20240415IPC Direct Brady.pdf

RECEIVED
Monday,April 15,2024 4:10 PM
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-24-17
COST ADJUSTMENT ("PCA") RATES )
FOR ELECTRIC SERVICE FROM JUNE )
1, 2024, THROUGH MAY 31, 2025 . )
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 2024-2025 Power Cost Adjustment ("PCA") rates to become
9 effective June 1, 2024 . If approved, the 2024-2025 PCA
10 will result in a decrease in total billed revenue of
11 approximately $35 . 7 million, or 2 . 31 percent.
12 Q. How is your testimony organized?
13 A. My testimony consists of five sections . In the
14 first section, I provide an overview of the PCA. In the
15 second section, I detail the 2024-2025 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 2024-2025 PCA rates to become
19 effective June 1, 2024 . 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 2024-2025 PCA rates if approved as filed. In the final
23 section, I discuss additional topics related to Order Nos .
24 35804 and 36042 of the Company' s 2023 PCA filing and
25 General Rate Case, respectively.
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 2024-2025 PCA Forecast
5 Exhibit No. 2 2023 Balancing Adjustment
6 Exhibit No. 3 2023 ROE Determination Revenue Sharing
7 Exhibit No. 4 Confidential - Black Mesa Solar
8 Generation and Expenses
9 Exhibit No. 5 Confidential - Hells Canyon Liquidated
10 Damages
11 I . PCA OVERVIEW
12 Q. What is the purpose of the PCA?
13 A. The PCA is a rate mechanism that quantifies
14 and tracks annual differences between actual Net Power
15 Supply Expenses ("NPSE") and the normalized or "base level"
16 of NPSE recovered in the Company' s base rates, resulting in
17 a credit or surcharge that is updated annually on June 1 .
18 The PCA mechanism uses a 12-month test period of April
19 through March ("PCA Year") and includes a forecast
20 component and a Balancing Adjustment. The forecast
21 component represents the difference between the Company' s
22 NPSE forecast from the March Operating Plan and base level
23 NPSE recovered in the Company' s base rates . The Balancing
24 Adjustment includes a backward-looking tracking of
25 differences between the prior PCA Year' s forecast and
BRADY, DI 3
Idaho Power Company

1 actual NPSE incurred by the Company, and also tracks the
2 collection of the prior year' s Balancing Adjustment.
3 Q. How does the PCA mechanism function?
4 A. With the exception of Public Utility
5 Regulatory Policies Act of 1978 ("PURPA") expenses and
6 demand response incentive payments, the PCA allows the
7 Company to pass through to customers 95 percent of the
8 annual differences in actual NPSE as compared with base
9 level NPSE, whether positive or negative. With respect to
10 PURPA expenses and demand response incentive payments, as
11 actual annual expenses deviate from base level NPSE, the
12 Company is allowed to pass 100 percent of the difference
13 for recovery or credit through the PCA. The PCA is also the
14 rate mechanism used by the Company to provide customer
15 benefits resulting from the revenue sharing mechanism
16 approved by the Commission in Order No. 34071 .
17 Q. Does the revenue collected from customers
18 through the annual PCA rate contribute toward the Company' s
19 earnings?
20 A. No. The PCA mechanism provides for the annual
21 collection or refund of net power supply cost differences
22 between actual costs incurred by the Company and the base
23 level NPSE component of base rates . Aside from the 95
24 percent to 5 percent sharing component I just described,
25 the PCA provides for a one-for-one collection or refund of
BRADY, DI 4
Idaho Power Company

1 actual net power supply expenses incurred, or to be
2 incurred, to provide safe, reliable electric service to
3 customers .
4 Q. What are the components of the PCA base level
5 NPSE?
6 A. The PCA base level NPSE includes the following
7 Federal Energy Regulatory Commission ("FERC") accounts :
8 Account 501, Fuel (coal) ; Account 536, Water for Power;
9 Account 547, Fuel (gas) ; Account 555, Purchased Power;
10 Account 565, Transmission of Electricity by Others; and
11 Account 447, Sales for Resale (typically referred to as
12 surplus sales) .
13 The PCA base level expense component for FERC
14 Account 555 includes costs of both PURPA and non-PURPA
15 (market) purchases . Per Order No. 32426, the Company
16 adjusts FERC Account 555 to also include demand response
17 incentive payments that the Company provides to customers
18 who participate in any of its three demand response
19 programs .
20 II . 2024-2025 PCA
21 Q. What is the total PCA collection that would
22 result under the 2024-2025 PCA rates proposed by the
23 Company in this case?
24 A. The 2024-2025 PCA rates would result in total
25 PCA collection of $112 . 7 million. This represents a
BRADY, DI 5
Idaho Power Company

1 decrease in total billed revenue of $35 . 7 million for the
2 upcoming year, a decrease of 2 . 31 percent.
3 Q. Have you prepared a table that details the
4 $35 . 7 million revenue impact by component?
5 A. Yes . Table 1 presents a separation of the
6 $35 . 7 million decrease into each component included in the
7 Company' s proposed rates .
8
Table 1 Idaho Jurisdictional Revenue Impact by Component
Line
No. Rate Component 2023-2024 PCA 2024-2025 PCA Difference
1 PCA Forecast $ 52,202,870 $ 22,712,031 $ (29,490,839)
2 PCA Balancing Adjustment $ 96,189,461 $ 89,970,511 $ (6,218,951)
3 PCA Total $ 148,392,331 $ 112,682,542 $ (35,709,789)
4 Revenue Sharing $ 0 $ 0 $ 0
5 Total Revenue Impact $ 148,392,331 $ 112,682,542 $ (35,709,789)
9
10 Q. What are the main factors driving the revenue
11 change requested in this case?
12 A. The decrease in this year' s PCA is driven by a
13 decrease in both the forecast component and the Balancing
14 Adjustment . The decrease in this year' s forecast component
15 is attributed primarily to higher forecast hydro
16 generation. The decrease in this year' s Balancing
17 Adjustment is primarily attributed to the Sales Based
18 Adjustment ("SBA") , which accounts for the variance in
19 actual sales and the sales used to set base level NPSE, and
20 an increase in Renewable Energy Credit ("REC") sales .
BRADY, DI 6
Idaho Power Company

1 A. PCA Forecast.
2 Q. How is the PCA forecast amount determined?
3 A. As described previously, the PCA forecast
4 component represents the difference between the Company' s
5 forecast of NPSE for the upcoming April - March test year
6 and base level NPSE recovered in the Company' s base rates .
7 Q. What is the Company' s determination of the
8 system-level difference between currently approved base
9 level NPSE1 and the forecast of NPSE for the 2024-2025 PCA
10 Year?
11 A. The system-level forecast of NPSE for the
12 2024-2025 PCA Year is $509, 555, 990, which is $24, 648, 746
13 higher than the currently approved base level NPSE of
14 $484, 907, 244 . Table 2 presents the system-level
15 differences between currently approved base level NPSE and
16 the forecast of NPSE for the 2024-2025 PCA Year by FERC
17 account .
18
19
20
21
22
1 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 7
Idaho Power Company

I
Table 2 2024-2025 PCA FORECAST(Total System)
Line No. FERC Account Base NPSE Forecast Difference
95%Sharing Accounts
1 Account 501,Coal $ 65,523,000 $ 117,075,844 $ 51,552,844
2 Account 536,Water for Power $ 0 $ 0 $ 0
3 Account 547,Other Fuel $ 119,653,675 $ 147,302,230 $ 27,648,555
4 Account 555,Purchased Power Non-PURPA $ 99,465,021 $ 90,809,149 $ (8,655,871)
5 Account 565,3rd Party Transmission $ 10,263,139 $ 10,419,009 $ 155,870
6 Account 447,Surplus Sales $ (34,686,350) $ (86,055,453) $ (51,369,103)
$ 260,218,486 $ 279,550,780 $ 19,332,294
100%Sharing Accounts
7 Account 555,PURPA $ 214,448,755 $ 219,593,677 $ 5,144,922
8 Account 555,Demand Response Incentives $ 10,240,003 $ 10,411,533 $ 171,530
9 Total $ 484,907,244 $ 509,555,990 $ 24,648,746
2
3 Q. What is the basis for the forecast of NPSE for
4 the 2024-2025 PCA Year?
5 A. The forecast of NPSE for the 2024-2025 PCA
6 Year is based on the Company' s March 2024 Operating Plan.
7 Q. How is the NPSE forecast developed for the
8 Company' s Operating Plan?
9 A. The Operating Plan is prepared monthly and
10 represents a forecast of the Company' s monthly NPSE for the
11 following 18-month period; however, for the PCA, the
12 Company includes only the 12 months that correspond to the
13 PCA Year. The Operating Plan is developed by simulating
14 the dispatch of the Company' s generation resources for each
15 month, segmented by 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
4 system load forecast is then analyzed against the resulting
5 monthly heavy load and light load dispatch to determine a
6 monthly load and resource balance. Any identified resource
7 deficiency is assumed to be filled with market energy
8 purchases or natural gas to fuel either the Langley Gulch
9 power plant (`Langley Gulch") or Jim Bridger 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 2024-2025
14 PCA Year, as determined in the Company' s March 2024
15 Operating Plan, is provided in Exhibit No. 1 .
16 Q. Did the Company make any adjustments to the
17 March 2024 Operating Plan, for purposes of quantifying
18 forecast NPSE for the 2024-2025 PCA Year?
19 A. Yes . The Company made two adjustments to the
20 March 2024 Operating Plan for purposes of quantifying NPSE.
21 The first is the modification related to the power purchase
22 agreement ("PPA") with Black Mesa Solar, which was
23 introduced in last year' s PCA filing. The second is a
BRADY, DI 9
Idaho Power Company

