20230417IPC Direct Brady_Exhibits.pdf

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPANY FOR
AUTHORITY TO IMPLEMENT POWER
COST ADJUSTMENT (“PCA”) RATES
FOR ELECTRIC SERVICE FROM JUNE
1, 2023, THROUGH MAY 31, 2024.

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CASE NO. IPC-E-23-12

IDAHO POWER COMPANY

DIRECT TESTIMONY

OF

JESSICA G. BRADY
RECEIVED
Monday, April 17, 2023 3:46:07 PM
IDAHO PUBLIC
UTILITIES COMMISSION

BRADY, DI 1
Idaho Power Company
Q. Please state your name, business address, and 1
present position with Idaho Power Company (“Idaho Power” or 2
“Company”). 3
A. My name is Jessica G. Brady. My business 4
address is 1221 West Idaho Street, Boise, Idaho 83702. I 5
am employed by Idaho Power as a Regulatory Analyst in the 6
Regulatory Affairs Department. 7
Q. Please describe your educational background. 8
A. In May of 2016, I received a Bachelor of 9
Science degree in Economics and a Bachelor of Arts degree 10
in Spanish from the University of Idaho. I have also 11
attended “The Basics: Practical Regulatory Training for the 12
Electric Industry,” an electric utility ratemaking course 13
offered through New Mexico State University’s Center for 14
Public Utilities and “Electric Utility Fundamentals & 15
Insights,” an electric utility course offered through the 16
Western Energy Institute. 17
Q. Please describe your work experience. 18
A. In September 2021, I was hired as a Regulatory 19
Analyst in Idaho Power’s Regulatory Affairs Department. As 20
a Regulatory Analyst, I provide support for the Company’s 21
regulatory activities, including compliance reporting, 22
financial analysis, and the development of revenue 23
forecasts for regulatory filings. I am also responsible for 24
the Company’s power cost filings in both Idaho and Oregon. 25

BRADY, DI 2
Idaho Power Company
Prior to Idaho Power, I worked for five years at 1
Clearwater Analytics, a provider of investment accounting 2
and reporting software. I held various roles at Clearwater 3
Analytics but was primarily focused on customer success and 4
relationship management. I gained a breadth of knowledge in 5
investments and the use of proprietary software to 6
streamline the operations of a company’s finance and 7
accounting teams. I spent my last year at Clearwater 8
developing a training program focused on providing new 9
hires with the technical skills to be successful in an 10
operations role. 11
Q. What is the Company requesting in this case? 12
A. The Company is requesting approval of its 13
2023-2024 Power Cost Adjustment (“PCA”) rates to become 14
effective June 1, 2023. If approved, the 2023-2024 PCA 15
will result in an increase in total billed revenue of 16
approximately $200.2 million, or 14.68 percent. 17
Q. How is your testimony organized? 18
A. My testimony consists of four sections. In the 19
first section, I provide an overview of the PCA. In the 20
second section, I detail the 2023-2024 PCA amount in 21
comparison to last year’s PCA amount, identify and discuss 22
the main factors contributing to this change, and present 23
the quantification of the 2023-2024 PCA rates to become 24
effective June 1, 2023. In the third section, I discuss 25

BRADY, DI 3
Idaho Power Company
the additional PCA component related to revenue sharing. In 1
the final section, I detail the net customer impact of the 2
2023-2024 PCA rates if approved as filed. 3
I. PCA OVERVIEW 4
Q. What is the purpose of the PCA? 5
A. The PCA is a rate mechanism that quantifies 6
and tracks annual differences between actual Net Power 7
Supply Expenses (“NPSE”) and the normalized or “base level” 8
of NPSE recovered in the Company’s base rates, resulting in 9
a credit or surcharge that is updated annually on June 1. 10
The PCA mechanism uses a 12-month test period of April 11
through March (“PCA Year”) and includes a forecast 12
component and a Balancing Adjustment, formerly referred to 13
as the “true-up” and the “true-up of the true-up”. The 14
forecast component represents the difference between the 15
Company’s NPSE forecast from the March Operating Plan and 16
base level NPSE recovered in the Company’s base rates. The 17
Balancing Adjustment includes a backward-looking tracking 18
of differences between the prior PCA Year’s forecast and 19
actual NPSE incurred by the Company, and also tracks the 20
collection of the prior year’s Balancing Adjustment. 21
Q. How does the PCA mechanism function? 22
A. With the exception of Public Utility 23
Regulatory Policies Act of 1978 (“PURPA”) expenses and 24
demand response incentive payments, the PCA allows the 25

BRADY, DI 4
Idaho Power Company
Company to pass through to customers 95 percent of the 1
annual differences in actual NPSE as compared with base 2
level NPSE, whether positive or negative. With respect to 3
PURPA expenses and demand response incentive payments, as 4
actual annual expenses deviate from base level NPSE, the 5
Company is allowed to pass 100 percent of the difference 6
for recovery or credit through the PCA. The PCA is also 7
the rate mechanism used by the Company to provide customer 8
benefits resulting from the revenue sharing mechanism 9
approved by the Commission in Order No. 34071. 10
Q. Does the revenue collected from customers 11
through the annual PCA rate contribute toward the Company’s 12
earnings? 13
A. No. The PCA mechanism provides for the annual 14
collection or refund of net power supply cost differences 15
between actual costs incurred by the Company and the base 16
level NPSE component of base rates. Aside from the 95 17
percent to 5 percent sharing component I just described, 18
the PCA provides for a one-for-one collection or refund of 19
actual net power supply expenses incurred, or to be 20
incurred, to provide safe, reliable electric service to 21
customers. 22
Q. What are the components of the PCA base level 23
NPSE? 24
BRADY, DI 5
Idaho Power Company
A. The PCA base level NPSE includes the following1
Federal Energy Regulatory Commission (“FERC”) accounts: 2
Account 501, Fuel (coal); Account 536, Water for Power; 3
Account 547, Fuel (gas); Account 555, Purchased Power; 4
Account 565, Transmission of Electricity by Others; and 5
Account 447, Sales for Resale (typically referred to as 6
surplus sales). 7
The PCA base level expense component for FERC 8
Account 555 includes costs of both PURPA and non-PURPA 9
(market) purchases. Per Order No. 32426, the Company 10
adjusts FERC Account 555 to also include demand response 11
incentive payments that the Company provides to customers 12
who participate in any of its three demand response 13
programs. 14
II. 2023-2024 PCA15
Q. What is the total PCA collection that would16
result under the 2023-2024 PCA rates proposed by the 17
Company in this case? 18
A. The 2023-2024 PCA rates would result in total19
PCA collection of $408.2 million. This represents an 20
increase in total billed revenue of $200.2 million for the 21
upcoming year, an increase of 14.68 percent. 22
Q. Have you prepared a table that details the23
$200.2 million revenue impact by component? 24
BRADY, DI 6
Idaho Power Company
A. Yes. Table 1 presents a separation of the 1
$200.2 million increase into each component included in the 2
Company’s proposed rates. 3
Table 1 Revenue Impact by Component 
Line 
No. Rate Component 2022‐2023 PCA 2023‐2024 PCA Difference 
1 PCA Forecast   $           169,966,873  $        218,005,217   $      48,038,344  
2 PCA Balancing Adjustment   $             38,583,273    $        189,924,254   $    151,625,231  
3 PCA Total   $           208,550,146  $        408,213,721   $    199,663,575  
4 Revenue Sharing   $                (568,435)   $                  0     $            568,435  
5 Total Revenue Impact   $           207,981,710  $       408,213,721   $    200,232,011  
4
Q. What are the main factors driving the revenue5
change requested in this case? 6
A. The increase in this year’s PCA is driven by7
an increase in both the forecast component and the 8
Balancing Adjustment. The increase in this year’s forecast 9
component is attributed primarily to higher forecast market 10
energy and natural gas prices, combined with a limited coal 11
supply. 12
As can be seen on Table 1, the Balancing Adjustment 13
accounts for over 75 percent of the overall PCA revenue 14
change, indicating that last year’s actual power costs were 15
greater than forecast. Similar to the forecast component, 16
the increase in the Balancing Adjustment is largely 17
attributed to high natural gas and market energy prices 18
during the 2022-2023 PCA Year, combined with a limited coal 19

BRADY, DI 7
Idaho Power Company
supply. In addition, hydro generation was 9 percent lower 1
than forecast. 2
The price increases in both the natural gas and 3
energy markets, as well as the limited coal supply, will be 4
discussed in more detail later in this testimony. 5
A. PCA Forecast. 6
Q. How is the PCA forecast amount determined? 7
A. As described previously, the PCA forecast 8
component represents the difference between the Company’s 9
forecast of NPSE for the upcoming April – March test year 10
and base level NPSE recovered in the Company’s base rates. 11
Q. What is the Company’s determination of the 12
system-level difference between currently approved base 13
level NPSE1 and the forecast of NPSE for the 2023-2024 PCA 14
Year? 15
A. The system-level forecast of NPSE for the 16
2023-2024 PCA Year is $541,499,384, which is $235,814,515 17
higher than the currently approved base level NPSE of 18
$305,684,869. Table 2 presents the system-level 19
differences between currently approved base level NPSE and 20
the forecast of NPSE for the 2023-2024 PCA Year by FERC 21
account. 22
23

1 In the Matter of the Application of Idaho Power Company for
Authority to Establish a New Base Level of Net Power Supply Expense,
Case No. IPC-E-13-20, Order No. 33000 (March 21, 2014).

