved update of NPSE, divided by the System-level Sales
21 Forecast .
22 Q. What is the rate for the forecast portion of
23 the PCA for April 2026 through March 2027?
24 A. The rate for non-PURPA expenses is $0 . 0103 per
25 kilowatt-hour ("kWh") , which is calculated by multiplying
BRADY, DI 21
Idaho Power Company
1 $180, 871, 953 from Table 2 by 95 percent and then dividing
2 it by the System-level Sales Forecast of 16, 727, 802, 226 kWh
3 ( ($180, 871, 953 * 0 . 95) / 16, 727, 802, 226) = 0 . 0103 $/kWh) .
4 The rate for PURPA expenses is negative $0 . 0001 per kWh,
5 which is calculated by dividing negative $1, 088, 465 from
6 Table 2 by the 16, 727, 802, 226 kWh. The rate for demand
7 response incentive payments is $0 . 0001 per kWh, which is
8 calculated by dividing the $1, 311, 776 from Table 2 by the
9 Idaho Jurisdictional Sales Forecast of 16, 046, 891, 871 kWh.
10 The rate for Energy Storage Rents is $0 . 0000 per kWh as
11 there is no difference between base level and forecast
12 expenses .
13 The total forecast portion of the PCA rate is
14 $0 . 0103 per kWh, which is calculated by adding the non-
15 PURPA expense of $0 . 0103 per kWh to the PURPA expense of
16 negative $0 . 0001 per kWh to the demand response incentive
17 payment of $0 . 0001 per kWh to the Energy Storage Rents
18 expense of $0 . 0000 per kwh (0 . 0103 - 0 . 0001 + 0 . 0001 +
19 0 . 0000 = 0 . 0103 $/kWh) .
20 Q. How did you compute this year' s Balancing
21 Adjustment rate?
22 A. As shown in Exhibit No. 2, this year' s
23 Balancing Adjustment of the PCA is approximately negative
24 $75 million, which, when added to the Boardman Balancing
25 Account amount of negative $3, 279, 207 and divided by the
BRADY, DI 22
Idaho Power Company
1 Idaho Jurisdictional Sales Forecast of 16, 046, 891, 871 kWh,
2 results in a rate of negative $0 . 0049 per kWh (-$78, 337, 620
3 / 16, 046, 891, 871 = $0 . 0049/kWh.
4 Q. What is the resulting PCA rate when you
5 combine all the PCA components described previously?
6 A. The uniform PCA rate comprises (1) the $0 . 0103
7 per kWh for the 2026-2027 projected power cost of serving
8 firm loads under the current PCA methodology and 95 percent
9 sharing, and (2) the negative $0 . 0049 per kWh for the 2025-
10 2026 Balancing Adjustment of the PCA. The sum of these two
11 components is a $0 . 0054 per kWh charge .
12 III . ADDITIONAL PCA RATE ADJUSTMENTS
13 A. Revenue Sharing.
14 Q. When was the revenue sharing mechanism
15 originally established?
16 A. The revenue sharing mechanism was originally
17 established in Case No. IPC-E-09-30 and approved in Order
18 No . 30978, effective for the years 2009-2011 . Since then,
19 the revenue sharing mechanism has been modified and
20 extended five times . 6 Order No . 34071 in Case No. GNR-U-18-
21 01 extended the revenue sharing mechanism indefinitely,
22 with modifications .
6 Order Nos. 32424, 33149, 34071, 36042, and 36892.
BRADY, DI 23
Idaho Power Company
1 The mechanism was most recently modified in the
2 Company' s 2025 General Rate Case, effective January 1, 2026
3 (Order No . 36892) .
4 Q. What is the purpose of the Revenue Sharing
5 Mechanism?
6 A. The Revenue Sharing Mechanism includes
7 provisions for the accelerated amortization of Accumulated
8 Deferred Investment Tax Credits ("ADITC") to help achieve a
9 minimum specified percent Idaho jurisdictional return on
10 year-end equity ("Idaho ROE") and also provides for the
11 potential sharing between Idaho Power and its Idaho
12 customers of Idaho jurisdictional earnings in excess of a
13 maximum specified Idaho ROE.
14 Q. Can you explain the modifications related to
15 the Revenue Sharing Mechanism from the 2023 General Rate
16 Case?
17 A. The Revenue Sharing Mechanism was modified to
18 include an additional amount of Investment Tax Credits
19 ("ITC") equal to the incremental ITC generated from the
20 Company' s investment in 2023 battery storage projects,
21 including augmentation costs . In addition, the ADITC cap
22 previously set at $25 million was removed.