1 modification related to a new special contract with Lamb
2 Weston, Inc. (""Lamb Weston") .2
3 Q. Please explain the modification related to
4 Black Mesa Solar.
5 A. For purposes of quantifying forecast NPSE for
6 the 2024-2025 PCA Year, the Company removed the forecasted
7 expenses associated with Black Mesa Solar, because Micron
8 Technology, Inc . ("Micron") will be paying for 100 percent
9 of the generation according to the provisions of the
10 special contract3 between Idaho Power and Micron.
11 Q. Please provide more information on the Black
12 Mesa Solar PPA and its treatment in the PCA forecast.
13 A. Black Mesa Solar is a 40 MW alternating
14 current solar photovoltaic generation facility that came
15 online in June 2023 . The PPA was negotiated in conjunction
16 with the Micron special contract, which states that Idaho
17 Power will procure renewable resources to assist Micron in
18 meeting a portion of its annual energy requirements with
19 energy generated by those resources . While the renewable
20 resource, Black Mesa Solar in this case, is connected to
2 In the Matter of the Application for Approval of Special contract
and Tariff Schedule 34 to Provide Electric Service to Lamb Weston,
Inc. , Case No. IPC-E-23-18, Order No. 35929 (September 21, 2023) .
3 In the Matter of the Replacement Special contract with Micron
Technology, Inc. , and Purchase Agreement with Black Mesa Energy LLC,
Case No. IPC-E-22-06, Order No. 35482 (August 01, 2023) .
BRADY, DI 10
Idaho Power Company

1 the Company' s system and does not serve Micron directly,
2 Micron is paying for all of the output.
3 As a result, the cost of the PPA was removed from
4 the Company' s calculation of forecast NPSE. In compliance
5 with Commission Order No. 35893, 4 the Company has provided
6 Black Mesa Solar' s forecast generation and expenses, as
7 well as Micron' s monthly load forecast, as Confidential
8 Exhibit No . 4 .
9 Q. How will the excess generation and renewable
10 capacity credit payments, as detailed in Micron' s special
11 contract, be incorporated into this year' s PCA filing?
12 A. In the event that Black Mesa Solar' s
13 generation exceeds Micron' s load in a given hour, the
14 Company will compensate Micron for the excess generation
15 according to the methodology approved by the Commission in
16 Order No . 35482 . However, for the 2024-2025 PCA year, the
17 Company does not expect Black Mesa Solar' s generation to
18 exceed Micron' s load in any hour. As a result, no excess
19 generation payments are included in this year' s PCA
20 forecast .
21 In addition, as stated in Order No. 35482, the
22 Company will not begin renewable capacity credit payments
4 In the Matter of Idaho Power's Application to Expand Optional
Customer Clean Energy Offerings through The Clean Energy Your Way
Program, Case No. IPC-E-21-40, Order No. 35893 (August 15, 2023) .
BRADY, DI 11
Idaho Power Company

1 until July 1, 2026 . As a result, no renewable capacity
2 credit payments are included in this year' s PCA forecast.
3 Q. Please explain the modification related to
4 Lamb Weston.
5 A. Order No. 35929 approved a new special
6 contract with Lamb Weston. It consists of a two-block
7 pricing structure that includes an embedded cost pricing
8 block ("Block 1") and a marginal cost pricing block ("Block
9 2") . Block 2 consists of electricity consumed beyond 20
10 megawatts . According to the Lamb Weston special contract,
11 revenues from Block 2 energy sales should be treated as a
12 surplus sale in NPSE calculations . As a result, revenues
13 associated with Lamb Weston' s forecast Block 2 energy sales
14 have been included in Account 447, Sales for Resale, as an
15 offset to NPSE .
16 Q. How does the Company' s forecast of system-
17 level NPSE for the 2024-2025 PCA compare to the system-
18 level forecast included in last year' s PCA?
19 A. Table 3 below compares this year' s 2024-2025
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 2024-2025 PCA year is
23 $509, 555, 990, which is $31, 943, 394 lower than last year' s
24 forecast amount of $541, 499, 384 .
25
BRADY, DI 12
Idaho Power Company

Table 3 PCA Forecast Comparison Expenses (Total System)
2023-2024 2024-2025
Line No. FERC Account Forecast Forecast Difference
95%Sharing Accounts
1 Account 501,Coal $ 130,090,026 $ 117,075,844 $ (13,014,182)
2 Account 536,Water for Power $ 0 $ 0 $ 0
3 Account 547,Other Fuel $ 134,623,640 $ 147,302,230 $ 12,678,591
4 Account 555,Purchased Power Non-PURPA $ 123,492,688 $ 90,809,149 $ (32,683,539)
5 Account 565,3rd Party Transmission $ 7,964,649 $ 10,419,009 $ 2,454,360
6 Account 447,Surplus Sales $ (84,191,539) $ (86,055,453) $ (1,863,914)
$ 311,979,464 $ 279,550,780 $ (32,428,684)
100%Sharing Accounts
7 Account 555,PURPA $ 218,535,412 $ 219,593,677 $ 1,058,265
8 Account 555,Demand Response Incentives $ 10,984,508 $ 10,411,533 $ (572,975)
$ 229,519,920 $ 230,005,210 $ 485,290
9 Total PCA Forecast $ 541,499,384 $ 509,555,990 $ (31,943,394)
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 decreased approximately $32 . 4 million
6 from last year' s forecast, while the 100 percent sharing
7 accounts have increased approximately $0 . 49 million over
8 last year' s forecast.
9 Q. What factors are contributing to the major
10 differences presented in Table 3?
11 A. Forecast expenses included in the 95 percent
12 sharing accounts are expected to decrease by 10 percent as
13 compared to last year, from $311, 979, 464 to $279, 550, 780 .
14 Due to the 12 percent increase in forecast hydro generation
BRADY, DI 13
Idaho Power Company

1 and the conversion of Bridger Units 1 and 2 to natural gas,
2 the Company expects to rely more on hydro and natural gas
3 generation and less on purchased power and coal generation
4 to serve load in the 2024-2025 PCA Year.
5 Q. Please elaborate on the changes in the 95
6 percent sharing accounts for this year' s forecast as
7 compared with last year' s forecast as presented in Table 3 .
8 A. For the 2024-2025 PCA year, the average
9 forecast market purchase price is $62 . 07 per megawatt-hour
10 ("MWh") , compared to $76 . 01 per MWh last year, a decrease
11 of 18 percent . Accordingly, expenses from non-PURPA
12 purchased power are expected to decrease 26 percent
13 compared to last year.
14 The per-unit cost of natural gas-fired generation
15 for the 2024-2025 PCA year is $40 . 52 per MWh, a decrease of
16 2 percent compared to last year. The per-unit cost of coal-
17 fired generation for the 2024-2025 PCA year is $38 . 18 per
18 MWh, an increase of 3 percent compared to last year. While
19 the forecast prices for natural gas and coal remained
20 relatively unchanged, due to the conversion of Bridger
21 Units 1 and 2 to natural gas, natural gas generation is
22 expected to increase 11 percent and coal-fired generation
23 is expected to decrease 13 percent as compared to last
24 year' s forecast.
BRADY, DI 14
Idaho Power Company

1 Surplus sales revenue is expected to increase 2
2 percent compared to last year, from $84, 191, 539 to
3 $86, 055, 453 . For the 2024-2025 PCA Year, the average
4 forecast market sales price is $62 . 64 per MWh compared with
5 $82 . 96 last year, a 25 percent decrease.
6 Q. Does Account 447, Sales for Resale, include
7 forecasted revenues from wheeling losses?
8 A. Yes . Consistent with Order No. 36042 in the
9 Company' s 2023 General Rate Case, Idaho Power has included
10 both actual and forecasted revenues from wheeling losses in
11 NPSE beginning January 2024 .
12 Q. What factors are contributing to the change in
13 the 100 percent sharing accounts?
14 A. As can be seen in Table 3, forecast expenses
15 included in the 100 percent sharing accounts are expected
16 to increase 0 .2 percent compared to last year, from
17 $229, 519, 920 to $230, 005, 210 . Forecast PURPA costs
18 increased by $1 . 06 million as compared to last year' s
19 forecast and forecast demand response incentive payments
20 decreased by $0 . 57 million as compared to last year.
21 Q. Is the increase in forecast PURPA costs
22 related to increased generation output from PURPA projects?
23 A. In part. Table 4 details changes between last
24 year' s PCA forecast and this year' s PCA forecast with
25 respect to forecasted generation in MWh. As shown in Table
BRADY, DI 15
Idaho Power Company