BRADY, DI 8
Idaho Power Company
Table 2 2023 ‐ 2024 PCA FORECAST (Total System) 

Line No. FERC Account Base NPSE Forecast Difference 
  95% Sharing Accounts     
1 Account 501, Coal   $           108,503,180    $     130,090,026   $        21,586,845  
2 Account 536, Water for Power   $               2,380,597    $                         0    $       (2,380,597) 
3 Account 547, Other Fuel   $             33,367,563    $     134,492,688    $     101,256,077  
4 Account 555, Purchased Power Non‐PURPA   $             62,606,593    $     123,485,717   $       60,886,095  
5 Account 565, 3rd Party Transmission    $               5,455,955    $         7,964,649    $         2,508,694  
6 Account 447, Surplus Sales    $         (51,735,153)   $    (84,191,539)   $    (32,456,386) 
       $          160,578,735    $    311,979,464    $    151,400,729  

  100% Sharing Accounts     
7 Account 555, PURPA   $          133,853,869    $     218,535,412    $      84,681,543  
8 Account 555, Demand Response Incentives   $            11,252,265    $     10,984,508    $         (267,757) 
9 Total   $          305,684,869    $   541,499,384  

$    235,814,515  
1
Q. What is the basis for the forecast of NPSE for 2
the 2023-2024 PCA Year? 3
A. The forecast of NPSE for the 2023-2024 PCA 4
Year is based on the Company’s March 2023 Operating Plan. 5
Q. How is the NPSE forecast developed for the 6
Company’s Operating Plan? 7
A. The Operating Plan is prepared monthly and 8
represents a forecast of the Company’s monthly NPSE for the 9
following 18-month period; however, for the PCA, the 10
Company includes only the 12 months that correspond to the 11
PCA Year. The Operating Plan is developed by simulating 12
the dispatch of the Company’s generation resources for each 13
month, segmented by heavy load and light load hours. The 14
dispatch considers a current forecast of forward market 15

BRADY, DI 9
Idaho Power Company
energy prices, available hydro generation, coal and natural 1
gas prices, and any existing hedge transactions. The 2
system load forecast is then analyzed against the resulting 3
monthly heavy load and light load dispatch to determine a 4
monthly load and resource balance. Any identified resource 5
deficiency is assumed to be filled with market energy 6
purchases or natural gas to fuel the Langley Gulch power 7
plant (“Langley Gulch”), based on economics and available 8
generating capacity at Langley Gulch. Economically 9
dispatched generation above the system load forecast 10
represents surplus energy sales. The forecast of monthly 11
NPSE and generation for the 2023-2024 PCA Year, as 12
determined in the Company’s March 2023 Operating Plan, is 13
provided in Exhibit No. 1. 14
Q. Did the Company make any adjustments to the 15
March 2023 Operating Plan, for purposes of quantifying 16
forecast NPSE for the 2023-2024 PCA Year? 17
A. Yes. Forecast NPSE in the March 2023 Operating 18
Plan includes the addition of a new power purchase 19
agreement (“PPA”), Black Mesa Solar. For purposes of 20
quantifying forecast NPSE for the 2023-2024 PCA Year for 21
this filing, the Company removed the forecasted expenses 22
associated with Black Mesa Solar, because Micron 23
Technology, Inc. (“Micron”) will be paying for 100 percent 24
of Black Mesa Solar’s generation according to the 25

BRADY, DI 10
Idaho Power Company
provisions of a new Energy Sales Agreement (“ESA”)2 between 1
Idaho Power and Micron. 2
Q. Please provide more information on the Black 3
Mesa Solar PPA and its treatment in the PCA forecast. 4
A. Black Mesa Solar is a 40 MW alternating 5
current solar photovoltaic generation facility, expected to 6
come online in June 2023. The PPA was negotiated in 7
conjunction with the Micron ESA, which states that Idaho 8
Power will procure renewable resources to assist Micron in 9
meeting a portion of its annual energy requirements with 10
energy generated by those resources. While the renewable 11
resource, Black Mesa Solar in this case, will not serve 12
Micron directly, and rather will be connected to the 13
Company’s system, Micron will pay for all of the output 14
through its ESA. 15
Because Micron will be paying for 100 percent of 16
Black Mesa Solar’s generation, the cost of the PPA was 17
removed from the Company’s calculation of forecast NPSE. 18
As recommended by Commission Staff in Order No. 35482, the 19
Company has provided Black Mesa Solar’s forecast generation 20
and expenses, as well as Micron’s monthly load forecast, as 21
Confidential Exhibit No. 4. 22

2 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, 2022).

BRADY, DI 11
Idaho Power Company
Q. How will the excess generation and renewable 1
capacity credit payments, as detailed in Micron’s ESA, be 2
incorporated into this year’s PCA filing? 3
A. In the event that Black Mesa Solar’s 4
generation exceeds Micron’s load in a given hour, the 5
Company will compensate Micron for the excess generation 6
according to the methodology approved by the Commission in 7
Order No. 35482. However, for the 2023-2024 PCA year, the 8
Company does not expect Black Mesa Solar’s generation to 9
exceed Micron’s load in any hour. As a result, no excess 10
generation payments are included in this year’s PCA 11
forecast. 12
In addition, as stated in Order No. 35482, the 13
Company will not begin renewable capacity credit payments 14
until July 1, 2026. As a result, no renewable capacity 15
credit payments are included in this year’s PCA forecast. 16
Q. How does the Company’s forecast of system-17
level NPSE for the 2023-2024 PCA compare to the system-18
level forecast included in last year’s PCA? 19
A. Table 3 below compares this year’s 2023-2024 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 2023-2024 PCA year is 23
$541,499,384, which is $52,004,084 higher than last year’s 24
forecast amount of $489,495,300. 25

BRADY, DI 12
Idaho Power Company
Table 3 PCA Forecast Comparison Expenses  (Total System) 

Line No. FERC Account 
2022‐2023     
Forecast 
2023‐2024 
Forecast Difference 
  95% Sharing Accounts     
1 Account 501, Coal   $      151,179,160    $        130,090,026    $     (21,089,135) 
2 Account 536, Water for Power   $                          0    $                            0    $                         0   
3 Account 547, Other Fuel   $        79,067,982    $        134,623,640    $       55,555,657  
4 Account 555, Purchased Power Non‐PURPA   $        98,482,808    $        123,492,688    $       25,009,880  
5 Account 565, 3rd Party Transmission    $          5,149,239    $            7,964,649    $         2,815,409  
6 Account 447, Surplus Sales   $     (65,085,848)   $       (84,191,539)   $    (19,105,691) 
     $     268,793,342    $       311,979,464    $       43,186,122  

  100% Sharing Accounts     
7 Account 555, PURPA   $     212,586,058    $        218,535,412    $         5,949,354  
8 Account 555, Demand Response Incentives   $          8,115,900    $          10,984,508    $         2,868,608  
       $     220,701,958  

$        229,519,920    $        8,817,962  

9 Total PCA Forecast 

$    489,495,300 

$        541,499,384    $      52,004,084  
1
Q. What general conclusions can be drawn from the 2
information contained in Table 3? 3
A. When viewed by category, the 95 percent 4
sharing accounts have increased approximately $43.2 million 5
from last year’s forecast, while the 100 percent sharing 6
accounts have increased approximately $8.8 million over 7
last year’s forecast. 8
Q. What factors are contributing to the major 9
differences presented in Table 3? 10
A. Forecast expenses included in the 95 percent 11
sharing accounts are expected to increase by 16 percent as 12
compared to last year, from $268,793,342 to $311,979,464. 13
Due to the limited coal supply, the Company expects to rely 14

BRADY, DI 13
Idaho Power Company
more on natural gas generation and purchased power to serve 1
load in the 2023-2024 PCA Year. 2
Q. Please explain the circumstances that led to 3
the Company’s limited coal supply. 4
A. Global natural gas supply and demand 5
disruptions over the last several months, stemming from the 6
Russian invasion of Ukraine and sabotage of the Nord Stream 7
pipelines, have caused price escalation and volatility in 8
the natural gas and energy markets. 9
As the same time, the U.S. has been ramping down its 10
coal production, limiting the supply of coal available to 11
the electric utility sector. Similarly, production 12
capabilities at Bridger Coal Company (“BCC”) have decreased 13
as a result of the closing of the underground mining 14
operations at the end of 2021. 15
As a result of the price escalation and volatility 16
in the natural gas and energy markets throughout 2022, 17
Idaho Power increased its reliance on coal-fired generation 18
to serve load. Actual coal-fired generation for the first 9 19
months of 2022 was 50 percent higher than the same period 20
in 2021, and 30 percent higher than the 5-year average for 21
the period. 22
The increase in coal-fired generation in 2022, 23
combined with the closure of the underground mine at BCC, 24
has resulted in a limited supply of coal available for use 25

BRADY, DI 14
Idaho Power Company
in 2023. Coal availability is expected to improve in 2024, 1
however, when Bridger Units 1 and 2 are converted to 2
natural gas fired units, thus reducing Idaho Power’s coal-3
fired fleet from 5 units to 3 units. 4
Q. How is Idaho Power working to limit the 5
customer impact of the current coal constraints at the 6
Bridger plant? 7
A. Idaho Power plans to use 100 percent of the 8
available production capacity from BCC through 2023. Idaho 9
Power is actively working with its operating partner at 10
BCC, PacifiCorp, to identify opportunities to maximize coal 11
production with existing infrastructure, resources, and 12
equipment. 13
In addition to utilizing 100 percent of available 14
production capacity at BCC, the Company has secured all 15
available coal from its primary third-party supplier, Black 16
Butte Coal Company, through 2023. 17
Idaho Power has also recently secured rail 18
transportation that will allow for approximately 200,000 19
tons of spot coal to be delivered from the Powder River 20
Basin (“PRB”) to the Bridger plant beginning in May 2023 21
through December 2023. While PRB coal has not been utilized 22
at Bridger as a base fuel supply source to date due to its 23
high propensity to spontaneously combust, the plant is 24
capable of consuming PRB coal on a limited scale. Idaho 25