23 Effective January 1, 2024, potential revenue sharing
24 between Idaho Power and customers will occur if earnings
25 are in excess of a 9 . 6 percent Idaho ROE. In addition, all
BRADY, DI 24
Idaho Power Company
1 revenue sharing will be implemented through the PCA, rather
2 than a portion offsetting customer-funded pension
3 obligations . Lastly, the minimum-specified Idaho ROE is
4 9 . 12 percent .'
5 Q. What have been the results of the revenue
6 sharing mechanism since it was implemented through 2025?
7 A. The Company' s earnings in each year from 2011
8 through 2015, as well as 2018 and 2021, resulted in revenue
9 sharing with customers totaling $126 . 7 million, either as a
10 direct rate offset in the PCA or as an offset to amounts
11 that would have otherwise been collected in rates . The
12 Company' s earnings in 2016, 2017, 2019, 2020, and 2022-2025
13 were below the revenue sharing threshold. These amounts are
14 detailed in Table 8 below.
15
16
17
18
19
20
21
22
23
' In the Matter of the Application of Idaho Power Company for Authority
to Increase its Rates and Charges for Electric Service in the State of
Idaho and for Associated Regulatory Accounting Treatment, Case No. IPC-
E-23-11, Order No. 36042 (December 28, 2023) .
BRADY, DI 25
Idaho Power Company
Table 8 2009-2025 Revenue Sharing and ADITC($Millions)
Line Revenue Sharing/ADITC 2009-2011 2012-2014 2015-2019 2020-2023 2024 2025
No. Component
1 Available ADITC For Use $45.0 $45.0 $45.0 $45.0 $107.0 $167.7
Total
ADITC
2 ADITC Used: $0.0 $0.0 $0.0 $0.0 $29.8 $40.3
3 Customer Benefits
4 Reduction to Rates: $27.1 $22.8 $8.2 $0.6 $0.0 $0.0
5 Offset to Pension $20.3 $47.8 $0.0 $0.0 $0.0 $0.0 Total
Balancing Account: Sharing
6 Total Sharing $47.4 $70.6 $8.2 $0.6 $0.0 $0. $126.7
1
2 Q. Did the Company' s year-end 2025 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 2025 financial
6 results yielded an actual Idaho ROE of 7 . 98 percent,
7 falling below the minimum specified Idaho ROE of 9 . 12
8 percent . As a result, $40, 336, 413 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 2025 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 2025 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 26
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 2025 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 2026 through May 2027 test year results in a PCA increase
14 of $51 . 6 million, or 3 . 02 percent.
15 Q. What is the combined revenue impact of each of
16 the Company' s filings to be effective June 1, 2026?
17 A. If the proposed PCA and Fixed Cost Adjustment
18 ("FCA") filings are approved as filed, the combined impact
19 is an overall increase in current billed revenue of $56 . 7
20 million, or 3 . 31 percent.
21 Q. Have you prepared a revised Schedule 55 that
22 includes the proposed PCA rates?
23 A. Yes . Attachment 1 to the Application is a
24 revised Schedule 55 and includes the proposed PCA rates in
25 clean and legislative formats .
BRADY, DI 27
Idaho Power Company
1 Q. Please summarize the Company' s request in this
2 filing.
3 A. If approved, the 2026-2027 PCA will result in
4 an increase in total billed revenue of approximately $51 . 6
5 million, or 3 . 02 percent. The Commission should approve the
6 Company' s computation of the PCA rates, the calculation of
7 which follows the methodology that was approved in Order
8 No . 30715 .
9 Q. Does this conclude your testimony?
10 A. Yes, it does .
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
BRADY, DI 28
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 . 1-4 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 2026, at Boise, Idaho.