1 4, total PURPA generation is anticipated to decrease by
2 136, 646 MWh, or 4 percent. The increase in PURPA expense is
3 largely the result of price escalation in PURPA contracts,
4 for which the average cost is $75 . 17 per MWh, compared to
5 $71 . 47 last year.
Table 4 PCA Forecast Comparison Generation(Total System-MWh)
2024-2025
Line No. FERC Account 2023-2024 Forecast Forecast Difference
1 Hydro 6,487,995 7,293,179 805,184
95%Sharing Accounts
2 Account 501,Coal 3,520,905 3,066,212 (454,693)
3 Account 547,Other Fuel 3,261,784 3,635,055 373,271
4 Account 555,Purchased Power Non-PURPA 1,695,683 1,577,970 (117,713)
95%Sharing Accounts 14,966,367 15,572,415 606,048
100%Sharing Accounts
5 Account 555,PURPA 3,057,802 2,921,156 (136,646)
100%Accounts 3,057,802 2,921,156 (136,646)
6 Total Generation 18,024,169 18,493,571 469,402
95%Sharing Accounts
7 Less Account 447,Surplus Sales 1,014,817 1,306,125 291,308
8 Total Load 17,009,352 17,187,446 178,094
6
7 Q. What other general conclusions can be drawn
8 from the information in Table 4?
9 A. Compared to last year' s forecast, hydro
10 generation is expected to increase from 6, 487, 995 MWh to
11 7, 293, 179 MWh, or 12 percent. In addition, coal-fired
12 generation is expected to decrease 13 percent and natural
13 gas generation is expected to increase 11 percent compared
14 to last year. Lastly, non-PURPA purchased power is expected
BRADY, DI 16
Idaho Power Company

1 to decrease 7 percent from last year, which is largely
2 attributed to the reduction in forecast short-term market
3 purchases .
4 Q. What is causing the 12 percent increase in
5 expected hydro generation?
6 A. The increase in expected hydro generation is
7 mainly due to higher projected inflows into Brownlee
8 reservoir. The March Operating Plan used in this year' s PCA
9 forecast projects April through July inflows into Brownlee
10 of 4 . 8 million acre-feet ("MAF") as compared to 4 . 3 MAF
11 used to determine last year' s PCA forecast, an increase of
12 12 percent . Expected inflows into Brownlee are higher than
13 last year' s PCA forecast as a result of better reservoir
14 storage conditions, which provide for sustained runoff and
15 increased hydro generation during the spring and summer
16 months . Storage at major reservoirs above Brownlee are 85
17 percent full, which is 127 percent of normal .
18 Q. How are the forecasted NPSE differences
19 presented in Table 2 used to determine the 2024-2025 PCA
20 forecast component to be collected from Idaho customers?
21 A. The 2024-2025 PCA forecast component reflects
22 the Idaho jurisdictional share of the forecasted NPSE
23 differences presented in Table 2, adjusted for the PCA
24 sharing provisions . The Idaho jurisdictional share of the
25 forecast NPSE differences is determined by applying a ratio
BRADY, DI 17
Idaho Power Company

1 of forecast firm Idaho jurisdictional sales to forecast
2 firm system-level sales to the system-level NPSE
3 differences .
4 Q. Were any changes made to the Idaho
5 jurisdictional sales and system-level sales to account for
6 the discussed modifications related to Black Mesa Solar and
7 Lamb Weston?
8 A. Yes . Both the portion of Micron' s load
9 forecast to be met by Black Mesa Solar and forecast Lamb
10 Weston Block 2 energy sales were removed from the total
11 forecast Idaho jurisdictional sales and system-level sales
12 and were not used in the derivation of the PCA rate.
13 Q. What is the Company' s forecast of system-level
14 firm sales and Idaho jurisdictional firm sales, net of the
15 Black Mesa Solar and Lamb Weston modifications, for the
16 2024-2025 PCA Year?
17 A. For the 2024-2025 PCA Year, Idaho Power has
18 forecast system-level firm sales to be 15, 787, 686 MWh and
19 Idaho jurisdictional firm sales to be 15, 131, 267 MWh, or
20 95 . 84 percent of the system level .
21 Q. What is the Company' s determination of the
22 2024-2025 PCA forecast component to be collected from Idaho
23 customers?
24 A. The 2024-2025 PCA forecast component to be
BRADY, DI 18
Idaho Power Company

1 collected from Idaho customers is $22, 704, 611 . 5 Table 5
2 presents the determination of the 2024-2025 PCA forecast
3 component by individual PCA expense and revenue category.
Table
5 2024-2025 PCA FORECAST
Difference After
Line No. FERC Account Difference from Base Sharing Idaho Allocation
95%Sharing Accounts (From Table 2)
1 Account 501,Coal $ 51,552,844 $ 48,975,202 $ 46,938,915
2 Account 536,Water for Power $ 0 $ 0 $ 0
3 Account 547,Other Fuel $ 27,648,555 $ 26,266,127 $ 25,174,036
4 Account 555,Purchased Power Non-PURPA $ (8,655,871) $ (8,223,078) $ (7,881,179)
5 Account 565,3rd Party Transmission $ 155,870 $ 148,077 $ 141,920
6 Account 447,Surplus Sales $ (51,369,103) $ (48,800,648) $ (46,771,618)
$ 19,332,295 $ 18,365,680 $ 17,602,074
100%Sharing Accounts
7 Account 555,PURPA $ 5,144,922 $ 5,144,922 $ 4,931,007
8 Account 555,Demand Response Incentives $ 171,530 $ 171,530 $ 171,530
9 Total $ 24,648,747 $ 23,682,132 $ 22,704,611
4
5 B. Balancing Adjustment.
6 Q. What is this year' s quantification of the
7 Balancing Adjustment?
8 A. The Balancing Adjustment is detailed in the
9 PCA deferral report, attached hereto as Exhibit No. 2 . This
10 report compares actual NPSE amounts to actual power cost
11 collections monthly, with the differences accumulated as a
12 deferral balance . The balance at the end of March 2024,
13 with interest applied, was $89, 971, 188 as shown on row 100
5 This will not tie to the forecast component from Table 1 due to
rounding of PCA rate.
BRADY, DI 19
Idaho Power Company

1 of Exhibit No . 2 . The approximate $90 million represents a
2 decrease to customer rates in this year' s PCA Balancing
3 Adjustment .
4 Q. To what factors do you attribute the
5 accumulation of the approximate $90 million deferral
6 balance?
7 A. Order No. 35804 in last year' s PCA filing
8 directed Idaho Power to collect the 2022-2023 PCA deferral
9 balance equally over a two-year period. As a result, this
10 year' s approximate $90 million balance is primarily
11 attributed to the continued collection of last year' s
12 deferral balance . Actual power supply expenses in the 2023-
13 2024 PCA Year were just 3 percent higher than forecast
14 expenses . As a result, the variance between forecast and
15 actual power supply expenses for the 2023-2024 PCA Year had
16 a relatively small impact on this year' s deferral balance.
17 However, this year' s deferral balance does include
18 increased benefits associated with the SBA, as well as
19 increased REC sales .
20 Q. Please explain the changes in actual versus
21 forecast generation and expense for the 2023-2024 PCA Year.
22 A. Actual hydro generation for the 2023-2024 PCA
23 year totaled 6, 921, 812 MWh, a 7 percent increase from last
24 year' s forecast of 6, 487, 995 MWh. Actual non-PURPA
25 purchased power totaled 3, 912, 307 MWh, a 131 percent
BRADY, DI 20
Idaho Power Company

1 increase from last year' s forecast. Actual natural gas
2 generation totaled 3, 086, 278 MWh, a 5 percent decrease from
3 last year' s forecast. Lastly, actual surplus sales volumes
4 totaled 2, 637, 210 MWh, an increase of 160 percent from last
5 year' s forecast.
6 Q. Please elaborate on the changes in actual
7 versus forecast generation and expense for the 2023-2024
8 PCA Year.
9 A. Actual coal-fired generation for the 2023-
10 2024 PCA year was 27 percent lower than forecast . Actual
11 coal fuel expense totaled $106, 401, 903, which was 18
12 percent lower than forecast.
13 Actual natural gas generation for the 2023-2024 PCA
14 was 5 percent lower than forecast. Actual natural gas
15 expense was $171, 487, 628, which was 27 percent higher than
16 forecast . The per-unit cost of natural gas in the 2023-2024
17 PCA Year was $55 . 56/MWh, a 35 percent increase from
18 forecast .
19 Actual non-PURPA purchased power totaled 3, 912, 307
20 MWh for the 2023-2024 PCA Year, which was 131 percent
21 higher than forecast. Actual non-PURPA purchased power
22 expense was $225, 264, 049, which was 82 percent higher than
23 forecast .
24 Surplus sales totaled 2, 637, 210 MWh for the 2023-
25 2024 PCA Year, which was 160 percent higher than forecast.
BRADY, DI 21
Idaho Power Company

1 Actual surplus sales revenue was $160, 755, 918, which was 91
2 percent higher than forecast.
3 While both purchased power and surplus sales
4 increased, surplus sale volumes were highest in off-peak
5 spring and winter months, and purchased power was highest
6 in either summer months, where hot temperatures caused
7 higher than forecast peak loads, or in spring months, where
8 prices were relatively low.
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 . Per Commission Order No. 34100, Idaho
13 Power included its actual costs of Western Energy Imbalance
14 Market ("EIM") participation for April 2023 through
15 December 2023 in the Balancing Adjustment . Because EIM
16 costs were included in base rates resulting from the
17 Company' s 2023 General Rate Case, which went into effect on
18 January 1, 2024, EIM costs are no longer included in the
19 PCA as of that date . Benefits associated with EIM
20 participation are embedded in actual NPSE.
21 Q. Please summarize the conditions of Order No.
22 34100 as they pertain to EIM cost recovery through the 2023
23 PCA.
24 A. Per the terms of the settlement stipulation
25 ("EIM Stipulation") approved by Order No. 34100, Idaho
BRADY, DI 22
Idaho Power Company