BRADY, DI 15
Idaho Power Company
Power intends to rely on as much PRB coal as can be 1
delivered and burned safely at the plant in 2023. 2
Q. Has the Company and its partner considered 3
increasing the capacity to produce coal at BCC? 4
A. Yes. However, no feasible, cost-effective 5
methods of increasing coal production capacity in the short 6
term have been identified. Increasing coal production at 7
BCC to levels that would completely fill the shortfall in 8
supply would require new permits and additional investment 9
in capital infrastructure. Because the current coal supply 10
constraints are not expected to persist after the 11
conversion of Bridger Units 1 and 2 to natural gas, 12
additional investment to fill the near-term temporary 13
shortfall in coal supply would not provide a benefit to 14
customers in the long-term. 15
Q. What is Idaho Power doing to address coal 16
constraints at the Valmy plant? 17
A. At Valmy, Idaho Power is actively working to 18
secure additional coal supply for 2023, 2024, and 2025. 19
Solicitations made in a June 2022 Request for Proposal 20
(“RFP”) seeking 2023 coal volumes from spot coal suppliers 21
indicated minimal Western coal available and higher coal 22
prices. 23
As a result of the knowledge gained from the June 24
2022 RFP, Idaho Power, and its co-owner of Valmy, NV 25

BRADY, DI 16
Idaho Power Company
Energy, commissioned an independent engineering firm to 1
evaluate the performance capabilities of the current dry 2
sorbent injection system and feasibility of installing 3
activated carbon injection systems that would enhance 4
controls to allow Valmy to burn higher mercury and sulfur 5
coals. Based on information provided by the engineering 6
firm, Valmy plant specifications for mercury and sulfur 7
were refined. 8
In November 2022, NV Energy and Idaho Power issued a 9
new RFP seeking coal for 2023. Idaho Power has scheduled a 10
test burn for a new fuel source from this RFP, and a 11
contract is being negotiated with the supplier pending 12
finalization of rail transportation. Idaho Power expects 13
that this volume of additional coal, combined with existing 14
stockpile inventory, will provide fuel to operate Valmy 15
during the summer months of 2023, as well as the winter 16
months of 2023–24. 17
Q. Please elaborate on the changes in the 95 18
percent sharing accounts for this year’s forecast as 19
compared with last year’s forecast as presented in Table 3. 20
A. For the 2023-2024 PCA year, the average 21
forecast market purchase price is $76.01 per megawatt-hour 22
(“MWh”), compared to $49.11 per MWh last year, an increase 23
of 55 percent. In addition, the per-unit cost of natural 24
gas for the 2023-2024 PCA year is $41.27 per MWh, an 25

BRADY, DI 17
Idaho Power Company
increase of 33 percent compared to last year. As a result 1
of the limited coal supply, the per-unit cost of coal 2
generation has also increased from last year. The average 3
per-unit cost of coal-fired generation for the 2023-2024 4
PCA year is $36.95 per MWh, an increase of 24 percent 5
compared to last year. Accordingly, expenses from non-PURPA 6
purchased power are expected to increase 25 percent as 7
compared to last year’s forecast, natural gas expense is 8
expected to increase 70 percent, and coal fuel expense is 9
expected to decrease 14 percent. 10
The increase in forecast market energy prices is 11
also resulting in higher surplus sales revenue. Surplus 12
sales revenue is expected to increase 29 percent compared 13
to last year, from $65,085,848 to $84,191,539. For the 14
2023-2024 PCA Year, the average forecast market sales price 15
is $82.96 per MWh compared with $51.73 last year, a 60 16
percent increase. 17
Q. What factors are contributing to the change in 18
the 100 percent sharing accounts? 19
A. As can be seen in Table 3, forecast expenses 20
included in the 100 percent sharing accounts are expected 21
to increase by 4 percent as compared to last year, from 22
$220,701,958 to $229,519,920. Forecast PURPA costs 23
increased by $5.95 million as compared to last year’s 24

BRADY, DI 18
Idaho Power Company
forecast and forecast demand response incentive payments 1
increased by $2.9 million as compared to last year. 2
Q. Is the increase in forecast PURPA costs 3
related to increased generation output from PURPA projects? 4
A. In part. Table 4 details changes between last 5
year’s PCA forecast and this year’s PCA forecast with 6
respect to forecasted generation in MWh. As shown in Table 7
4, PURPA generation is anticipated to increase by 19,189 8
MWh, or less than 1 percent. The 3 percent increase in 9
PURPA expense is largely the result of price escalation in 10
PURPA contracts, for which the average cost is $71.47 per 11
MWh, compared to $69.96 last year. 12
Table 4 PCA Forecast Comparison Generation (Total System‐MWh) 

Line No. FERC Account 2022‐2023 Forecast 
2023‐2024 
Forecast Difference 
1 Hydro                5,972,743                 6,487,995                   515,252 

  95% Sharing Accounts     
2 Account 501, Coal                5,083,043                 3,520,905                 (1,562,138)  
3 Account 547, Other Fuel                2,556,322                 3,261,784                     705,462  
4 Account 555, Purchased Power Non‐PURPA                1,580,326                 1,695,683                     115,357  
  95% Sharing Accounts              15,192,435               14,966,367                  (226,068)  

  100% Sharing Accounts     
5 Account 555, PURPA                3,038,613                 3,057,802                     19,189  
  100% Accounts                3,038,613                 3,057,802                      19,189  

6 Total Generation              18,231,048               18,024,169                  (206,879)  

  95% Sharing Accounts     
7 Account 447, Surplus Sales                1,258,195                 1,014,817                     (243,978)  
8 Total Load              16,972,853               17,009,352  36,499  
13

BRADY, DI 19
Idaho Power Company
Q. What other general conclusions can be drawn 1
from the information in Table 4? 2
A. Compared to last year’s forecast, hydro 3
generation is expected to increase from 5,972,743 MWh to 4
6,487,995 MWh, or 9 percent. Due to the limited coal 5
supply, coal-fired generation is expected to decrease from 6
5,083,043 MWh to 3,520,905 MWh, or 31 percent. To offset 7
the reduction in coal-fired generation, natural gas 8
generation is expected to increase 28 percent compared to 9
last year. In addition, non-PURPA purchased power is 10
expected to increase 7 percent from last year. This 7 11
percent increase is due to an increase in PPA generation, 12
more specifically, the increased forecast generation from 13
Jackpot Solar, which came online in December 2022. 14
Q. What is causing the 9 percent increase in 15
expected hydro generation? 16
A. The increase in expected hydro generation is 17
mainly due to higher projected inflows into Brownlee 18
reservoir. The March Operating Plan used in this year’s 19
PCA forecast projects April through July inflows into 20
Brownlee of 4.3 million acre-feet (“MAF”) as compared to 21
2.9 MAF used to determine last year’s PCA forecast, an 22
increase of 69 percent. Expected inflows into Brownlee are 23
higher than last year’s PCA forecast as a result of better 24
snowpack conditions, which provide for sustained runoff and 25

BRADY, DI 20
Idaho Power Company
increased hydro generation during the spring and summer 1
months. Snowpack conditions used to determine this year’s 2
PCA hydro forecast are 117 percent of normal, compared to 3
76 percent of normal last year. 4
Q. How are the forecasted NPSE differences 5
presented in Table 2 used to determine the 2023-2024 PCA 6
forecast component to be collected from Idaho customers? 7
A. The 2023-2024 PCA forecast component reflects 8
the Idaho jurisdictional share of the forecasted NPSE 9
differences presented in Table 2, adjusted for the PCA 10
sharing provisions. The Idaho jurisdictional share of the 11
forecast NPSE differences is determined by applying a ratio 12
of forecast firm Idaho jurisdictional sales to forecast 13
firm system-level sales to the system-level NPSE 14
differences. 15
Q. Were any changes made to the Idaho 16
jurisdictional sales and system-level sales to account for 17
the portion of Micron’s load met by Black Mesa Solar? 18
A. Yes. The portion of Micron’s load forecast to 19
be met by Black Mesa Solar was removed from the total 20
forecast Idaho jurisdictional sales and system-level sales 21
and was not used in the derivation of the PCA rate. 22
Q. What is the Company’s forecast of system-level 23
firm sales and Idaho jurisdictional firm sales, net of the 24

BRADY, DI 21
Idaho Power Company
portion of Micron’s load met by Black Mesa Solar, for the 1
2023-2024 PCA Year? 2
A. For the 2023-2024 PCA Year, Idaho Power has 3
forecast system-level firm sales to be 15,684,447 MWh and 4
Idaho jurisdictional firm sales to be 14,982,736 MWh, or 5
95.52 percent of the system level. 6
Q. What is the Company’s determination of the 7
2023-2024 PCA forecast component to be collected from Idaho 8
customers? 9
A. The 2023-2024 PCA forecast component to be 10
collected from Idaho customers is $218,006,526. Table 5 11
presents the determination of the 2023-2024 PCA forecast 12
component by individual PCA expense and revenue category. 13
14
Table 5 2023‐2024 PCA FORECAST 

Line No. FERC Account Difference from Base 
Difference After 
Sharing Idaho Allocation 
  95% Sharing Accounts (From Table 1)    
1 Account 501, Coal   $     21,586,845    $      20,507,503   $       19,588,713  
2 Account 536, Water for Power   $     (2,380,597)   $      (2,261,567)  $       (2,160,243) 
3 Account 547, Other Fuel   $   101,256,077    $      96,193,273   $       91,883,560  
4 Account 555, Purchased Power Non‐PURPA   $     60,886,095    $      57,841,790   $       55,250,325  
5 Account 565, 3rd Party Transmission    $       2,508,694    $        2,383,259   $         2,276,483  
6 Account 447, Surplus Sales      $  (32,456,386)   $   (30,833,566)  $    (29,452,141) 
       $   151,400,729    $    143,830,692   $     137,386,697  

  100% Sharing Accounts     
7 Account 555, PURPA   $     84,681,543    $     84,681,543   $       80,887,586  
8 Account 555, Demand Response Incentives   $        (267,757)   $        (267,757)  $          (267,757) 
9 Total   $   235,814,515    $   228,244,478   $     218,006,526  
15