17
18 Signed:
19 Jessica Brady
BRADY, DI 29
Idaho Power Company
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-26-10
IDAHO POWER COMPANY
BRADY, DI
TESTIMONY
EXHIBIT NO. 1
PCA FORECAST
IDAHO POWER PCA FORECAST
APRIL 1,2026-MARCH 31,2027
Line No. FERC Account April May June July August September October November December January February March Annual
96 Sharina Accounts
1 Hydroelectric Generation(MWh) 585,637 599,336 707,339 600,532 491,382 474,467 416,334 367,154 413,172 541,841 454,462 583,483 6,235,140
Account 536,Water for Power
2 Total Expense $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
Account 501,Steam
Jim Bridger 3&4
3 Energy(MWh) 31,200 32,240 31,200 148,038 239,340 231,619 239,340 231,941 239,340 239,340 216,178 239,340 2,119,115
4 Total Expense $ 1,073,616 $ 1,112,446 $ 1,077,830 $ 5,227,748 $ 8,505,524 $ 8,265,924 $ 8,570,171 $ 8,327,245 $ 8,614,249 $ 8,185,225 $ 7,166,447 $ 7,772,363 $ 73,898,788
Jim Bridger 1&2
5 Energy(MWh) - - 65,869 217,049 228,826 101,229 - 115,344 205,712 94,576 63,552 18,660 1,110,816
6 Total Expense $ 136,701 $ 136,701 $ 1,037,126 $ 6,251,640 $ 7,058,370 $ 2,797,026 $ 141,807 $ 5,701,062 $ 12,340,350 $ 5,776,456 $ 3,580,527 $ 947,266 $ 45,905,032
Valmy
7 Energy(MWh) 52,832 43,688 - 110,568 16,377 17,894 65,847 70,138 78,783 67,445 49,019 43,874 616,465
8 Total Expense $ 793,139 $ 694,597 $ 136,701 $ 2,478,071 $ 525,167 $ 533,678 $ 1,672,011 $ 2,478,432 $ 4,071,640 $ 3,716,096 $ 2,506,593 $ 1,417,666 $ 21,023,791
Account 547,Other Fuel
Langley Gulch
9 Energy(MWh) - 140,310 207,136 210,704 211,120 208,240 62,577 201,302 226,896 227,040 202,080 219,513 2,116,918
10 Total Expense $ 493,883 $ 1,971,403 $ 3,193,751 $ 5,410,314 $ 5,531,909 $ 5,229,822 $ 1,808,302 $ 6,966,612 $ 10,104,206 $ 10,185,660 $ 8,051,083 $ 5,831,733 $ 64,778,679
Danskin
11 Energy(MWh) - 11,008 6,992 120,680 121,096 49,920 121,488 14,804 137,288 135,696 107,712 9,019 835,703
12 Total Expense $ 248,247 $ 564,507 $ 459,475 $ 4,785,970 $ 4,901,290 $ 2,036,881 $ 4,242,298 $ 987,671 $ 9,041,970 $ 9,004,636 $ 6,405,542 $ 640,667 $ 43,319,155
Bennett Mountain
13 Energy(MWh) 47,424 - - 85,320 106,536 - 78,408 132,766 79,320 77,072 39,744 - 646,590
14 Total Expense $ 1,139,990.02 $ 122,270.98 $ 122,270.98 $ 3,307,406.98 $ 4,198,196.82 $ 122,270.98 $ 2,691,333.16 $ 6,726,265.18 $ 5,260,475.32 $ 5,143,439.80 $ 2,393,665.72 $ 126,270.52 $ 31,353,856
Account 555,Purchased Power Non-PURPA
15 Energy(MWh) 296,428 314,384 389,238 310,114 236,358 177,100 144,803 113,842 97,389 166,012 139,113 181,326 2,566,105
16 Total Expense $ 9,551,821 $ 8,432,436 $ 16,882,855 $ 22,630,478 $ 17,319,687 $ 11,674,759 $ 6,442,920 $ 7,603,383 $ 8,098,575 $ 11,198,467 $ 8,906,919 $ 6,906,737 $ 135,649,035
Account 565,3rd Party Transmission
17 Total Expense $ 779,996 $ 718,332 $ 967,345 $ 1,307,772 $ 1,189,415 $ 976,466 $ 1,406,345 $ 1,011,482 $ 908,050 $ 1,237,473 $ 845,430 $ 832,621 $ 12,180,727
Account 447,Surplus Sales
18 Energy(MWh) (36,313) (13,056) (2,268) (2,560) (2,260) (1,843) (1,568) (1,358) (1,332) (36,506) (1,531) (64,889) (165,484)
19 Total Expense $ (1,447,839) $ (886,411) $ (805,731) $ (1,140,382) $ (1,480,517) $ (1,829,545) $ (2,058,195) $ (3,368,292) $ (5,813,720) $ (5,554,409) $ (5,141,513) $ (6,478,135) $ (36,004,689)
100%Sharing Accounts
Account 555,PURPA
20 Energy(MWh) 282,399 309,766 290,979 275,326 264,354 224,560 209,685 174,268 182,349 187,509 216,026 243,173 2,860,395