1 Power agreed to include an EIM-related monthly revenue
2 requirement in its monthly PCA deferral calculation based
3 on actual EIM participation costs commencing April 1, 2018 .
4 The Company also agreed to apply a soft cap to EIM-related
5 revenue requirement included in the PCA deferral equal to
6 annual EIM benefits as reported by the California
7 Independent System Operator ("CAISO") for the corresponding
8 period.
9 Q. Is the EIM-related revenue requirement
10 included in the April 2023 through March 2024 PCA deferral
11 under the soft cap of annual CAISO-reported benefits for
12 that same period?
13 A. Yes . For the April 2023 through December 2023
14 period, the EIM-related revenue requirement totaled $1 . 9
15 million, while CAISO reported EIM benefits for Idaho Power
16 of approximately $49 . 6 million from April through December.
17 Therefore, the Company' s EIM-related revenue requirement is
18 less than the soft cap agreed to in the EIM Stipulation.
19 Q. Does Idaho Power believe the EIM has provided
20 net benefits to customers since joining in April 2018?
21 A. Yes . While Idaho Power believes the CAISO
22 benefit calculation overstates estimated benefits to Idaho
23 Power' s system, the Company believes customers have
24 realized significant net benefits since the Company' s entry
25 into the EIM in April 2018 . As discussed in the Company' s
BRADY, DI 23
Idaho Power Company

1 May 24, 2019, Report of EIM Benefits and Costs of
2 Participation, filed in Case No. IPC-E-16-19, Idaho Power
3 has developed a more precise methodology for determining
4 EIM benefits that uses inputs specific to the Company.
5 Based on this methodology, the Company believes benefits
6 achieved between April 2023 and December 2023 are
7 approximately $39 . 5 million (benefits for the first quarter
8 of 2024 are not yet available) . This level of EIM benefits
9 compared to the Idaho-jurisdictional EIM costs of $1 . 9
10 million, demonstrates a net benefit to the Company and,
11 ultimately, its customers .
12 C. PCA Rate Determination.
13 Q. How is the rate for the forecast portion of
14 the PCA for April 2024 through March 2025 determined?
15 A. The rate for the forecast portion of the PCA
16 is equal to the sum of (1) 95 percent of the difference
17 between the non-PURPA 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 forecast of system
20 firm sales for June 1, 2024, through May 31, 2025 ("System-
21 level Sales Forecast") ; and (2) 100 percent of the
22 difference between PURPA-related expenses quantified in the
23 Operating Plan and those quantified in the Company' s last
24 approved update of NPSE, divided by the Company' s System-
25 level Sales Forecast; and (3) 100 percent of the difference
BRADY, DI 24
Idaho Power Company

1 between the Idaho jurisdictional demand response incentive
2 payments quantified in the Operating Plan and those
3 quantified in the Company' s last approved update of NPSE,
4 divided by the forecast of Idaho jurisdictional firm sales
5 for June 1, 2024, through May 31, 2025 .
6 Q. What is the rate for the forecast portion of
7 the PCA for April 2024 through March 2025?
8 A. The rate for non-PURPA expenses is 0 . 1163
9 cents per kilowatt-hour ("kWh") , which is calculated by
10 multiplying $19, 332, 295 from Table 2 by 95 percent and then
11 dividing it by the System-level Sales Forecast (net of
12 Black Mesa Solar generation and Lamb Weston Block 2 energy
13 sales) of 15, 787, 686 MWh ( ($19, 332, 295 * 0 . 95) /
14 15, 787, 686) _ $1 . 163 /MWh = 0 . 1163 cents/kWh) . The rate for
15 PURPA expenses is 0 . 0326 cents per kWh, which is calculated
16 by dividing $5, 144, 922 from Table 2 by the 15, 787, 686 MWh
17 ($5, 144, 922 / 15, 787, 686 MWh = $0 . 326/MWh = 0 . 0326
18 cents/kWh) . The rate for demand response incentive payments
19 is 0 . 0011 cents per kWh, which is calculated by dividing
20 the $171, 530 from Table 2 by the forecast of Idaho
21 jurisdictional firm sales (net of Black Mesa Solar and Lamb
22 Weston modifications) of 15, 131, 267 MWh (171, 530 /
23 15, 131, 267 MWh = $0 . 0110/MWh = 0 . 0011 cents/kWh) . The
24 forecast portion of the PCA rate is 0 . 1501 cents per kWh,
25 which is calculated by adding the non-PURPA expense of
BRADY, DI 25
Idaho Power Company

1 0 . 1163 cents per kWh to the PURPA expense of 0 . 0326 cents
2 per kWh to the demand response incentive payment of 0 . 0011
3 cents per kWh (0 . 1163 + 0 . 0326 + 0 . 0011 = 0 . 1501
4 cents/kWh) .
5 Q. How did you compute this year' s Balancing
6 Adjustment rate?
7 A. As shown in Exhibit No. 2, this year' s
8 Balancing Adjustment of the PCA is approximately $90
9 million, which, when divided by the Company' s forecast of
10 Idaho jurisdictional sales of 15, 131, 267 MWh, results in a
11 rate of 0 . 5946 cents per kWh ($89, 971, 188 / 15, 131, 267 =
12 $5 . 946/MWh = 0 . 5946 cents/kWh) .
13 Q. What is the resulting PCA rate when you
14 combine all the PCA components described previously?
15 A. The uniform PCA rate comprises (1) the 0 . 1501
16 cents per kWh for the 2024-2025 projected power cost of
17 serving firm loads under the current PCA methodology and 95
18 percent sharing, and (2) the 0 . 5946 cents per kWh for the
19 2023-2024 Balancing Adjustment of the PCA. The sum of these
20 two components is a 0 . 7447 cents per kWh charge for all
21 rate classes .
22 III . ADDITIONAL PCA RATE ADJUSTMENTS
23 A. Revenue Sharing.
24 Q. When was the revenue sharing mechanism
25 originally established?
BRADY, DI 26
Idaho Power Company

1 A. The revenue sharing mechanism was originally
2 established in Case No . IPC-E-09-30 and approved in Order
3 No . 30978, effective for the years 2009-2011 . Since then,
4 the revenue sharing mechanism has been modified and
5 extended four times . 6 Order No . 34071 in Case No. GNR-U-18-
6 01 extended the revenue sharing mechanism indefinitely,
7 with modifications .
8 The mechanism was most recently modified in the
9 Company' s 2023 General Rate Case . However, the stipulated
10 modifications were effective January 1, 2024, and will not
11 impact the PCA filing until 2025 .
12 Q. What are the provisions of the current revenue
13 sharing mechanism?
14 A. In Case No. GNR-U-18-01, the Company filed a
15 motion to approve a settlement stipulation ("2018
16 Stipulation") extending the sharing mechanism indefinitely,
17 with modifications . The Commission approved the 2018
18 Stipulation in Order No . 34071 .
19 Per the terms of the 2018 Stipulation, if the
20 Company' s actual year-end Return on Equity ("ROE") for the
21 Idaho jurisdiction exceeds 10 percent, all amounts up to
22 and including a 10 . 5 percent ROE will be shared between
23 customers and the Company on an 80 percent and 20 percent
24 basis, respectively, to be provided as a rate reduction to
6 Order Nos. 32424, 33149, 34071, and 36042.
BRADY, DI 27
Idaho Power Company

1 become effective at the time of the subsequent year' s PCA.
2 If the Company' s Idaho jurisdictional ROE exceeds 10 . 5
3 percent, all amounts in excess of 10 . 5 percent will be
4 shared 55 percent with Idaho customers as a rate reduction
5 to become effective with the subsequent year' s PCA, 25
6 percent will be shared with Idaho customers in the form of
7 an offset to amounts in the Company' s pension balancing
8 account, and 20 percent will be apportioned to the Company.
9 With regard to the amortization of Accumulated
10 Deferred Investment Tax Credits ("ADITC") , the 2018
11 Stipulation allows the Company to accelerate the
12 amortization of ADITC, in an amount up to $45 million, to
13 achieve a maximum 9 . 4 percent Idaho jurisdictional ROE if
14 the Company' s year-end actual results fall below that
15 amount for any year beginning January 1, 2020 . Idaho Power
16 may use up to $25 million of additional amortization of
17 ADITC per year, provided the total, cumulative amount of
18 ADITC does not exceed $45 million. Per the 2018
19 Stipulation, once the Company has fully amortized the $45
20 million of ADITC, revenue sharing will cease; however,
21 Idaho Power may at any time request to replenish the total
22 amount of ADITC it is permitted to amortize, and if
23 approved by the Commission, revenue sharing would continue.
24 Q. What have been the results of the revenue
25 sharing mechanism since it was implemented through 2022?
BRADY, DI 28
Idaho Power Company