BRADY, DI 22
Idaho Power Company
B. Balancing Adjustment. 1
Q. What is this year’s quantification of the 2
Balancing Adjustment? 3
A. The Balancing Adjustment is detailed in the 4
PCA deferral report, attached hereto as Exhibit No. 2. This 5
report compares actual NPSE amounts to actual power cost 6
collections monthly, with the differences accumulated as a 7
deferral balance. The balance at the end of March 2023, 8
with interest applied, was $190,205,569 as shown on row 100 9
of Exhibit No. 2. The approximate $190 million represents 10
an increase to customer rates in this year’s PCA Balancing 11
Adjustment. 12
Q. To what factors do you attribute the 13
accumulation of the approximate $190 million deferral 14
balance? 15
A. The approximate $190 million deferral balance 16
was primarily driven by a decrease in actual hydro 17
generation from expected as well as higher than forecast 18
market purchases and natural gas generation, due to a 19
limited coal supply. 20
Actual hydro generation for the 2022-2023 PCA year 21
totaled 5,458,343 MWh, a 9 percent decrease from last 22
year’s forecast of 5,972,743 MWh. Actual purchased power 23
totaled 4,297,723 MWh, a 172 percent increase from last 24
year’s forecast. Actual natural gas generation totaled 25

BRADY, DI 23
Idaho Power Company
2,716,835 MWh, a 6 percent increase from last year’s 1
forecast. Lastly, actual surplus sales volumes totaled 2
1,455,119 MWh, an increase of 16 percent from last year. 3
Actual natural gas and market energy prices were 4
also higher than forecast, driving a 126 percent increase 5
in natural gas fuel expense and a 318 percent increase in 6
purchased power expense. 7
In addition, due to the limited coal supply, the 8
Company began optimizing its coal-fired generation dispatch 9
in October 2022. At a high level, this dispatch 10
optimization process involved reducing coal unit dispatch 11
during lower market price conditions to ensure the plants 12
were available to operate during high load and/or high 13
market price conditions. As a result, actual coal-fired 14
generation totaled 3,265,218 MWh, a decrease of 36 percent 15
compared to last year’s forecast. 16
Q. Please elaborate on the changes in actual 17
versus forecast generation and expense for the 2022-2023 18
PCA Year. 19
A. Last year’s PCA forecast included an average 20
market sales price of $51.73 per MWh. The actual average 21
market sales price for the 2022-2023 PCA year was $116.98 22
per MWh, a 126 percent increase. As a result of the 23
difference in forecast and actual market sales prices, as 24
well as economic opportunity during the spring and winter 25

BRADY, DI 24
Idaho Power Company
months of the 2022-2023 PCA year, actual surplus sales 1
volumes were 16 percent higher than forecast. Surplus sales 2
revenue totaled $170,224,982, which was 162 percent higher 3
than forecast revenues of $65,085,848. 4
As mentioned above, actual coal-fired generation for 5
the 2022-2023 PCA year was 36 percent lower than forecast. 6
Actual coal fuel expense totaled $94,955,998, which was 37 7
percent lower than forecast. Coal-fired generation was 8
lower than forecast due to the limited coal supply, as 9
discussed earlier in testimony. 10
Natural gas generation totaled 2,716,835 MWh for the 11
2022-2023 PCA Year, which was 6 percent higher than 12
forecast. Due to the increased natural gas prices, actual 13
natural gas expense totaled $178,317,313, which was 126 14
percent higher than forecast. While natural gas prices were 15
higher than forecast, the Company’s reliance on natural gas 16
generation increased 6 percent as it was needed to meet 17
load, as well as make off-system sales when it was 18
economic, as noted previously. 19
While both purchased power and surplus sales 20
increased, surplus sale volumes were highest in off-peak 21
spring and winter months, and purchased power was highest 22
in summer months, where hot temperatures caused 23
continuously higher than forecast peak loads. 24

BRADY, DI 25
Idaho Power Company
Q. Were there any items included in this year’s 1
Balancing Adjustment in addition to actual NPSE incurred 2
during the April 2022 through March 2023 period? 3
A. Yes. Per Commission Order No. 34100, Idaho 4
Power included its actual costs of Western Energy Imbalance 5
Market (“EIM”) participation for April 2022 through March 6
2023 in the Balancing Adjustment. Benefits associated with 7
EIM participation are embedded in actual NPSE experienced 8
over that same period. 9
Q. Please summarize the conditions of Order No. 10
34100 as they pertain to EIM cost recovery through the 2022 11
PCA. 12
A. Per the terms of the settlement stipulation 13
(“EIM Stipulation”) approved by Order No. 34100, Idaho 14
Power agreed to include an EIM-related monthly revenue 15
requirement in its monthly PCA deferral calculation based 16
on actual EIM participation costs commencing April 1, 2018. 17
The Company also agreed to apply a soft cap to EIM-related 18
revenue requirement included in the PCA deferral equal to 19
annual EIM benefits as reported by the California 20
Independent System Operator (“CAISO”) for the corresponding 21
period. 22
Q. Is the EIM-related revenue requirement 23
included in the April 2022 through March 2023 PCA deferral 24

BRADY, DI 26
Idaho Power Company
under the soft cap of annual CAISO-reported benefits for 1
that same period? 2
A. Yes. For the April 2022 through March 2023 3
period, the EIM-related revenue requirement totaled $2.5 4
million, while CAISO reported EIM benefits for Idaho Power 5
of approximately $37.7 million from April through December 6
(CAISO’s first quarter 2023 report has not yet been 7
published). Therefore, the Company’s EIM-related revenue 8
requirement is less than the soft cap agreed to in the EIM 9
Stipulation. 10
Q. Does Idaho Power believe the EIM has provided 11
net benefits to customers since joining in April 2018? 12
A. Yes. While Idaho Power believes the CAISO 13
benefit calculation overstates estimated benefits to Idaho 14
Power’s system, the Company believes customers have 15
realized significant net benefits since the Company’s entry 16
into the EIM in April 2018. As discussed in the Company’s 17
May 24, 2019, Report of EIM Benefits and Costs of 18
Participation, filed in Case No. IPC-E-16-19, Idaho Power 19
has developed a more precise methodology for determining 20
EIM benefits that uses inputs specific to the Company. 21
Based on this methodology, the Company believes benefits 22
achieved between April 2022 and December 2022 are 23
approximately $9 million (benefits for the first quarter of 24
2023 are not yet available). This level of EIM benefits 25

BRADY, DI 27
Idaho Power Company
compared to the Idaho-jurisdictional EIM costs of $2.5 1
million, demonstrates a net benefit to the Company and, 2
ultimately, its customers. 3
C. PCA Rate Determination. 4
Q. How is the rate for the forecast portion of 5
the PCA for April 2023 through March 2024 determined? 6
A. The rate for the forecast portion of the PCA 7
is equal to the sum of (1) 95 percent of the difference 8
between the non-PURPA 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 forecast of system 11
firm sales for June 1, 2023, through May 31, 20243 (“System-12
level Sales Forecast”); and (2) 100 percent of the 13
difference between PURPA-related expenses quantified in the 14
Operating Plan and those quantified in the Company’s last 15
approved update of NPSE, divided by the Company’s System-16
level Sales Forecast; and (3) 100 percent of the difference 17
between the Idaho jurisdictional demand response incentive 18
payments quantified in the Operating Plan and those 19
quantified in the Company’s last approved update of NPSE, 20
divided by the forecast of Idaho jurisdictional firm sales4 21
for June 1, 2023, through May 31, 2024. 22

3 System-level and Idaho jurisdictional firm sales used in the
calculation are net of Black Mesa Solar’s forecasted generation for the
June 2023 – May 2024 time period.
4 Id.

BRADY, DI 28
Idaho Power Company
Q. What is the rate for the forecast portion of 1
the PCA for April 2023 through March 2024? 2
A. The rate for non-PURPA expenses is 0.9183 3
cents per kilowatt-hour (“kWh”), which is calculated by 4
multiplying $151,400,729 from Table 2 by 95 percent and 5
then dividing it by the System-level Sales Forecast, net of 6
Black Mesa Solar generation, of 15,662,267 MWh 7
(($151,400,729 * 0.95) / 15,662,267) = $9.183 /MWh = 0.9183 8
cents/kWh). The rate for PURPA expenses is 0.5407 cents 9
per kWh, which is calculated by dividing $84,681,543 from 10
Table 2 by the 15,662,267 MWh ($84,681,543 / 15,662,267 MWh 11
= $5.407/MWh = 0.5407 cents/kWh). The rate for demand 12
response incentive payments is negative 0.0018 cents per 13
kWh, which is calculated by dividing the negative $267,757 14
from Table 2 by the forecast of Idaho jurisdictional firm 15
sales, net of Black Mesa Solar generation, of 14,960,556 16
MWh (-$267,757 / 14,960,556 MWh = -$0.0180/MWh = -0.0018 17
cents/kWh). The forecast portion of the PCA rate is 1.4572 18
cents per kWh, which is calculated by adding the non-PURPA 19
expense of 0.9183 cents per kWh to the PURPA expense of 20
0.5407 cents per kWh to the demand response incentive 21
payment of negative 0.0018 cents per kWh (0.9183 + 0. 5407 22
+ -0.0018 = 1.4572 cents/kWh). 23
Q. How did you compute this year’s Balancing 24
Account rate? 25

BRADY, DI 29
Idaho Power Company
A. As shown in Exhibit No. 2, this year’s 1
Balancing Adjustment of the PCA is approximately $190 2
million, which, when divided by the Company’s forecast of 3
Idaho jurisdictional sales, net of Black Mesa generation, 4
of 14,960,556 MWh, results in a rate of 1.2714 cents per 5
kWh ($190,205,569 / 14,960,556 = $12.714/MWh = 1.2714 6
cents/kWh). 7
Q. What is the resulting PCA rate when you 8
combine all the PCA components described previously? 9
A. The uniform PCA rate comprises (1) the 1.4572 10
cents per kWh for the 2023-2024 projected power cost of 11
serving firm loads under the current PCA methodology and 95 12
percent sharing, and (2) the 1.2714 cents per kWh for the 13
2022-2023 Balancing Adjustment of the PCA. The sum of these 14
two components is a 2.7286 cents per kWh charge for all 15
rate classes. 16
III. ADDITIONAL PCA RATE ADJUSTMENTS 17
A. Revenue Sharing. 18
Q. When was the revenue sharing mechanism 19
originally established? 20
A. The revenue sharing mechanism was originally 21
established in Case No. IPC-E-09-30 and approved in Order 22
No. 30978, effective for the years 2009-2011. Since then, 23
the revenue sharing mechanism has been modified and 24