21 Total Expense $ 16,578,610 $ 18,465,700 $ 22,474,218 $ 25,140,277 $ 24,679,150 $ 17,932,305 $ 16,507,255 $ 16,688,984 $ 17,679,887 $ 15,812,056 $ 18,361,423 $ 15,311,115 $ 225,630,980
Account 555,Demand Response Incentives
22 Total Expense $ 19,000 $ 39,000 $ 309,468 $ 3,086,657 $ 4,676,950 $ 1,291,208 $ 198,487 $ 987,764 $ 14,000 $ 9,000 $ 9,000 $ 14,000 $ 10,654,534
Account 577.4,Energy Storage Rents
23 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 $ 1,795,500 $ 1,795,500 $ 21,546,000
95%Sharing Accounts $ 12,769,554 $ 12,866,283 $ 23,071,623 $ 50,259,018 $ 47,749,042 $ 29,807,281 $ 24,916,993 $ 36,433,860 $ 52,625,795 $ 48,893,044 $ 34,714,694 $ 17,997,189 $ 392,104,375
100%Sharing Accounts $ 18,393,110 $ 20,300,200 $ 24,579,186 $ 30,022,434 $ 31,151,600 $ 21,019,013 $ 18,501,242 $ 19,472,248 $ 19,489,387 $ 17,616,556 $ 20,165,923 $ 17,120,615 $ 257,831,514
24 Total Net Power Supply Expense $ 31,162,665 $ 33,166,483 $ 47,650,809 $ 80,281,451 $ 78,900,642 $ 50,826,294 $ 43,418,235 $ 55,906,107 $ 72,115,182 $ 66,509,600 $ 54,880,617 $ 35,117,804 $ 649,935,889
25 Total Generation(MWh) 1,295,920 1,450,732 1,698,753 2,078,331 1,915,389 1,485,029 1,338,482 1,421,560 1,660,249 1,736,531 1,487,885 1,538,388 19,107,248
26 Total Load(MWh) 1,259,607 1,437,676 1,696,484 2,075,771 1,913,129 1,483,185 1,336,914 1,420,201 1,658,917 1,700,025 1,486,355 1,473,498 18,941,763
Exhibit No. 1
Case No.IPC-E-26-10
J.Brady,IPC
Page 1 of 1
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-26-10
IDAHO POWER COMPANY
BRADY, DI
TESTIMONY
EXHIBIT NO. 2
BALANCING ADJUSTMENT
Power Cost Adjustment
April 2025 thru March 2026
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-Steam $ 4,185,189.51 5,079,870.13 7,393,303.75 12,948,986.00 12,469,922.08 11,677,955.31 12,442,290.10 12,110,829.68 6,120,652.98 8,820,091.36 4,622,863.37 3,349,823.58 101,221,777.85
Fuel Expense-Gas $ 4,171,864.78 5,033,712.69 8,758,307.31 12,555,793.34 14,337,608.49 10,680,723.95 7,668,317.32 13,768,782.83 21,651,445.71 20,099,279.17 16,547,761.71 9,951,991.09 145,225,588.39
Non-Firm Purchases $ 5,024,525.17 9,140,929.96 14,361,687.80 17,976,943.09 10,895,348.01 10,675,570.30 16,084,450.58 18,695,786.80 18,807,296.43 8,388,954.11 7,089,137.09 7,121,436.81 144,262,066.15
Third Party Transmission $ 906,827.13 888,490.62 162,163.74 1,242,859.85 1,252,117.18 1,107,583.76 934,454.29 1,001,700.32 1,196,143.89 1,887,949.86 2,497,850.46 (976,184.90) 12,101,956.20
Surplus Sales&Transmission Losses $ (9,199,561.59) (7,136,761.59) (4,424,969.98) (4,811,109.30) (736,555.23) (8,109,961.57) (15,074,008.68) (17,500,833.78) (12,410,460.86) (2,727,638.85) (4,432,396.77) (1,651,982.88) (88,216,241.08)
Water for Power(Leases) $
Total Actual NPSE $ 5,088,845.00 13,006,241.81 26,250,492.62 39,913,472.98 38,218,440.53 26,031,871.75 22,055,503.61 28,076,265.85 35,365,078.15 36,468,635.65 26,325,215.86 17,795,083.70 314,595,147.51
Idaho Allocation 95.6% 95.9% 96.1% 96.1% 96.0% 95.9% 96.1% 95.2% 95.4% 95.6% 95.5% 96.2
Net Idaho Jurisdictional Actual Non-QF $ 4,864,935.82 12,472,985.90 25,226,723.41 38,356,847.53 36,689,702.91 24,964,565.01 21,195,338.97 26,728,605.09 33,738,284.56 34,864,015.68 25,140,581.15 17,118,870.52 301,361,456.55
Base Non-QF
Fuel Expense-Steam $ 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 8,708,206.93 8,312,454.26 7,916,325.64 74,954,228.82
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 4,074,939.11 3,889,749.66 3,704,384.29 103,007,182.06