1 A. The Company' s earnings in each year from 2011
2 through 2015, as well as 2018 and 2021, resulted in revenue
3 sharing with customers totaling $126 . 7 million, either as a
4 direct rate offset in the PCA or as an offset to amounts
5 that would have otherwise been collected in rates . The
6 Company' s earnings in 2016, 2017, 2019, 2020, and 2022 were
7 below the revenue sharing threshold. These amounts are
8 detailed in Table 6 below.
Table
6 2009-2022 Revenue Sharing
Line
No. Revenue Sharing Component 2009-2011 2012-2014 2015-2019 2020-2022
1 Available ADITC For Use $45 Million $45 Million $45 Million $45 Million
2 Customer Benefits($ Millions):
3 Reduction to Rates $27.1 $22.8 $8.2 $0.6 Total
4 Offset to Pension Balancing Account $20.3 $47.8 $0.0 $0.0 2009-2022
5 Total $47.4 $70.6 $8.2 $0.6 $126.7
9
10 Q. Did the Company' s year-end 2023 financial
11 results warrant any action related to the existing sharing
12 agreement per the terms of the 2018 Stipulation?
13 A. No. The Company' s year-end 2023 financial
14 results yielded an actual Idaho jurisdictional ROE of 9 . 4
15 percent, falling below the 10 percent ROE threshold for
16 revenue sharing, and thus resulting in no revenue sharing
17 with customers .
18 Q. Did the Company use the same methodology to
19 determine the Idaho jurisdictional 2023 year-end ROE that
20 was used in prior PCA filings?
BRADY, DI 29
Idaho Power Company

1 A. Yes . The methodology used to determine the
2 Company' s Idaho jurisdictional 2023 year-end ROE is
3 consistent with the methodology used for the year-end ROE
4 determinations since the inception of the mechanism.
5 Q. Do you have an exhibit demonstrating the
6 application of this methodology?
7 A. Yes . Exhibit No. 3 provides a step-by-step
8 calculation of the Idaho jurisdictional ROE based on year-
9 end 2023 financial results utilizing the Commission-
10 approved methodology from previous PCA filings .
11 IV. NET CUSTOMER IMPACT
12 Q. What is the revenue impact of the requested
13 PCA rate when compared with PCA rates currently in effect?
14 A. Attachment 2 to the Application filed
15 contemporaneously with my testimony provides a detailed
16 description of the overall revenue impact of this filing on
17 each customer class . As shown in Attachment 2, applying the
18 requested PCA rates to expected customer sales for the June
19 2024 through May 2025 test year results in a PCA decrease
20 of $35 . 7 million .
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 30
Idaho Power Company

1 Q. Please summarize the Company' s request in this
2 filing.
3 A. If approved, the 2024-2025 PCA will result in
4 a decrease in total billed revenue of approximately $35 . 7
5 million, or 2 . 31 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 Nos . 30715, 33307, and 34071 .
9 V. COMPLIANCE WITH PRIOR ORDERS
10 Q. Please describe the topics discussed in Idaho
11 Power' s 2023 PCA filing (Order No. 35804) that the Company
12 is addressing in this filing.
13 A. Idaho Power is addressing two issues that were
14 discussed in Order No. 35804 . The first is the outcome of
15 damage claims for Hells Canyon Unit No . 3 . The second is
16 regarding the Company' s coal supply management in the 2022-
17 2023 PCA Year.
18 Q. What was the Commission' s order regarding
19 Hells Canyon Unit No. 3?
20 A. Idaho Power was directed to notify the
21 Commission of any outcome on the Hells Canyon Unit No . 3
22 damage claim.
23 Q. Please summarize the issues that led to Idaho
24 Power seeking damage claims for Hells Canyon Unit No. 3 .
BRADY, DI 31
Idaho Power Company

1 A. Hells Canyon Unit No. 3 failed due to a phase-
2 to-phase stator on June 23, 2020 . The likely root cause was
3 degraded coil insulation. At the time of the failure, Idaho
4 Power had already planned for scheduled maintenance from
5 August 2021 to December 2021 and was under contract with
6 Alstom Renewable US ("General Electric") . Because General
7 Electric did not meet the completion dates for the project,
8 Idaho Power withheld delay liquidated.
9 Q. Were the delay liquidated damages that Idaho
10 Power received included in this year' s PCA filing as an
11 offset to power supply costs?
12 A. Yes . The majority of delay liquidated damages
13 were included as an offset to power supply costs in the
14 2023-2024 PCA Year. However, a portion was also recorded to
15 offset labor costs that would not have otherwise occurred.
16 The Company has provided additional detail on the delay
17 liquidated damage amounts in Confidential Exhibit No. 5 .
18 Q. What was the Commission' s order regarding
19 Idaho Power' s coal supply management in the 2022-2023 PCA
20 Year?
21 A. Order No. 35804 directed Commission Staff to
22 investigate the prudency of the Company' s power supply
23 expenses related to coal supply issues and report its
24 assessment to the Commission within six months of the
25 Commission' s final order.
BRADY, DI 32
Idaho Power Company

1 Q. Did Commission Staff provide a report
2 detailing its investigation?
3 A. Yes . On November 30, 2023, Commission Staff
4 filed a confidential report that recommended an adjustment
5 to NPSE be considered in the 2024 PCA filing. Staff also
6 recommended that Idaho Power include Staff' s report and a
7 response to Staff' s report as a part of the 2024 PCA
8 filing.
9 Q. Has Idaho Power included a response to Staff' s
10 report with this filing?
11 A. Yes . Idaho Power has included both Staff' s
12 report and its response to Staff' s report as Confidential
13 Attachments 3 and Attachment 4 to this filing,
14 respectively.
15 Q. What can be concluded from the information
16 contained in Attachment 4?
17 A. The information contained in Attachment 4
18 demonstrates that Idaho Power' s management of its available
19 coal supply during the 2022-2023 PCA Year was reasonable
20 and prudent based on the information available to the
21 Company at the time . The Company does not agree that an
22 adjustment to NPSE is reasonable under the circumstances
23 presented. To the contrary, as more fully described in
24 Attachment 4, the Company moved expeditiously and
25 judiciously to mitigate the challenges that arose from
BRADY, DI 33
Idaho Power Company

1 sustained market volatility and limited coal inventories in
2 the region.
3 Q. Are there any other issues stemming from the
4 Company' s 2023 General Rate Case that the Company is
5 addressing in this filing?
6 A. Yes . In the 2023 General Rate Case settlement
7 stipulation, parties agreed to discuss the annual tracking
8 of third-party point-to-point wheeling revenues in a
9 separate proceeding.
10 Q. Has Idaho Power discussed a proposed wheeling
11 revenue tracking mechanism with Staff?
12 A. Yes . Idaho Power provided its proposed
13 wheeling revenue tracking mechanism to Staff on March 28,
14 2024, and has been engaged in continuing discussions with
15 Staff regarding the mechanism. Idaho Power will continue to
16 work with Staff and make a filing detailing the proposal as
17 soon as possible .
18 Q. Does this conclude your testimony?
19 A. Yes, it does .
20
21
22
23
24
BRADY, DI 34
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 Senior Regulatory Analyst in
6 the 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 2024, at Boise, Idaho.
17
18 Signed:
BRADY, DI 35
Idaho Power Company