BRADY, DI 30
Idaho Power Company
extended three times.5 Most recently, the revenue sharing 1
mechanism was extended indefinitely, with modifications, in 2
Order No. 34071 in Case No. GNR-U-18-01. 3
Q. What are the provisions of the current revenue 4
sharing mechanism? 5
A. In Case No. GNR-U-18-01, the Company filed a 6
motion to approve a settlement stipulation (“2018 7
Stipulation”) extending the sharing mechanism indefinitely, 8
with modifications. The Commission approved the 2018 9
Stipulation in Order No. 34071. 10
Per the terms of the 2018 Stipulation, if the 11
Company’s actual year-end Return on Equity (“ROE”) for the 12
Idaho jurisdiction exceeds 10 percent, all amounts up to 13
and including a 10.5 percent ROE will be shared between 14
customers and the Company on an 80 percent and 20 percent 15
basis, respectively, to be provided as a rate reduction to 16
become effective at the time of the subsequent year’s PCA. 17
If the Company’s Idaho jurisdictional ROE exceeds 10.5 18
percent, all amounts in excess of 10.5 percent will be 19
shared 55 percent with Idaho customers as a rate reduction 20
to become effective with the subsequent year’s PCA, 25 21
percent will be shared with Idaho customers in the form of 22
an offset to amounts in the Company’s pension balancing 23
account, and 20 percent will be apportioned to the Company. 24

5 Order Nos. 32424, 33149 and 34071.

BRADY, DI 31
Idaho Power Company
With regard to the amortization of Accumulated 1
Deferred Investment Tax Credits (“ADITC”), the 2018 2
Stipulation allows the Company to accelerate the 3
amortization of ADITC, in an amount up to $45 million, to 4
achieve a maximum 9.4 percent Idaho jurisdictional ROE if 5
the Company’s year-end actual results fall below that 6
amount for any year beginning January 1, 2020. Idaho Power 7
may use up to $25 million of additional amortization of 8
ADITC per year, provided the total, cumulative amount of 9
ADITC does not exceed $45 million. Per the 2018 10
Stipulation, once the Company has fully amortized the $45 11
million of ADITC, revenue sharing will cease; however, 12
Idaho Power may at any time request to replenish the total 13
amount of ADITC it is permitted to amortize, and if 14
approved by the Commission, revenue sharing would continue. 15
Q. What have been the results of the revenue 16
sharing mechanism since it was implemented through 2021? 17
A. The Company’s earnings in each year from 2011 18
through 2015, as well as 2018 and 2021, resulted in revenue 19
sharing with customers totaling $126.7 million, either as a 20
direct rate offset in the PCA or as an offset to amounts 21
that would have otherwise been collected in rates. The 22
Company’s earnings in 2016, 2017, 2019, and 2020 were below 23
the revenue sharing threshold. These amounts are detailed 24
in Table 6 below. 25

BRADY, DI 32
Idaho Power Company
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  

1
Q. Did the Company’s year-end 2022 financial 2
results warrant any action related to the existing sharing 3
agreement per the terms of the 2018 Stipulation? 4
A. No. The Company’s year-end 2022 financial 5
results yielded an actual Idaho jurisdictional ROE of 9.8 6
percent, falling below the 10 percent ROE threshold for 7
revenue sharing, and thus resulting in no revenue sharing 8
with customers. 9
Q. Did the Company use the same methodology to 10
determine the Idaho jurisdictional 2022 year-end ROE that 11
was used in prior PCA filings? 12
A. Yes. The methodology used to determine the 13
Company’s Idaho jurisdictional 2022 year-end ROE is 14
consistent with the methodology used for the year-end ROE 15
determinations since the inception of the mechanism. 16
Q. Do you have an exhibit demonstrating the 17
application of this methodology? 18

BRADY, DI 33
Idaho Power Company
A. Yes. Exhibit No. 3 provides a step-by-step 1
calculation of the Idaho jurisdictional ROE based on year-2
end 2022 financial results utilizing the Commission-3
approved methodology from previous PCA filings. 4
IV. NET CUSTOMER IMPACT 5
Q. What is the revenue impact of the requested 6
PCA rate when compared with PCA rates currently in effect? 7
A. Attachment 2 to the Application filed 8
contemporaneously with my testimony provides a detailed 9
description of the overall revenue impact of this filing on 10
each customer class. As shown in Attachment 2, applying 11
the requested PCA rates to expected customer sales for the 12
June 2023 through May 2024 test year6 results in a PCA 13
increase of $200.2 million. 14
Q. Given the magnitude of the increase for the 15
2023-2024 PCA, did the Company consider proposing any rate 16
mitigation options? 17
A. Yes, though after careful consideration it was 18
ultimately decided to not propose any rate mitigation 19
measures in this case. While the Company is sensitive to 20
the financial impact the proposed increase will have on its 21
customers, it believes the potential longer-term downside 22

6 Expected customer sales for the June 2023 – May 2024 test year are
reduced by the amount of Micron’s load forecast to be met by Black Mesa
Solar generation for the reasons explained herein.

BRADY, DI 34
Idaho Power Company
risks outweigh the near-term relief of deferring all or a 1
portion of the requested increase. 2
Q. What concerns does the Company have with 3
proposing rate mitigation measures in this case? 4
A. First, the Company believes that customer 5
interests are generally best served by matching cost 6
recovery as closely as possible with the period in which 7
power supply costs are incurred. Additionally, mitigating 8
rate impacts by spreading recovery over multiple years 9
creates the possibility that the deferred collection will 10
result in “rate pancaking” with potential future rate 11
increases, essentially deferring an increase in the current 12
year to create an even larger increase in the future. 13
Q. Is the Company’s decision not to propose any 14
rate mitigation measures in this case consistent with 15
Commission precedent? 16
A. Yes. In considering the use of rate mitigation 17
measures in prior PCA cases, the Commission has repeatedly 18
declined to spread recovery of amounts into subsequent 19
years citing concerns surrounding rate pancaking, 20
appropriate matching of costs and recovery, and the overall 21
intent of the PCA mechanism.7 22

7 See, e.g., Order Nos. 28722, 29026, 30563, 30828, and 32821.

BRADY, DI 35
Idaho Power Company
Q. Would Idaho Power be amenable to implementing 1
rate mitigation measures for the 2023-2024 PCA if the 2
Commission determines such measures are appropriate? 3
A. Yes. While both Idaho Power and the Commission 4
have expressed concerns with rate mitigation measures in 5
the past, the Company would be amenable to discussing such 6
measures in the current filing. A two-year recovery period, 7
for example, would reduce the rate impact from the proposed 8
$200.2 million, or 14.68 percent increase, to an 9
approximate $100 million, or slightly more than 7 percent, 10
annual increase in collection spread over two years. 11
Q. Have you prepared a revised Schedule 55 that 12
includes the proposed PCA rates? 13
A. Yes. Attachment 1 to the Application is a 14
revised Schedule 55 and includes the proposed PCA rates in 15
clean and legislative formats. 16
Q. Please summarize the Company’s request in this 17
filing. 18
A. If approved, the 2023-2024 PCA will result in 19
an increase in total billed revenue of approximately $200.2 20
million, or 14.68 percent. The Commission should approve 21
the Company’s computation of the PCA rates, the calculation 22
of which follows the methodology that was approved in Order 23
Nos. 30715, 33307, and 34071. 24
Q. Does this conclude your testimony? 25

BRADY, DI 36
Idaho Power Company
A. Yes, it does. 1
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BRADY, DI 37
Idaho Power Company
DECLARATION OF JESSICA G. BRADY 1
I, Jessica G. Brady, declare under penalty of 2
perjury under the laws of the state of Idaho: 3
1. My name is Jessica G. Brady. I am employed 4
by Idaho Power Company as a Regulatory Analyst in the 5
Regulatory Affairs Department. 6
2. On behalf of Idaho Power, I present this 7
pre-filed direct testimony and Exhibit Nos. 1-4 in this 8
matter. 9
3. To the best of my knowledge, my pre-filed 10
direct testimony and exhibits are true and accurate. 11
I hereby declare that the above statement is true to 12
the best of my knowledge and belief, and that I understand 13
it is made for use as evidence before the Idaho Public 14
Utilities Commission and is subject to penalty for perjury. 15
SIGNED this 14th day of April 2023, at Boise, Idaho. 16
17
Signed: _________________________ 18