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 11,801,431.44 11,265,104.27 10,728,267.60 109,721,822.32
Third Party Transmission $ 676,879.00 717,209.00 876,732.00 1,119,424.00 1,197,292.00 1,042,404.00 729,201.00 688,863.00 786,405.00 996,321.87 951,043.08 905,721.29 10,687,495.24
Surplus Sales&Transmission Losses $ (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) (6,812,498.23) (6,502,897.83) (6,193,003.31) (45,986,364.37)
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 18,768,401.12 17,915,453.45 17,061,695.50 252,384,364.08
Idaho Allocation 1 95.57% 95.57% 95.57% 95.57% 95.57% 95.57% 95.57% 95.57%- 95.83% 95.83
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 17,985,758.80 17,168,379.04 16,350,222.80 241,343,475.18
Idaho Jurisdiction Change From Base $ (11,536,825.81) (4,906,032.50) 3,982,234.92 11,231,564.22 7,677,570.57 (294,397.72) 3,525,746.68 10,036,457.84 14,682,556.46 16,878,256.88 7,972,202.11 768,647.72 60,017,981.37
Sharing Percentage 1 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) $ (10,959,984.52) (4,660,730.88) 3,783,123.17 10,669,986.01 7,293,692.04 (279,677.83) 3,349,459.35 9,534,634.95 13,948,428.64 16,034,344.04 7,573,592.00 730,215.33 57,017,082.30
Idaho Jurisdictional Qualifying Facility NPSE
Actual OF(Includes Net Metering,Raft River 100%&Liquidated Damages) $ 15,271,159.83 19,728,567.80 25,896,598.28 29,675,207.47 25,830,625.92 19,758,505.60 19,793,108.70 16,045,670.56 18,716,957.07 11,820,456.43 15,264,281.99 16,148,971.47 233,950,111.12
Idaho Allocation 95.6% 95.9% 96.1% 96.1% 96.0% 95.9% 96.1% 95.2% 95.4% 95.6% 95.5% 96.2
Idaho Jurisdictional Actual OF $ 14,599,228.80 18,919,696.52 24,886,630.95 28,517,874.38 24,797,400.88 18,948,406.87 19,021,177.46 15,275,478.37 17,855,977.04 11,300,356.35 14,577,389.30 15,535,310.55 224,234,927.47
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 18,279,879.39 17,449,133.05 16,617,597.52 216,046,921.96
Idaho Allocation 95.57% 95.57% 95.57% 95.57% 95.57% 95.57% 95.57% 95.57% 95.57% 95.83% 95.83% 95.83
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 17,517,608.42 16,721,504.20 15,924,643.70 206,612,144.51
Idaho Jurisdiction Change From Base $ 1,082,366.13 4,597,466.41 7,378,827.20 6,163,646.16 888,200.98 (1,867,766.51) 4,459,482.38 1,519,306.51 2,151,953.82 (6,217,252.07) (2,144,114.90) (389,333.15) 17,622,782.96
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) $ 1,082,366.13 4,597,466.41 7,378,827.20 6,163,646.16 888,200.98 (1,867,766.51) 4,459,482.38 1,519,306.51 2,151,953.82 (6,217,252.07) (2,144,114.90) (389,333.15) 17,622,782.96
Idaho Revenue Adjustment(SBAR)
Actual Idaho Jurisdictional Billing Month Sales MWh 1,041,992 1,154,889 1,398,929 1,671,616 1,671,846 1,500,405 1,180,713 1,028,839 1,118,516 1,210,052 1,244,813 1,091,459 15,314,069
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 1,311,041 1,235,222 1,183,031 15,056,824
Sales Change MWh 24,497 62,849 142,794 127,263 41,747 54,524 55,757 (21,044) (48,172) (100,989) 9,591 (91,572) 257,245
•of Prior Period Billings at Old Rate-effective thru 12/31/25 $30.90 1 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 58.605% 0.157% 0.000
•of Current Period Billings at New Rate-effective 01/01/26 $27.82 1 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 41.400% 99.800% 100.000