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-24-17
IDAHO POWER COMPANY
BRADY, DI
TESTIMONY
EXHIBIT NO. 1

IDAHO POWER PCA FORECAST
APRIL 1,2024-MARCH 31,2025
Line No. FERC Account April May June July August September October November December January February March Annual
95%Sharing Accounts
1 Hydroelectric Generation(MWh) 984,013 1,014,012 840,054 580,097 533,664 525,889 376,759 368,488 490,260 498,374 469,152 612,417 7,293,179
Account 536,Water for Power
2 Total Expense $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
Account 501,Coal
Jim Bridger
3 Energy(MWh) 90,468 32,238 145,785 245,367 245,367 237,452 245,367 237,452 245,367 245,367 221,622 225,522 2,417,371
4 Total Expense $ 2,871,016 $ 945,751 $ 4,603,392 $ 7,898,826 $ 7,943,000 $ 7,693,577 $ 7,951,834 $ 7,692,152 $ 7,947,417 $ 8,334,677 $ 7,660,886 $ 7,854,302 $ 79,396,827
North Valmy
5 Energy(MWh) (0) - - 56,892 87,108 80,561 87,104 84,294 87,104 87,104 78,674 (0) 648,841
6 Total Expense $ 332,698 $ 332,698 $ 332,698 $ 3,293,293 $ 4,877,353 $ 4,505,872 $ 4,860,741 $ 4,682,835 $ 4,825,208 $ 4,855,438 $ 4,447,480 $ 332,698 $ 37,679,017
Account 547,Other Fuel
Langley Gulch
7 Energy(MWh) 174,453 28,052 207,200 210,704 211,056 208,320 41,718 215,505 227,040 226,896 202,080 120,492 2,073,516
8 Total Expense $ 2,613,583 $ 741,628 $ 3,069,456 $ 5,672,395 $ 5,410,032 $ 5,221,659 $ 1,061,272 $ 7,944,304 $ 10,443,023 $ 11,057,701 $ 9,613,294 $ 3,649,775 $ 66,398,122
Bridger Gas
9 Energy(MWh) - - - 147,766 81,537 83,441 84,223 - 154,144 137,923 32,497 - 721,530
10 Total Expense -$33,476 -$33,476 -$33,476 $4,595,181 $2,828,501 $2,549,886 $2,486,104 $291,204 $11,604,917 $10,467,898 $2,318,886 $301,830 $ 37,343,977
Danskin
11 Energy(MWh) - - - 120,680 121,032 44,016 78,816 - 51,440 56,744 8,352 - 481,080
12 Total Expense $ 188,260 $ 188,260 $ 181,598 $ 5,495,380 $ 5,257,425 $ 2,031,590 $ 3,096,800 $ 181,598 $ 3,803,819 $ 4,398,665 $ 867,110 $ 188,260 $ 25,878,765
Bennett Mountain
13 Energy(MWh) - - - 118,488 125,496 - 41,496 41,112 32,336 - - - 358,928
14 Total Expense $ 92,724.99 $ 92,724.99 $ 89,443.76 $ 5,277,150.27 $ 5,324,428.59 $ 89,443.76 $ 1,608,948.27 $ 2,442,656.48 $ 2,385,670.75 $ 92,724.99 $ 92,724.99 $ 92,724.99 $ 17,681,367
Account 555,Purchased Power Non-PURPA
15 Energy(MWh) 154,437 95,729 206,462 203,717 138,109 89,501 77,522 169,317 100,158 92,938 121,704 128,377 1,577,970
16 Total Expense $ 7,247,733 $ 3,873,409 $ 8,205,246 $ 12,155,377 $ 7,780,932 $ 4,681,890 $ 5,038,880 $ 13,197,004 $ 8,771,299 $ 6,679,661 $ 8,160,739 $ 5,016,979 $ 90,809,149
Account 565,3rd Party Transmission
17 Total Expense $ 484,900 $ 642,929 $ 979,873 $ 1,588,903 $ 1,413,041 $ 763,336 $ 1,063,909 $ 675,368 $ 735,071 $ 773,786 $ 810,920 $ 486,974 $ 10,419,009
Account 447,Surplus Sales
18 Energy(MWh) (504,188) (114,532) (114,102) (48,368) (49,256) (135,907) (57,956) (17,855) (68,817) (78,661) (56,303) (60,179) (1,306,125)
19 Total Expense $ (20,401,610) $ (4,333,683) $ (5,979,539) $ (4,029,466) $ (4,873,012) $ (12,237,123) $ (3,550,765) $ (2,821,347) $ (8,233,743) $ (7,219,658) $ (6,810,908) $ (5,564,599) $ (86,055,453)
100%Sharing Accounts
Account 555,PURPA
20 Energy(MWh) 287,513 300,952 296,853 281,342 269,878 229,994 221,701 171,622 188,068 200,471 228,193 244,581 2,921,156
21 Total Expense $ 15,984,371 $ 16,481,737 $ 21,588,102 $ 24,318,489 $ 24,037,578 $ 17,360,119 $ 16,703,289 $ 15,726,756 $ 17,639,259 $ 16,286,900 $ 18,511,882 $ 14,955,194 $ 219,593,677
Account 555,Demand Response Incentives
22 Total Expense $ $ $ 270,468 $ 3,047,657 $ 4,657,950 $ 1,277,208 $ 184,487 $ 973,763 $ $ $ $ $ 10,411,533
95%Sharing Accounts $ (6,604,171) $ 2,450,240 $ 11,448,693 $ 41,947,040 $ 35,961,700 $ 15,300,131 $ 23,617,722 $ 34,185,774 $ 42,282,682 $ 39,440,893 $ 27,161,132 $ 12,358,944 $ 279,550,780
100%Sharing Accounts $ 15,984,371 $ 16,481,737 $ 21,858,570 $ 27,366,146 $ 28,695,528 $ 18,637,327 $ 16,887,776 $ 16,700,519 $ 17,639,259 $ 16,286,900 $ 18,511,882 $ 14,955,194 $ 230,005,210
23 Total Net Power Supply Expense $ 9,413,676 $ 18,965,452 $ 33,340,739 $ 64,718,005 $ 61,828,727 $ 31,387,572 $ 38,019,395 $ 50,595,089 $ 48,317,024 $ 45,259,895 $ 43,354,129 $ 27,012,309 $ 509,555,990
24 Total Generation(MWh) 1,690,885 1,470,982 1,696,354 1,965,052 1,813,247 1,499,162 1,254,705 1,287,790 1,575,915 1,545,816 1,362,273 1,331,390 18,493,571
25 Total Load(MWh) 1,186,696 1,356,450 1,582,253 1,916,684 1,763,991 1,363,255 1,196,749 1,269,935 1,507,098 1,467,155 1,305,970 1,271,211 17,187,446
Exhibit No. 1
Case No.IPC-E-24-17
J.Brady,IPC
Page 1 of 1