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-23-12

IDAHO POWER COMPANY

BRADY, DI
TESTIMONY

EXHIBIT NO. 1

Line No. FERC Accoun April May June Jul Augus Septembe Octobe Novembe Decembe January February March Annua
95% Sharing Account
1 Hydroelectric Generation (MWh 669,893 815,724 668,995 589,237 459,802 469,487 410,852 376,407 417,821 500,561 511,721 597,496 6,487,995
Account 536, Water for Power
2 Total Expense -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$
Account 501, Coa
Jim Bridge3 Energy (MWh)32,400 33,480 52,800 345,000 389,280 368,000 291,648 301,087 397,342 248,168 224,151 198,028 2,881,385
4 Total Expense 927,519$ 944,093$ 1,583,803$ 11,771,641$ 13,302,239$ 12,531,704$ 9,823,994$ 10,124,985$ 13,479,776$ 9,093,109$ 8,224,823$ 7,120,278$ 98,927,967$
North Valm
5 Energy (MWh)0 0 0 92,982 93,606 90,587 (0) 90,586 93,606 93,606 84,547 (0) 639,520 6 Total Expense 281,244$ 281,244$ 281,244$ 4,036,122$ 4,112,417$ 4,091,354$ 281,244$ 4,346,310$ 4,494,603$ 4,527,474$ 4,147,553$ 281,244$ 31,162,058$
Account 547, Other Fuel
Langley Gulc
7 Energy (MWh)139,733 217,400 207,136 210,784 211,056 173,533 104,419 215,505 227,040 226,896 209,272 219,721 2,362,496 8 Total Expense 4,057,080$ 5,606,759$ 5,549,706$ 6,062,379$ 6,297,359$ 5,184,195$ 2,768,811$ 8,521,863$ 11,667,835$ 11,483,215$ 9,621,781$ 8,050,424$ 84,871,408$
Danskin
9 Energy (MWh)- - 107,536 120,760 121,032 17,920 16,072 - 48,608 91,656 - - 523,584
10 Total Expense 188,260$ 188,260$ 4,834,354$ 5,856,346$ 6,077,534$ 1,087,306$ 880,963$ 188,260$ 4,036,946$ 7,322,223$ 188,260$ 188,260$ 31,036,972$
Bennett Mountai11 Energy (MWh)53,120 24,600 29,792 123,504 117,792 - 26,896 - - - - - 375,704
12 Total Expense 2,730,132.99$ 1,136,502.99$ 1,372,887.23$ 5,862,220.99$ 5,798,229.63$ 92,724.99$ 1,258,935.55$ 92,724.99$ 92,724.99$ 92,724.99$ 92,724.99$ 92,724.99$ 18,715,259$
Account 555, Purchased Power Non-PURP
13 Energy (MWh)142,847 191,051 259,425 196,337 112,350 68,143 152,585 101,420 99,244 122,682 106,225 143,375 1,695,683 14 Total Expense 7,687,629$ 9,415,073$ 13,232,753$ 18,203,695$ 14,155,915$ 4,935,489$ 9,776,664$ 7,118,508$ 8,565,313$ 11,905,097$ 9,371,986$ 9,124,566$ 123,492,688$
Account 565, 3rd Party Transmission15 Total Expense 288,871$ 555,684$ 995,003$ 1,295,183$ 1,374,340$ 678,713$ 627,107$ 442,821$ 475,985$ 476,827$ 531,126$ 222,991$ 7,964,649$
Account 447, Surplus Sale
16 Energy (MWh)(164,104) (233,311) (50,588) (57,706) (29,711) (77,912) (18,744) (23,789) (3,189) (43,366) (130,716) (181,682) (1,014,817)
17 Total Expense (11,881,670)$ (11,175,499)$ (2,179,620)$ (7,279,357)$ (6,124,246)$ (12,126,073)$ (1,354,165)$ (2,053,469)$ (389,477)$ (5,433,721)$ (13,001,139)$ (11,193,102)$ (84,191,539)$
100% Sharing Account
Account 555, PURP
18 Energy (MWh)294,581 304,873 315,285 293,178 276,769 254,323 228,028 184,726 193,395 208,290 248,034 256,321 3,057,802 19 Total Expense 15,926,928$ 16,207,313$ 22,389,867$ 24,148,708$ 23,196,742$ 17,877,565$ 16,195,226$ 16,041,536$ 17,320,985$ 16,103,838$ 18,694,874$ 14,431,830$ 218,535,412$
Account 555, Demand Response Incentive
20 Total Expense -$ -$ 283,373$ 3,219,549$ 4,926,370$ 1,339,151$ 185,519$ 59,448$ 971,098$ -$ -$ -$ 10,984,508$
95% Sharing Account 4,279,066$ 6,952,118$ 25,670,130$ 45,808,231$ 44,993,789$ 16,475,415$ 24,063,555$ 28,782,003$ 42,423,706$ 39,466,950$ 19,177,114$ 13,887,387$ 311,979,464$ 100% Sharing Account 15,926,928$ 16,207,313$ 22,673,240$ 27,368,257$ 28,123,112$ 19,216,716$ 16,380,745$ 16,100,984$ 18,292,083$ 16,103,838$ 18,694,874$ 14,431,830$ 229,519,920$
21 Total Net Power Supply Expense 20,205,994$ 23,159,431$ 48,343,370$ 73,176,488$ 73,116,901$ 35,692,131$ 40,444,300$ 44,882,987$ 60,715,789$ 55,570,787$ 37,871,988$ 28,319,217$ 541,499,384$
22 Total Generation (MWh) 1,332,575 1,587,128 1,640,969 1,971,781 1,781,687 1,441,992 1,230,500 1,269,731 1,477,055 1,491,859 1,383,951 1,414,941 18,024,169
23 Total Load (MWh) 1,168,471 1,353,817 1,590,381 1,914,075 1,751,976 1,364,081 1,211,755 1,245,943 1,473,866 1,448,493 1,253,235 1,233,259 17,009,352
APRIL 1, 2023 - MARCH 31, 2024IDAHO POWER PCA FORECAS
Exhibit No. 1 Case No. IPC-E-23-12 J. Brady, IPC
Page 1 of 1