Sales Adjustment Prior To Sharing@ $ (756,959.52) (1,942,037.56) (4,412,343.19) (3,932,441.41) (1,289,992.71) (1,684,784.77) (1,722,880.95) 650,261.36 1,488,509.45 2,991,935.11 (266,747.00) 2,547,541.91 (8,329,939.28)
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) $ (719,111.54) (1,844,935.68) (4,191,726.03) (3,735,819.34) (1,225,493.07) (1,600,545.53) (1,636,736.90) 617,748.29 1,414,083.98 2,842,338.35 (253,409.65) 2,420,164.81 (7,913,442.31)
Idaho Jurisdcitional Demand Response Incentive Payments
Idaho Actual Demand Response $ - 1,393.75 268,711.74 2,533,952.43 2,565,639.99 1,857,990.03 1,683,158.38 25,873.69 - 4,161.83 - 163.29 8,941,045.13
Idaho Base Demand Response $ 675,353.00 715,592.00 874,755.00 1,116,901.00 1,194,593.00 1,040,054.00 727,557.00 687,310.00 784,632.00 753,285.61 719,051.83 684,785.54 9,973,869.98
Change From Base $ (675,353.00) (714,198.25) (606,043.26) 1,417,051.43 1,371,046.99 817,936.03 955,601.38 (661,436.31) (784,632.00) (749,123.78) (719,051.83) (684,622.25) (1,032,824.85)
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) (714,198.25) (606,043.26) 1,417,051.43 1,371,046.99 817,936.03 955,601.38 (661,436.31) (784,632.00) (749,123.78) (719,051.83) (684,622.25) (1,032,824.85)
Idaho Miscellaneous Revenue
System Emission Allowance Sales Credit $ - - - - -
System Renewable Energy Credit Sales $ 502.69 (24,886.92) (9,439,816.33) 50,792.82 837.21 112.23 125.01 (17,170.11) (24,346,168.81) (6,267,604.26) (8,848,382.00) (48,891,658.47)
Revenue Subtotal $ 502.69 (24,886.92) 0.00 (9,439,816.33) 50,792.82 837.21 112.23 125.01 (17,170.11) (24,346,168.81) (6,267,604.26) (8,848,382.00) (48,891,658.47)
Idaho Allocation 95.6% 95.9% 96.1% 96.1% 96.0% 95.9% 96.1% 95.2% 95.4% 95.6% 95.5% 96.2
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) $ 456.54 (22,673.23) 0.00 (8,618,080.32) 46,323.05 762.74 102.46 113.06 (15,561.27) (22,111,190.51) (5,686,283.96) (8,086,536.31) (44,492,567.75)
xii o.
Idaho PTP Wheeling Revenues Case No.IPC-E-26-10
J.Brady,IPC
Page 1 of 2
Actual PTP Revenue Booked $ (3,717,491.44) (3,697,939.82) (4,224,636.74) (4,237,448.38) (4,296,468.51) (4,012,888.78) (4,265,349.50) (4,177,519.48) (4,502,524.42) (4,324,917.60) (4,040,473.68) (4,380,435.38) (49,878,093.73)
Idaho Allocation 95.6% 95.9% 96.1% 96.1% 96.0% 95.9% 96.1% 95.2% 95.4% 95.6% 95.5% 96.2
ID PTP Revenue $ (3,553,921.82) (3,546,324.29) (4,059,875.91) (4,072,187.89) (4,124,609.77) (3,848,360.34) (4,099,000.87) (3,976,998.54) (4,295,408.30) (4,134,621.23) (3,858,652.36) (4,213,978.84) (47,783,940.16)
•of Prior Period Billings at Old Rate-effective through 12/31/25 $ 3.11 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 58.605% 0.157% 0.000
•of Current Period Billings at New Rate-effective 01/01/26 $ 3.381 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 41.400% 99.800% 100.000
OATT Revenue Credited in Base Rates $ (3,240,595.34) (3,591,705.14) (4,350,670.05) (5,198,727.24) (5,199,442.11) (4,666,258.86) (3,672,016.39) (3,199,689.11) (3,478,585.30) (3,898,695.61) (4,205,129.45) (3,689,130.91) (48,390,645.52)
OATT Revenue Difference (313,326.48) 45,380.85 290,794.14 1,126,539.35 1,074,832.34 817,898.52 (426,984.48) (777,309.43) (816,823.00) (235,925.62) 346,477.09 (524,847.93) 606,705.36
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) $ (297,660.15) 43,111.81 276,254.44 1,070,212.38 1,021,090.72 777,003.60 (405,635.26) (738,443.96) (775,981.85) (224,129.34) 329,153.24 (498,605.53) 576,370.10