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-24-17
IDAHO POWER COMPANY
BRADY, DI
TESTIMONY
EXHIBIT NO. 2

Power Cost Adjustment
April 2023 thru March 2024
April May June July August September October November December January February March Totals
Idaho Jurisdiction Net Power Supply Expense(Non-OF)
Actual Non-QF
Fuel Expense-Coal 2,221,982.74 3,006,071.09 3,437,223.59 12,886,895.53 11,461,334.14 7,444,181.67 15,680,984.56 8,559,225.36 13,738,240.92 10,268,546.59 6,808,703.71 4,172,539.41 99,685,929.31
Fuel Expense-Gas 7,084,049.35 5,632,516.53 9,664,980.87 16,368,505.15 15,390,577.21 8,095,915.38 4,831,072.03 14,413,078.28 26,189,452.80 38,423,877.14 15,831,447.36 9,968,343.12 171,893,815.22
Non-Firm Purchases 13,612,936.00 12,063,983.02 17,058,770.81 30,288,116.14 26,184,632.46 11,304,712.44 11,979,506.45 17,926,344.45 15,702,529.69 38,520,410.04 15,102,861.53 8,985,321.92 218,730,124.95
Third Party Transmission 716,175.77 602,066.71 535,012.88 1,176,942.34 1,008,219.06 768,675.58 1,746,235.99 849,206.95 904,819.59 751,248.84 787,301.02 777,689.06 10,623,593.79
Surplus Sales&Transmission Losses (14,249,788.30) (13,613,311.21) (11,301,514.81) (1,879,447.33) (5,179,737.42) (5,343,609.05) (9,474,443.50) (14,859,598.98) (9,842,557.98) (42,573,490.54) (18,602,476.72) (13,835,943.58) (160,755,919.42)
Water for Power(Leases)
Total Actual NPSE $ 9,385,355.56 7,691,326.14 19,394,473.34 58,841,011.83 48,865,025.45 22,269,876.02 24,763,355.53 26,888,256.06 46,692,485.02 45,390,592.07 19,927,836.90 10,067,949.93 340,177,543.85
Idaho Allocation 95.7% 95.8% 95.7% 96.4% 95.9% 96.2% 95.9% 95.4% 95.4% 95.5% 95.7% 95.9
Net Idaho Jurisctional Actual Non-QF $ 8,981,785.27 7,368,290.44 18,560,510.99 56,722,735.40 46,861,559.41 21,423,620.73 23,748,057.95 25,651,396.28 44,544,630.71 43,348,015.43 19,070,939.91 9,655,163.98 325,936,706.50
Base Non-QF
Fuel Expense-Coal $ 7,525,242.00 7,487,643.00 9,019,153.00 11,385,255.00 12,185,412.00 10,796,845.00 7,781,442.00 7,302,324.00 8,455,019.00 5,483,866.09 5,225,193.36 4,796,697.48 97,444,091.93
Fuel Expense-Gas $ 2,314,209.00 2,302,646.00 2,773,625.00 3,501,263.00 3,747,333.00 3,320,312.00 2,392,997.00 2,245,656.00 2,600,139.00 10,014,265.74 9,541,895.08 8,759,404.84 53,513,745.65
Non-Firm Purchases $ 4,342,083.00 4,320,388.00 5,204,073.00 6,569,319.00 7,031,012.00 6,229,805.00 4,489,910.00 4,213,459.00 4,878,566.00 8,324,601.37 7,931,931.79 7,281,467.80 70,816,615.95
Third Party Transmission $ 378,398.00 376,507.00 453,517.00 572,494.00 612,729.00 542,907.00 391,281.00 367,189.00 425,151.00 858,960.68 818,443.70 751,326.61 6,548,904.00
Surplus Sales $ (3,588,093.00) (3,570,166.00) (4,300,402.00) (5,428,577.00) (5,810,099.00) (5,148,019.00) (3,710,251.00) (3,481,805.00) (4,031,418.00) (2,903,030.97) (2,766,095.65) (2,539,259.91) (47,277,216.54)
Water for Power(Leases) $ 165,106.00 164,281.00 197,883.00 249,796.00 267,352.00 236,886.00 170,727.00 160,216.00 185,506.00 0.00 0.00 0.00 1,797,753.00
Idaho Base NPSE $ 11,136,945.00 11,081,299.00 13,347,849.00 16,849,550.00 18,033,739.00 15,978,736.00 11,516,106.00 10,807,039.00 12,512,963.00 21,778,662.91 20,751,368.28 19,049,636.81 182,843,894.00
Idaho Allocation 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.57% 95.57% 95.57
Net Idaho Jurisdiction 95%Items $ 10,580,097.75 10,527,234.05 12,680,456.55 16,007,072.50 17,132,052.05 15,179,799.20 10,940,300.70 10,266,687.05 11,887,314.85 20,813,868.14 19,832,082.66 18,205,737.90 174,052,703.40
Idaho Jurisdiction Change From Base $ (1,598,312.48) (3,158,943.61) 5,880,054.44 40,715,662.90 29,729,507.36 6,243,821.53 12,807,757.25 15,384,709.23 32,657,315.86 22,534,147.29 (761,142.75) (8,550,573.92) 151,884,003.10
Sharing Percentage 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0
Net Power Supply Expense Deferral U $ (1,518,396.86) (3,000,996.43) 5,586,051.72 38,679,879.76 28,243,031.99 5,931,630.45 12,167,369.39 14,615,473.77 31,024,450.07 21,407,439.93 (723,085.61) (8,123,045.22) 144,289,802.96
Idaho Jurisdictional Qualifying Facility NPSE
Actual OF(Includes Net Metering,Raft River 100%&Liquidated Damages) $ 16,401,337.57 13,300,989.58 17,636,195.14 23,467,171.34 22,980,416.01 17,241,806.00 16,357,011.20 13,643,091.85 15,759,446.92 17,281,218.32 16,967,890.11 12,465,314.51 203,501,888.55
Idaho Allocation 95.7% 95.8% 95.7% 96.4% 95.9% 96.2% 95.9% 95.4% 95.4% 95.5% 95.7% 95.9
Idaho Jurisctional Actual OF $ 15,696,080.05 12,742,348.02 16,877,838.75 22,622,353.17 22,038,218.95 16,586,617.37 15,686,373.74 13,015,509.62 15,034,512.36 16,503,563.50 16,238,270.84 11,954,236.62 194,995,922.99
Base QF $ 9,283,440.00 9,237,057.00 11,126,388.00 14,045,307.00 15,032,413.00 13,319,420.00 9,599,498.00 9,008,440.00 10,430,450.00 17,948,022.13 17,101,417.96 15,699,003.40 151,830,856.49
Idaho Allocation 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.57% 95.57% 95.57
Idaho Jurisdictional Base $ 8,819,268.00 8,775,204.15 10,570,068.60 13,343,041.65 14,280,792.35 12,653,449.00 9,119,523.10 8,558,018.00 9,908,927.50 17,152,924.75 16,343,825.15 15,003,537.55 144,528,579.80
Idaho Jurisdiction Change From Base $ 6,876,812.05 3,967,143.87 6,307,770.15 9,279,311.52 7,757,426.60 3,933,168.37 6,566,850.64 4,457,491.62 5,125,584.86 (649,361.25) (105,554.31) (3,049,300.93) 50,467,343.19
Sharing Percentage 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0
OF Deferral(2) $ 6,876,812.05 3,967,143.87 6,307,770.15 9,279,311.52 7,757,426.60 3,933,168.37 6,566,850.64 4,457,491.62 5,125,584.86 (649,361.25) (105,554.31) (3,049,300.93) 50,467,343.19
Idaho Revenue Adjustment(SBAR)
Actual Idaho Jurisdictional Billing Month Sales MWh 1,079,076 1,078,897 1,243,540 1,506,736 1,665,023 1,405,767 1,074,008 1,009,195 1,144,193 1,229,509 1,200,336 1,114,051 14,750,331
Normalized Idaho Jurisdictional Billing Month Sales MWh 947,192 953,286 1,131,686 1,370,142 1,428,766 1,300,608 1,045,495 957,864 1,081,014 1,263,248 1,210,192 1,106,864 13,796,357
Sales Change MWh 131,884 125,611 111,854 136,594 236,257 105,159 28,513 51,331 63,179 (33,739) (9,856) 7,187 953,974
•of Prior Period Billings at Old Rate-effective thru 12/2023 $26.72 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 58.425% 0.786% 0.000
•of Current Period Billings at New Rate-effective 01/2024 $30.90 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 0.000% 41.600% 99.200% 100.000
Sales Adjustment Prior To Sharing@ $ (3,523,950.16) (3,356,314.10) (2,988,746.58) (3,649,793.13) (6,312,780.62) (2,809,857.48) (761,859.82) (1,371,567.66) (1,688,151.06) 960,407.85 304,189.30 (222,064.65) (25,420,488.11)
Sharing Percentage 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0
Idaho Revenue Adjustment(SBAR) $ (3,347,752.65) (3,188,498.40) (2,839,309.25) (3,467,303.47) (5,997,141.59) (2,669,364.61) (723,766.83) (1,302,989.28) (1,603,743.51) 912,387.46 288,979.84 (210,961.42) (24,149,463.71)
Idaho Jurisdiitional Demand Response Incentive Payments
Idaho Actual Demand Response $ 90.32 103.84 190,860.22 2,459,729.26 2,713,656.90 1,850,742.44 1,212,407.52 27,315.09 - - - - 8,454,905.59
Idaho Base Demand Response $ 780,401.00 776,502.00 935,327.00 1,180,702.00 1,263,682.00 1,119,681.00 806,970.00 757,284.00 876,823.00 857,024.33 816,598.69 749,632.90 10,920,627.92
Change From Base $ (780,310.68) (776,398.16) (744,466.78) 1,279,027.26 1,449,974.90 731,061.44 405,437.52 (729,968.91) (876,823.00) (857,024.33) (816,598.69) (749,632.90) (2,465,722.33)
Sharing Percentage 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0
Change From Base® $ (780,310.68) (776,398.16) (744,466.78) 1,279,027.26 1,449,974.90 731,061.44 405,437.52 (729,968.91) (876,823.00) (857,024.33) (816,598.69) (749,632.90) (2,465,722.33)
Idaho Miscellaneous Revenue
System Emission Allowance Sales Credit $ - - - - - - - - - - - - -
SystemRenewableEnergyCreditSales $ (630,210.04) (259,069.46) 335.82 (364,192.90) (1,649,463.00) (84,934.41) (163,816.01) (28,547.22) (3,835,483.45) (6,144,859.78) (5,124,642.59) (159,687.15) (18,444,570.19)
Revenue Subtotal $ (630,210.04) (259,069.46) 335.82 (364,192.90) (1,649,463.00) (84,934.41) (163,816.01) (28,547.22) (3,835,483.45) (6,144,859.78) (5,124,642.59) (159,687.15) (18,444,570.19)
Idaho Allocation 95.7% 95.8% 95.7% 96.4% 95.9% 96.2% 95.9% 95.4% 95.4% 95.5% 95.7% 95.9
Sharing Percentage 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0
Miscellaneous Revenue Deferral U $ (572,955.46) (235,779.12) 305.31 (333,527.86) (1,502,743.27) (77,621.56) (149,244.58) (25,872.35) (3,476,098.65) (5,574,924.04) (4,659,068.81) (145,482.98) (16,753,013.37)
Exhibit No.2
Case No.IPC-E-24-17
J.Brady,IPC
Page 1 of 2