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-23-12

IDAHO POWER COMPANY

BRADY, DI
TESTIMONY

EXHIBIT NO. 2

Power Cost Adjustment Highlighted cells need to be updated prior to the June and July PCA entries
April 2022 thru March 2023
April May June July August September October November December January February March Totals
Idaho Jurisdiction Net Power Supply Expense (Non-QF)
Actual Non-QF
Fuel Expense-Coal 10,847,106.68 7,386,836.10 4,111,571.46 11,388,060.41 12,934,149.36 10,862,858.85 4,311,322.69 7,381,229.78 8,669,673.61 7,626,241.65 7,359,669.84 2,077,275.31 94,955,995.74
Fuel Expense-Gas 5,526,950.57 4,507,824.70 1,959,307.24 10,394,443.73 6,195,389.72 11,777,878.94 8,000,984.36 21,045,163.64 36,970,792.16 27,818,545.94 19,969,889.01 24,150,144.27 178,317,314.28
Non-Firm Purchases 11,864,206.44 14,536,346.52 12,238,491.62 32,596,901.52 38,083,529.37 53,257,026.95 18,727,713.66 28,902,479.00 76,331,498.00 71,159,607.64 20,756,484.69 26,483,985.39 404,938,270.80
Third Party Transmission 590,965.52 1,005,756.94 1,365,288.83 1,915,820.21 1,790,013.35 1,018,981.81 884,839.05 682,107.44 822,136.83 875,468.43 962,712.15 905,086.65 12,819,177.21
Surplus Sales (3,054,903.66) (8,394,562.48) (2,261,691.94) 116,995.03 (227,238.62) (37,093,105.64) (5,653,754.73) (9,143,789.20) (42,268,447.57) (41,177,195.12) (14,320,861.02) (6,746,427.22) (170,224,982.17)
Water for Power (Leases)- - - - - - - - - - - - -
Total Actual NPSE $25,774,325.55 19,042,201.78 17,412,967.21 56,412,220.90 58,775,843.18 39,823,640.91 26,271,105.03 48,867,190.66 80,525,653.03 66,302,668.54 34,727,894.67 46,870,064.40 520,805,775.86
Idaho Allocation 95.6%95.4%95.7%96.0%95.9%95.8%95.7%95.3%95.2%95.3%95.6%96.0%
Net Idaho Jurisctional Actual Non-QF $24,640,255.23 18,166,260.50 16,664,209.62 54,155,732.06 56,366,033.61 38,151,047.99 25,141,447.51 46,570,432.70 76,660,421.68 63,186,443.12 33,199,867.30 44,995,261.82 497,897,413.14
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 9,553,773.00 8,912,994.00 8,098,078.00 108,503,180.00
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 2,938,035.00 2,740,979.00 2,490,369.00 33,367,563.00
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 5,512,549.00 5,142,819.00 4,672,610.00 62,606,593.00
Third Party Transmission $378,398.00 376,507.00 453,517.00 572,494.00 612,729.00 542,907.00 391,281.00 367,189.00 425,151.00 480,400.00 448,179.00 407,203.00 5,455,955.00
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) (4,555,312.00) (4,249,784.00) (3,861,227.00) (51,735,153.00)
Water for Power (Leases)$165,106.00 164,281.00 197,883.00 249,796.00 267,352.00 236,886.00 170,727.00 160,216.00 185,506.00 209,613.00 195,555.00 177,676.00 2,380,597.00
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 14,139,058.00 13,190,742.00 11,984,709.00 160,578,735.00
Idaho Allocation 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 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 13,432,105.10 12,531,204.90 11,385,473.55 152,549,798.25
Idaho Jurisdiction Change From Base $14,060,157.48 7,639,026.45 3,983,753.07 38,148,659.56 39,233,981.56 22,971,248.79 14,201,146.81 36,303,745.65 64,773,106.83 49,754,338.02 20,668,662.40 33,609,788.27 345,347,614.89
Sharing Percentage 95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%
Net Power Supply Expense Deferral ①$13,357,149.61 7,257,075.13 3,784,565.42 36,241,226.58 37,272,282.48 21,822,686.35 13,491,089.47 34,488,558.37 61,534,451.49 47,266,621.12 19,635,229.28 31,929,298.86 328,080,234.16
Idaho Jurisdictional Qualifying Facility NPSE
Actual QF (Includes Net Metering, Raft River 100% & Liquidated Damages)$14,958,605.05 16,068,219.34 18,990,400.71 21,624,166.85 20,132,150.98 16,190,054.78 13,070,143.71 16,510,351.76 17,309,716.19 15,523,875.98 18,000,196.38 14,949,609.43 203,327,491.16
Idaho Allocation 95.6%95.4%95.7%96.0%95.9%95.8%95.7%95.3%95.2%95.3%95.6%96.0%
Idaho Jurisctional Actual QF $14,300,426.43 15,329,081.25 18,173,813.48 20,759,200.18 19,306,732.79 15,510,072.48 12,508,127.53 15,734,365.23 16,478,849.81 14,794,253.81 17,208,187.74 14,351,625.05 194,454,735.78
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 11,785,917.00 10,995,427.00 9,990,113.00 133,853,870.00
Idaho Allocation 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 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 11,196,621.15 10,445,655.65 9,490,607.35 127,161,176.50
Idaho Jurisdiction Change From Base $5,481,158.43 6,553,877.10 7,603,744.88 7,416,158.53 5,025,940.44 2,856,623.48 3,388,604.43 7,176,347.23 6,569,922.31 3,597,632.66 6,762,532.09 4,861,017.70 67,293,559.28
Sharing Percentage 100.0%100.0%100.0%100.0%100.0%100.0%100.0%100.0%100.0%100.0%100.0%100.0%QF Deferral ②$5,481,158.43 6,553,877.10 7,603,744.88 7,416,158.53 5,025,940.44 2,856,623.48 3,388,604.43 7,176,347.23 6,569,922.31 3,597,632.66 6,762,532.09 4,861,017.70 67,293,559.28
Idaho Revenue Adjustment (SBAR
Actual Idaho Jurisdictional Billing Month Sales MWh 1,005,246 1,053,812 1,178,710 1,548,306 1,721,691 1,581,973 1,118,643 1,050,588 1,227,997 1,269,362 1,221,424 1,168,371 15,146,122
Normalized Idaho Jurisdictional Billing Month Sales MWh 947,192 953,286 1,131,686 1,370,142 1,428,766 1,300,608 1,045,495 957,864 1,081,014 1,177,663 1,101,149 1,004,027 13,498,892
Sales Change MWh 58,054 100,526 47,024 178,164 292,925 281,365 73,148 92,724 146,983 91,699 120,275 164,344 1,647,230
% of Prior Period Billings at Old Rate -$ 0.000%0.000%0.000%0.000%0.000%0.000%0.000%0.000%0.000%0.000%0.000%0.000%
% of Current Period Billings at New Rate-effective 6/2015 26.72$ 100.000%100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000%
Sales Adjustment Prior To Sharing @ $(1,551,202.88) (2,686,048.71) (1,256,481.28) (4,760,542.08) (7,826,942.72) (7,518,072.80) (1,954,514.56) (2,477,585.28) (3,927,385.76) (2,450,197.28) (3,213,748.00) (4,391,267.63) (44,013,988.98)
Sharing Percentage 95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%
Idaho Revenue Adjustment (SBAR) ③$(1,473,642.74) (2,551,746.27) (1,193,657.22) (4,522,514.98) (7,435,595.58) (7,142,169.16) (1,856,788.83) (2,353,706.02) (3,731,016.47) (2,327,687.42) (3,053,060.60) (4,171,704.25) (41,813,289.54)
Idaho Jurisdcitional Demand Response Incentive Payments
Idaho Actual Demand Response $ - - 163,366.82 2,073,169.22 2,843,974.65 2,121,623.76 628,735.75 479,437.58 1,020.00 14.35 85.35 101.34 8,311,528.82
Idaho Base Demand Response $780,401.00 776,502.00 935,327.00 1,180,702.00 1,263,682.00 1,119,681.00 806,970.00 757,284.00 876,823.00 990,769.00 924,317.00 839,807.00 11,252,265.00
Change From Base $(780,401.00) (776,502.00) (771,960.18) 892,467.22 1,580,292.65 1,001,942.76 (178,234.25) (277,846.42) (875,803.00) (990,754.65) (924,231.65) (839,705.66) (2,940,736.18)
Sharing Percentage 100.0%100.0%100.0%100.0%100.0%100.0%100.0%100.0%100.0%100.0%100.0%100.0%
Change From Base ④$(780,401.00) (776,502.00) (771,960.18)892,467.22 1,580,292.65 1,001,942.76 (178,234.25) (277,846.42) (875,803.00) (990,754.65) (924,231.65) (839,705.66) (2,940,736.18)
Idaho Miscellaneous Revenue
System Emission Allowance Sales Credit $- - - - - - - - - - - - -
System Renewable Energy Credit Sales $(1,168,040.31) 809.96 171.78 181.81 (1,183,377.60) 669.95 (83,462.81) 218.59 (738,019.94) (3,294,293.02) (4,123,273.82) (63,679.79) (10,652,095.20)
Revenue Subtotal $(1,168,040.31)809.96 171.78 181.81 (1,183,377.60)669.95 (83,462.81)218.59 (738,019.94) (3,294,293.02) (4,123,273.82) (63,679.79) (10,652,095.20)
Idaho Allocation 95.6%95.4%95.7%96.0%95.9%95.8%95.7%95.3%95.2%95.3%95.6%96.0%
Sharing Percentage 95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%Miscellaneous Revenue Deferral ⑤$(1,060,814.21)734.07 156.17 165.81 (1,078,116.16)609.72 (75,880.21)197.90 (667,465.23) (2,982,488.19) (3,744,757.28) (58,075.97) (9,665,733.58)
#
Exhibit No. 2
Case No. IPC-E-23-12 J. Brady, IPC
Page 1 of 25
Idaho EIM Participation Costs
Return on EIM Capital Investment $ 33,103.18 32,402.30 31,701.42 31,000.54 30,299.65 29,598.77 28,897.89 28,197.01 27,496.13 26,795.25 26,094.37 25,393.49 350,980.01
Operating Expenses $196,675.42 205,717.68 167,186.10 167,362.06 196,300.92 166,352.29 176,893.06 143,446.00 179,859.42 225,077.65 195,294.16 214,835.67 2,235,000.41
Revenue Subtotal $229,778.59 238,119.98 198,887.52 198,362.60 226,600.57 195,951.07 205,790.95 171,643.02 207,355.55 251,872.90 221,388.53 240,229.16 2,585,980.43
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%
EIM Revenue Requirement ⑥$218,289.66 226,213.98 188,943.14 188,444.47 215,270.54 186,153.52 195,501.40 163,060.87 196,987.77 239,279.26 210,319.11 228,217.70 2,456,681.42
TOTAL DEFERRAL (Sum of ①-⑥) $15,741,739.75 10,709,652.01 9,611,792.21 40,215,947.63 35,580,074.37 18,725,846.67 14,964,292.01 39,196,611.93 63,027,076.87 44,802,602.78 18,886,030.95 31,949,048.38 343,410,715.56
PCA Forecasted Revenues
Actual Idaho Jurisdictional Billing Month Sales MWh 1,005,246 1,053,812 1,178,710 1,548,306 1,721,691 1,581,973 1,118,643 1,050,588 1,227,997 1,269,362 1,221,424 1,168,371 15,146,122
% of Prior Period Billings at Old Rate 6/1/2021 7.83$ 100.000%100.000% 60.185%1.389%0.000%0.000%0.000%0.000%0.000%0.000%0.000%0.000%
% of Current Period Billings at New Rate - 6/1/2022 8.79$ 0.000%0.000% 39.800% 98.600% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000%Forecast Rate Revenues ⑦(8,839,128.20) (9,266,166.94) (11,441,018.36) (17,409,566.17) (19,407,095.97) (17,972,798.81) (12,708,913.52) (11,935,736.88) (13,951,273.90) (14,421,225.91) (13,876,598.56) (13,273,861.21) (164,503,384.43)
PCA Balancing Account Balance
Monthly Interest Rate (Annual 1% for 2022, 2% for 2023)%0.0833%0.0833% 0.0833% 0.0833%0.0833% 0.0833% 0.0833% 0.0833% 0.0833% 0.1667%0.1667%0.1667%1.2500%
Beginning Balance 38,669,525.55$ 46,832,766.34 49,603,036.48 47,089,846.29 65,914,170.36 77,522,098.47 74,442,372.54 73,918,880.54 98,574,262.10 144,614,010.89 172,012,445.47 174,207,820.07 38,669,525.55