TOTAL DEFERRAL(Sum of 1-6) $ (11,569,286.54) (2,601,959.82) 6,640,435.52 6,966,996.32 9,394,860.71 (2,152,287.50) 6,722,273.41 10,271,922.54 15,938,291.32 (10,425,013.31) (900,115.10) (6,508,717.10) 21,777,400.45
PCA Forecasted Revenues
Actual Idaho Jurisdictional Billing Month Sales MWh 1,041,992 1,154,889 1,398,929 1,671,616 1,671,846 1,500,405 1,180,713 1,028,839 1,118,516 1,210,052 1,244,813 1,091,459 15,314,069
•of Prior Period Billings at Old Rate 0.000% 0.000% 55.399% 0.3101% 0.000% 0.000% 0.000% 0.000% 0.000% 58.605% 0.157% 0.000
•of Current Period Billings at New Rate 100.000% 100.000% 44.600% 99.700% 100.000% 100.000% 100.000% 100.000% 100.000% 41.400% 99.800% 100.000
Forecast Rate Revenues(7) (1,564,030.09) (1,733,488.58) (3,911,782.01) (7,837,195.92) (7,858,311.56) (7,052,467.60) (5,549,786.82) (4,835,919.55) (5,257,438.44) (6,087,374.53) (6,895,347.54) (6,048,864.98) (64,632,007.62)
PCA Balancing Account Balance
Monthly Interest Rate 5%for 2025,4%for 2026 % 0.4167% 0.4167% 0.4167% 0.4167% 0.4167% 0.4167% 0.4167% 0.4167%- 0.3333% 0.3333% 4.7500
Beginning Balance $ (52,045,993.74) (71,591,928.94) (83,092,625.71) (83,618,004.78) (79,339,339.74) (72,538,256.58) (76,765,014.42) (72,222,791.17) (63,642,103.39) (49,480,543.82) (62,106,657.79) (65,936,534.19) (52,045,993.74)
2025-2026 Incremental Deferral(Sum of 1-6 above) (11,569,286.54) (2,601,959.82) 6,640,435.52 6,966,996.32 9,394,860.71 (2,152,287.50) 6,722,273.41 10,271,922.54 15,938,291.32 (10,425,013.31) (900,115.10) (6,508,717.10) 21,777,400.45
2025-2026 PCA Forecast Revenues(Collections)7 above (1,564,030.09) (1,733,488.58) (3,911,782.01) (7,837,195.92) (7,858,311.56) (7,052,467.60) (5,549,786.82) (4,835,919.55) (5,257,438.44) (6,087,374.53) (6,895,347.54) (6,048,864.98) (64,632,007.62)
2025-2026 PCA Prior Balance Revenues(Collections) 6,195,760.26 6,866,948.67 2,907,813.31 5,497,272.99 5,595,114.59 5,280,240.00 3,689,590.89 3,445,613.09 3,745,882.12 4,051,209.02 4,172,608.43 3,655,491.66 23,162,500.55
2025-2026 Ending Balance Without Current Month Interest (71,375,070.63) (82,794,326.01) (83,271,785.51) (78,990,931.39) (72,207,676.00) (76,462,771.68) (71,902,936.94) (63,341,175.09) (49,215,368.39) (61,941,722.64) (65,729,512.00) (74,838,624.61) (71,738,100.36)
Current Month Interest (216,858.31) (298,299.70) (346,219.27) (348,408.35) (330,580.58) (302,242.74) (319,854.23) (300,928.30) (265,175.43) (164,935.15) (207,022.19) (219,788.45) (3,320,312.70)
2025-2026 Ending Deferral Balance $ 71,591,928.94 83,092,625.71 83,618,004.78 79,339,339.74 72,538,256.58 76,765,014.42 72,222,791.17 63,642,103.39 49,480,543.82 62,106,657.79 65,936,534.19 75,058,413.06 75,058,413.06
Tab is 100%locked down,with no manual inputs.
Idaho Billed Sales MWh 1,041,992 1,154,889 1,398,929 1,671,616 1,671,846 1,500,405 1,180,713 1,028,839 1,118,516 1,210,052 1,244,813 1,091,459 15,314,069
Oregon Billed Sales MWh 47,806 49,780 57,526 67,705 70,248 64,187 47,932 52,146 54,307 56,256 58,744 42,982 669,619
Total MWh 1,089,798 1,204,669 1,456,456 1,739,321 1,742,094 1,564,592 1,228,645 1,080,985 1,172,823 1,266,308 1,303,557 1,134,441 15,983,688
Idaho%Billed Sales 95.6% 95.9% 96.1% 96.1% 96.0% 95.9% 96.1% 95.2% 95.4% 95.6% 95.5% 96.2%
Oregon%Billed Sales 4.4% 4.1% 3.9% 3.9% 4.0% 4.1% 3.9% 4.8% 4.6% 4.4% 4.5% 3.8%
Exhibit No. 2
Case No.IPC-E-26-30
J.Brady,IPC
Page 2 of 2
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-26-10
IDAHO POWER COMPANY
BRADY, DI
TESTIMONY