Idaho EIM Participation Costs
Return on EIM Capital Investment $ 28,871.58 28,222.16 27,572.73 26,923.30 26,273.88 25,624.45 24,975.02 24,325.60 23,676.17 - - - 236,464.90
Operating Expenses $ 167,711.80 184,168.76 174,913.14 183,130.19 215,392.32 262,228.23 212,616.66 155,300.39 164,197.09 - - - 1,719,658.58
Revenue Subtotal $ 196,583.38 212,390.91 202,485.87 210,053.50 241,666.20 287,852.68 237,591.68 179,625.99 187,873.26 0.00 0.00 0.00 1,956,123.47
Sharing Percentage 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 0.0% 0.0% 0.0%
EIM Revenue Requirement© $ 186,754.21 201,771.37 192,361.58 199,550.82 229,582.89 273,460.05 225,712.10 170,644.69 178,479.60 0.00 0.00 0.00 1,858,317.31
TOTAL DEFERRAL(Sum of(j)-©) $ 844,150.61 (3,032,756.87) 8,502,712.73 45,636,938.03 30,180,131.52 8,122,334.14 18,492,358.24 17,184,779.54 30,371,849.37 15,238,517.77 (6,015,327.58) (12,278,423.45) 153,247,264.05
PCA Forecasted Revenues
Actual Idaho Jurisdictional Billing Month Sales MWh 1,079,076 1,078,897 1,243,540 1,506,736 1,665,023 1,405,767 1,074,008 1,009,195 1,144,193 1,229,509 1,200,336 1,114,051 14,750,331
•of Prior Period Billings at Old Rate 100.000% 100.000% 58.321% 1.563% 0.000% 0.000% 0.000% 0.000% 0.000% 58.425% 0.786% 0.000%
•of Current Period Billings at New Rate 0.000% 0.000% 41.700% 98.400% 100.000% 100.000% 100.000% 100.000% 100.000% 41.600% 99.200% 100.000%
Forecast Rate Revenues(,7) (12,259,386.52) (12,257,343.81) (15,642,099.90) (21,950,132.14) (24,262,717.74) (20,489,411.26) (15,652,952.14) (14,707,632.03) (16,673,307.14) (12,700,800.30) (4,216,873.09) (3,844,373.82) (174,657,029.89)
PCA Balancing Account Balance
Monthly Interest Rate 2%for 2023 and 5%for 2024 % 0.1667% 0.1667% 0.1667% 0.1667% 0.1667% 0.1667% 0.1667% 0.1667% 0.1667% 0.4167% 0.4167% 0.4167% 2.7500%
Beginning Balance $ 190,205,568.62 176,366,072.47 158,628,085.50 146,720,978.03 161,097,764.80 156,699,273.09 135,654,963.94 131,890,644.72 128,177,579.55 134,815,898.27 130,106,737.33 112,709,561.34 190,205,568.62
2023-2024 Incremental Deferral(Sum of 1O-©above 844,150.61 (3,032,756.87) 8,502,712.73 45,636,938.03 30,180,131.52 8,122,334.14 18,492,358.24 17,184,779.54 30,371,849.37 15,238,517.77 (6,015,327.58) (12,278,423.45) 153,247,264.05
2023-2024 PCA Forecast Revenues(Collections)0 above (12,259,386.52) (12,257,343.81) (15,642,099.90) (21,950,132.14) (24,262,717.74) (20,489,411.26) (15,652,952.14) (14,707,632.03) (16,673,307.14) (12,700,800.30) (4,216,873.09) (3,844,373.82) (174,657,029.89)
2023-2024 PCA Prior Balance Revenues(Collections) (2,741,269.52) (2,741,829.74) (5,032,100.44) (9,554,554.08) (10,584,401.76) (8,938,397.49) (6,829,816.93) (6,410,030.42) (7,273,852.81) (7,808,611.32) (7,707,086.73) (7,085,199.72) (82,707,150.96)
Revenue Sharing-Order No.
DSM Rider Forecasted Surplus Funds-Order No.
2023-2024 Ending Balance Without Current Month Interest 176,049,063.19 158,334,142.05 146,456,597.89 160,853,229.84 156,430,776.82 135,393,798.48 131,664,553.11 127,957,761 81 134,602,268.97 129,545,004.42 112,167,449.93 89,501,564.35 86,088,651 82
Current Month Interest 317,009.28 293,943.45 264,380.14 244,534.96 268,496.27 261,165.46 226,091.61 219,817.74 213,629.30 561,732.91 542,111.41 469,623.17 3,882,535.70
2023-2024 Ending Deferral Balance $ 176,366,072.47 158,628,085.50 146,720,978.03 161,097,764.80 156,699,273.09 135,654,963.94 131,890,644.72 128,177,579.55 134,815,898.27 130,106,737.33 112,709,561.34 89,971,187.52 89,971,187.52
Tab is 100%locked down,with no manual inputs.
Idaho Billed Sales MWh 1,079,076 1,078,897 1,243,540 1,506,736 1,665,023 1,405,767 1,074,008 1,009,195 1,144,193 1,229,509 1,200,336 1,114,051 14,750,331
Oregon Billed Sales MWh 48,403 47,674 55,881 56,914 70,809 56,024 46,374 48,778 55,179 58,434 53,656 47,133 645,259
Total MWh 1,127,479 1,126,570 1,299,421 1,563,650 1,735,832 1,461,792 1,120,381 1,057,973 1,199,372 1,287,943 1,253,992 1,161,184 15,395,590
Idaho%Billed Sales 95.7% 95.8% 95.7% 96.4% 95.9% 96.2% 95.9% 95.4% 95.4% 95.5% 95.7% 95.9%
Oregon%Billed Sales 4.3% 4.2% 4.3% 3.6% 4.1% 3.8% 4.1% 4.6% 4.6% 4.5% 4.3% 4.1%
Exhibit No.2
Case No.IPC-E-24-17
J.Brady,IPC
Page 2 of 2

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-24-17
IDAHO POWER COMPANY
BRADY, DI
TESTIMONY
EXHIBIT NO. 3

1 IDAHO POWER COMPANY
z
3 ADDITIONAL INVESTMENT TAX CREDIT ANALYSIS
4 For the Twelve Months Ended December 31,2023
5
s Actual September 30,2023 Actual December 31,2023
1 TOTAL TOTAL
8 SYSTEM IDAHO mxmo SYSTEM IDAHO IDAHO°
9 "'SUMMARY OF RESULTS'•'
10 TOTAL COMBINED RATE BASE 4,206,978,903 4,022,103,489 95.606% September Allocations/Ratios
11
12 DEVELOPMENT OF NET INCOME
13 OPERATING REVENUES
14 RETAIL SALES REVENUES(Ind 449.1 Rev) 1,131,444,961 1,084,202,950 Direct Assign 1,472,666,391 1,409,982,947 Direct Assign
15 OTHER OPERATING REVENUES 216,499,424 207,160,642 95.7% 285,571,483 273,253,253 95.7%
16 TOTAL OPERATING REVENUES 1,347,944,384 1,291,363,592 1,758,237,874 1,683,236,200
17
18 OPERATING EXPENSES
19 OPERATION&MAINTENANCE EXPENSES 904,132,356 863,119,398 95.5% 1,209,651,994 1,154,780,153 95.5%
20 DEPRECIATION EXPENSE 137,896,300 132,136,256 95.8% 187,945,683 180,095,035 95.8%
21 AMORTIZATION OF LIMITED TERM PLANT 3,994,103 3,827,696 95.8% 5,439,874 5,213,231 95.8%
22 TAXES OTHER THAN INCOME 21,599,657 19,903,828 92.1% 25,081,924 23,112,696 92.1%
23 REGULATORY DEBITS/CREDITS 1,384,615 1,146,334 82.8% 1,846,154 1,528,445 82.8%
24 PROVISION FOR DEFERRED INCOME TAXES (16,780,812) (16,131,902) 96.1% (22,518,627) (21,647,836) 96.1%
25 INVESTMENT TAX CREDIT ADJUSTMENT 10,660,148 10,204,953 95.7% 50,193,136 48,049,858 95.7%
26 FEDERAL INCOME TAXES 32,639,240 31,794,214 97.4% (4,035,971) (3,931,480) 97.4%
27 STATE INCOME TAXES 8,535,520 8,344,625 97.8% 319,336 312,194 97.8%
28 TOTAL OPERATING EXPENSES 1,104,061,128 1,054,345,402 1,453,923,503 1,387,512,294
29
30 OPERATING INCOME 243,883,256 237,018,190 304,314,371 295,723,906
31 ADD:IERCO OPERATING INCOME 5,742,172 5,490,626 95.6% 8,033,987 7,682,044 95.6%
32
33 OPERATING INCOME BEFORE OTHER INCOME AND DEDUCTION: 249,625,428 242,508,817 312,348,358 303,405,950 97.1%
34 ADD:AFUDC EQUITY 43,221,277 41,321,921 95.6%(L 10)
35 ADD:OTHER INCOME AND DEDUCTIONS 17,357,747 16,860,801 97.1%(L 33)
36
37 INCOME BEFORE INTEREST CHARGES 372,927,382 361,588,672
38 LESS:INTEREST CHARGES 116,116,912 111,014,162 95.6%(L 10)
39
4o NET INCOME 256,810,470 250,574,510
41
42 ACTUAL YEAR-END RESULTS-BEFORE ITC ADJUSTMENT
43 EARNINGS ON COMMON STOCK 256,810,470 250,574,510
44 COMMON EQUITY AT YEAR END 2,782,171,830 2,659,909,470 95.6%(1-10)
45
46 RETURN ON YEAR-END COMMON EQUITY 9.23% 9.42%
47
48 EARNINGS ON COMMON STOCK @ 9.40 ROE 261,524,152 250,031,490 (L44.9.4%)
49 EARNINGS ON COMMON STOCK @ 10 ROE 278,217,183 265,990,947 (L44 10%)
50 EARNINGS ON COMMON STOCK @ 10.50 ROE 292,128,042 279,290,494 (L44.10.5%)
51
52
53 ACTUAL YEAR-END RESULTS-AFTER ITC ADJUSTMENT:
54 INVESTMENT TAX CREDIT ADJUSTMENT (599,360)(1-48-1-43)/(1-9.4%)
55 ADJUSTED EARNINGS ON COMMON STOCK 249,975,150
56 ADJUSTED COMMON EQUITY AT YEAR-END 2,659,310,110
57 ADJUSTED RETURN ON YEAR-END COMMON EQUITY 9.40%
58
59 IF IDAHO RETURN ON COMMON EQUITY(Line 46)<9.4%
60 ADDITIONAL ITC ADJUSTMENT(Annualized) If L 54 is negative,then 0;if positive,then smaller of L54 or$25,000,000 0
61
62 IF IDAHO RETURN ON COMMON EQUITY(Line 46)>10%
63 IDAHO EARNINGS GREATER THAN 10%ROE BUT LESS THAN 10.5% 0 (L43-L49)/(1-10%)
64
65 IF IDAHO RETURN ON COMMON EQUITY(Line 46)>10.5%
66 INCREMENTAL IDAHO EARNINGS GREATER THAN 10.50%ROE 0 (1-43-1-50)/(1-10.5%)
67
68 Per Order#34071: After Tax Tax Gross Up
69 ROE between 10%-10.5%-CUSTOMER SHARE-80%(Reduction to rates) 0 -
70 ROE between 10%-10.5%-COMPANY SHARE-20% 0
71 ROE greater than 10.5%(Incremental)--CUSTOMER SHARE-55%(Reduction to rates) 0 -
ROE greater than 10.5%(Incremental)--CUSTOMER SHARE-25%(Offset to Pension balance) 0 -
72 ROE greater than 10.5%(Incremental)--COMPANY SHARE-20% 0
73 0
74
Exhibit No.3
Case No.IPC-E-24-17
J.Brady,IPC
Page 1 of 1

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-24-17
IDAHO POWER COMPANY
BRADY, DI
TESTIMONY
CONFIDENTIAL
EXHIBIT NO. 4

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-24-17
IDAHO POWER COMPANY
BRADY, DI
TESTIMONY
CONFIDENTIAL
EXHIBIT NO. 5