EXHIBIT NO. 3
ROE DETERMINATION REVENUE SHARING
1 IDAHO POWER COMPANY
2
3 ADDITIONAL INVESTMENT TAX CREDIT ANALYSIS
4 For the Twelve Months Ended December 31,2025
5
6 Actual September 30,2025 Actual December 31,2025
1 TOTAL TOTAL
8 SYSTEM IDAHO IDAHO% SYSTEM IDAHO IDAHO%
9 •'•SUMMARY OF RESULTS•••
to TOTAL COMBINED RATE BASE 5,298,055,015 5,065,610,359 95.6% Sept Allocations/Ratios
11
12 DEVELOPMENT OF NET INCOME
13 OPERATING REVENUES
14 RETAIL SALES REVENUES(Ind 449.1 Rev) 1,233,369,462 1,181,922,554 Direct Assign 1,556,357,621 1,490,027,384 Direct Assign
15 OTHER OPERATING REVENUES 168,070,363 161,301,701 96.0% 247,981,706 237,994,792 96.0%
16 TOTAL OPERATING REVENUES 1,401,439,825 1,343,224,255 1,804,339,327 1,728,022,177
17
18 OPERATING EXPENSES
19 OPERATION&MAINTENANCE EXPENSES 895,518,946 862,906,499 96.4% 1,172,814,593 1,130,103,767 96.4%
26 DEPRECIATION EXPENSE 173,996,043 166,811,776 95.9% 235,023,637 225,319,551 95.9%
21 AMORTIZATION OF LIMITED TERM PLANT 6,649,269 6,388,251 96.1% 9,666,075 9,286,633 96.1%
22 TAXES OTHER THAN INCOME 21,818,127 20,145,295 92.3% 28,389,737 26,213,048 92.3%
23 REGULATORY DEBITS/CREDITS 4,131,455 3,878,014 93.9% 5,490,795 5,153,966 93.9%
24 PROVISION FOR DEFERRED INCOME TAXES (28,931,468) (27,509,227) 95.1% (49,153,098) (46,736,782) 95.1%
25 INVESTMENT TAX CREDIT ADJUSTMENT 10,573,330 10,121,006 95.7% 45,738,426 43,781,749 95.7%
26 FEDERAL INCOME TAXES 37,128,856 34,967,695 94.2% 18,645,847 17,560,527 94.2%
27 STATE INCOME TAXES 5,409,489 5,086,505 94.0% 3,379,772 3,177,976 94.0%
28 TOTAL OPERATING EXPENSES 1,126,294,048 1,082,795,814 1,469,995,784 1,413,860,434
29
36 OPERATING INCOME 275,145,777 260,428,441 334,343,542 314,161,742
31 ADD:IERCO OPERATING INCOME 1,717,822 1,646,201 95.8% 2,248,633 2,164,881 95.8%
32
33 OPERATING INCOME BEFORE OTHER INCOME AND DEDUCTIC 276,863,599 262,074,642 336,592,176 316,316,623 94.0%
34 ADD:AFUDC EQUITY 62,488,668 59,747,066 95.6%(L 10)
35 ADD:OTHER INCOME AND DEDUCTIONS 35,610,937 33,465,814 94.0%(L 33)
36
37 INCOME BEFORE INTEREST CHARGES 434,691,780 409,529,503
38 LESS:INTEREST CHARGES 159,166,343 152,183,145 95.6%(L 10)
39
46 NET INCOME 275,525,437 257,346,358
41
42 ACTUALYEAR-END RESULTS-BEFORE ITC ADJUSTMENT
43 EARNINGS ON COMMON STOCK 275,525,437 257,346,358
44 COMMON EQUITY AT YEAR END 3,371,655,674 3,223,729,059 95.6%(1-10)
45
46 RETURN ON YEAR-END COMMON EQUITY 8.17% 7.98%
47
4fi EARNINGS ON COMMON STOCK @ 9.12 ROE 307,494,997 294,004,090 (144.9.12%)
49 EARNINGS ON COMMON STOCK @ 9.6 ROE 323,678,945 309,477,990 (144.9.6%
51
52
53 ACTUAL YEAR-END RESULTS-AFTER ITC ADJUSTMENT:
54 INVESTMENT TAX CREDIT ADJUSTMENT 40,336,413 (1-48-1-43)/(1-9.12%)
55 ADJUSTED EARNINGS ON COMMON STOCK 297,682,771
56 ADJUSTED COMMON EQUITY AT YEAR-END 3,264,065,472
57 ADJUSTED RETURN ON YEAR-END COMMON EQUITY 9.12%
58
59 IF IDAHO RETURN ON COMMON EQUITY(Line 46)<9.12%
fie ADDITIONAL ITC ADJUSTMENT(Annual¢ed) If L 54 is negative,then 0(no cap on ADITC per Order 36042) 40,336,413
fit
fie 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%)
fi4
67
as Per Order#36042: After Tax Tax Gross Up
69 ROE Greater than 9.6%-CUSTOMER SHARE-80%(Reduction to rates) 0
76 ROE Greater than 9.6%-COMPANY SHARE-20% 0
73 0
74
Exhibit No. 3
Case No.IPC-E-26-10
J.Brady,PC
Page 1 of 1
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-26-10
IDAHO POWER COMPANY
BRADY, DI
TESTIMONY
CONFIDENTIAL
EXHIBIT NO. 4
CLEAN ENERGY YOUR WAY