2022-2023 Incremental Deferral (Sum of ①-⑥ above 15,741,739.75 10,709,652.01 9,611,792.21 40,215,947.63 35,580,074.37 18,725,846.67 14,964,292.01 39,196,611.93 63,027,076.87 44,802,602.78 18,886,030.95 31,949,048.38 343,410,715.56
2022-2023 PCA Forecast Revenues (Collections) ⑦ above (8,839,128.20) (9,266,166.94) (11,441,018.36) (17,409,566.17) (19,407,095.97) (17,972,798.81) (12,708,913.52) (11,935,736.88) (13,951,273.90) (14,421,225.91) (13,876,598.56) (13,273,861.21) (164,503,384.43)
2022-2023 PCA Prior Balance Revenues (Collections) 1,228,404.64 1,287,757.76 (153,917.98) (4,021,298.93) (4,619,978.77) (3,897,375.54) (2,840,905.80) (2,667,092.56) (3,118,199.40) (3,223,965.64) (3,100,745.20) (2,967,784.99) (28,095,102.41)
Revenue Sharing - Order No. - - (571,381.92) - - - - - - - - - (571,381.92)
DSM Rider Forecasted Surplus Funds - Order No. - - - - - - - - - - - - -
2022-2023 Ending Balance Without Current Month Interest 46,800,541.74 49,564,009.17 47,048,510.43 65,874,928.82 77,467,169.99 74,377,770.79 73,856,845.23 98,512,663.03 144,531,865.67 171,771,422.12 173,921,132.66 189,915,222.25 188,910,372.35
Current Month Interest 32,224.60 39,027.31 41,335.86 39,241.54 54,928.48 64,601.75 62,035.31 61,599.07 82,145.22 241,023.35 286,687.41 290,346.37 1,295,196.272022-2023 Ending Deferral Balance 46,832,766.34$ 49,603,036.48 47,089,846.29 65,914,170.36 77,522,098.47 74,442,372.54 73,918,880.54 98,574,262.10 144,614,010.89 172,012,445.47 174,207,820.07 190,205,568.62 190,205,568.62
Tab is 100% locked down, with no manual inputs.
Idaho Billed Sales MWh 1,005,246 1,053,812 1,178,710 1,548,306 1,721,691 1,581,973 1,118,643 1,050,588 1,227,997 1,269,362 1,221,424 1,168,371 15,146,122
Oregon Billed Sales MWh 46,427 50,553 53,082 63,743 72,727 68,968 50,421 51,906 62,339 62,037 56,639 49,302 688,143
Total MWh 1,051,673 1,104,364 1,231,792 1,612,049 1,794,417 1,650,941 1,169,064 1,102,494 1,290,336 1,331,399 1,278,063 1,217,673 15,834,266
Idaho % Billed Sales 95.6%95.4%95.7%96.0%95.9%95.8%95.7%95.3%95.2%95.3%95.6%96.0%
Oregon % Billed Sales 4.4%4.6%4.3%4.0%4.1%4.2%4.3%4.7%4.8%4.7%4.4%4.0%
Exhibit No. 2
Case No. IPC-E-23-12 J. Brady, IPC
Page 2 of 25
Power Cost Adjustment Input Sheet
April 2022 thru March 2023
Source April May June July August September October November December January February March Total
Actual Idaho Jurisdictional Billing Month Sales (Mwh) NCUST - Fin Accntng 1,005,246 1,053,812 1,178,710 1,548,306 1,721,691 1,581,973 1,118,643 1,050,588 1,227,997 1,269,362 1,221,424 1,168,371 15,146,122
Actual Idaho Jurisdictional Calendar Month Sales (Mwh)NCUST - Fin Accntng 1,030,080 1,151,009 1,309,649 1,770,115 1,656,873 1,267,327 1,022,769 1,159,427 1,297,005 1,255,296 1,120,338 1,156,785 15,196,672
Actual Oregon Jurisdictional Billing Month Sales (Mwh)NCUST - Fin Accntng 46,427 50,553 53,082 63,743 72,727 68,968 50,421 51,906 62,339 62,037 56,639 49,302 688,143
Surplus Sales (447) Purchases and Sales Sheet-Christy Van Paepeghem (3,054,903.66) (8,394,562.48) (2,261,691.94) 116,995.03 (227,238.62) (37,093,105.64) (5,653,754.73) (9,143,789.20) (42,268,447.57) (41,177,195.12) (14,320,861.02) (6,746,427.22) (170,224,982.17)
Total Purchased Power Purchases and Sales Sheet-Christy Van Paepeghem 12,191,275.94 14,772,851.86 12,670,837.76 32,482,332.00 37,703,740.06 53,511,436.21 19,164,182.26 29,443,672.31 76,511,844.14 71,435,626.01 21,313,471.02 26,579,956.71 407,781,226.28
Less Raft River Geothermal 100% PCA Purchases and Sales Sheet-Christy Van Paepeghem 421,475.64 406,842.04 527,600.39 589,330.74 528,975.59 464,130.18 527,125.14 699,354.59 724,962.11 614,089.57 559,327.26 452,143.91 6,515,357.16
Net Non-Firm Purchases - Including Telecaset & Raft River 95%(Acct 555000)11,769,800.30 14,366,009.82 12,143,237.37 31,893,001.26 37,174,764.47 53,047,306.03 18,637,057.12 28,744,317.72 75,786,882.03 70,821,536.44 20,754,143.76 26,127,812.80 401,265,869.12
Purchased Power Transmission Losses (555050)Purchases and Sales Sheet-Christy Van Paepeghem 92,639.60 168,488.10 92,879.25 696,566.17 894,801.42 199,583.40 85,663.16 155,437.39 541,970.00 335,938.83 265.59 354,785.32 3,619,018.23
Oregon Solar Purchases and Sales Sheet-Christy Van Paepeghem 1,766.54 1,848.60 2,375.00 7,334.09 13,963.48 10,137.52 4,993.38 2,723.89 2,645.97 2,132.37 2,075.34 1,387.27 53,383.45
Total Non-Firm Purchases 11,864,206.44 14,536,346.52 12,238,491.62 32,596,901.52 38,083,529.37 53,257,026.95 18,727,713.66 28,902,479.00 76,331,498.00 71,159,607.64 20,756,484.69 26,483,985.39 404,938,270.80
CSPP Expense (555070)Purchases and Sales Sheet-Christy Van Paepeghem 14,537,129.41 15,661,377.30 18,462,800.32 21,066,477.95 19,603,175.39 15,725,924.60 12,556,172.32 15,810,957.17 16,803,693.41 14,690,847.08 17,440,869.12 14,622,620.54 196,982,044.61
Net Metering (555101) Order No. 29094 Purchases and Sales Sheet-Christy Van Paepeghem - - - - - - - - - - - - -
Raft River 100%Purchases and Sales Sheet-Christy Van Paepeghem 421,475.64 406,842.04 527,600.39 589,330.74 528,975.59 464,130.18 527,125.14 699,354.59 724,962.11 614,089.57 559,327.26 452,143.91 6,515,357.16
Liquidated Damages (555080)Purchases and Sales Sheet-Christy Van Paepeghem - (31,641.84) (13,153.75) 40.00 (218,939.33) 218,939.33 - (125,155.02) (169,910.61)
Total QF 14,958,605.05 16,068,219.34 18,990,400.71 21,624,166.85 20,132,150.98 16,190,054.78 13,070,143.71 16,510,351.76 17,309,716.19 15,523,875.98 18,000,196.38 14,949,609.43 203,327,491.16
Demand Response Incentive Payments Purchases and Sales Sheet-Christy Van Paepeghem - - 163,366.82 2,073,169.22 2,843,974.65 2,121,623.76 628,735.75 479,437.58 1,020.00 14.35 85.35 101.34 8,311,528.82
Third Party Transmission (565000)Purchases and Sales Sheet-Christy Van Paepeghem 590,965.52 1,005,756.94 1,365,288.83 1,915,820.21 1,790,013.35 1,018,981.81 884,839.05 682,107.44 822,136.83 875,468.43 962,712.15 905,086.65 12,819,177.21
Fuel Expense - Coal (Account 501)Purchases and Sales Sheet-Christy Van Paepeghem 10,847,106.68 7,386,836.10 4,111,571.46 11,388,060.41 12,934,149.36 10,862,858.85 4,311,322.69 7,381,229.78 8,669,673.61 7,626,241.65 7,359,669.84 2,077,275.31 94,955,995.74
Fuel Expense - Gas - Capacity & Fuel (547101 - 547103. 547105) Purchases and Sales Sheet-Christy Van Paepeghem 5,526,950.57 4,507,824.70 1,959,307.24 10,394,443.73 6,195,389.72 11,777,878.94 8,000,984.36 21,045,163.64 36,970,792.16 27,818,545.94 19,969,889.01 24,150,144.27 178,317,314.28
Water Lease Expense (Acct 536003)Peoplesoft query - Cathy Campbell - - - - - - - - - - - - -
Emission Allowance Sales Peoplesoft query - Cathy Campbell - - - - - - - - - - - - -
Renewable Energy Credits Christy Van Paepeghem (1,168,040.31) 809.96 171.78 181.81 (1,183,377.60) 669.95 (83,462.81) 218.59 (738,019.94) (3,294,293.02) (4,123,273.82) (63,679.79) (10,652,095.20)
True-up Revenues YYYY PCA from Data Warehouse - Fin Accntng (1,228,404.64) (1,287,757.76) 153,917.98 4,021,298.93 4,619,978.77 3,897,375.54 2,840,905.80 2,667,092.56 3,118,199.40 3,223,965.64 3,100,745.20 2,967,784.99 28,095,102.41
Forecast Revenues YYYY PCA from Data Warehouse - Fin Accntng 8,839,128.20 9,266,166.94 11,441,018.36 17,409,566.17 19,407,095.97 17,972,798.81 12,708,913.52 11,935,736.88 13,951,273.90 14,421,225.91 13,876,598.56 13,273,861.21 164,503,384.43
Tab is 100% locked down, with exception of inputs, which have been traced to source
Normalized Idaho Jurisdictional Billed 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 1,177,663 1,101,149 1,004,027 13,498,892
Normalized Idaho Jurisdictional Calendar Month Sales (Mwh)911,298 1,108,897 1,213,542 1,521,656 1,379,463 1,113,295 955,414 980,350 1,177,700 1,169,731 990,746 982,290 13,504,382
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 9,553,773.00 8,912,994.00 8,098,078.00 108,503,180.00
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 2,938,035.00 2,740,979.00 2,490,369.00 33,367,563.00
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 5,512,549.00 5,142,819.00 4,672,610.00 62,606,593.00
Third Party Transmission 378,398.00 376,507.00 453,517.00 572,494.00 612,729.00 542,907.00 391,281.00 367,189.00 425,151.00 480,400.00 448,179.00 407,203.00 5,455,955.00
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) (4,555,312.00) (4,249,784.00) (3,861,227.00) (51,735,153.00)
Water for Power (Leases)165,106.00 164,281.00 197,883.00 249,796.00 267,352.00 236,886.00 170,727.00 160,216.00 185,506.00 209,613.00 195,555.00 177,676.00 2,380,597.00
Net 95% Items 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 14,139,058.00 13,190,742.00 11,984,709.00 160,578,735.00
Base Demand Response Incentive Payments 780,401 776,502 935,327 1,180,702 1,263,682 1,119,681 806,970 757,284 876,823 990,769 924,317 839,807 11,252,265
Base QF 9,283,440 9,237,057 11,126,388 14,045,307 15,032,413 13,319,420 9,599,498 9,008,440 10,430,450 11,785,917 10,995,427 9,990,113 133,853,870
Exhibit No. 2
Case No. IPC-E-23-12 J. Brady, IPC
Page 3 of 25
Idaho Power Company
Western EIM Participation Costs
Idaho Jurisdictional Revenue Requirement
RATE BASE Mar‐22
Electric Plant in Service
     Intangible Plant 5,792,702$             
     Production Plant 1153936.874
     Transmission Plant 1204191.691
     Distribution Plant 0
     General Plant 0
Total Electric Plant in Service 8150830.238
Less: Accumulated Depreciation 205803.1395
Less: Amortization of Other Plant 4152990.097
Net Electric Plant in Service 3792037.002
Less: Customer Adv for Construction 0
Less: Accumulated Deferred Income Taxes 38996.09787
Add: Plant Held for Future Use 0
Add: Working Capital 0
Add: Other Deferred Amounts 0
Add: Subsidiary Rate Base
TOTAL COMBINED RATE BASE 3,753,041$             
NET INCOME
Operating Revenues
     Sales Revenues 0
     Other Operating Revenues 0
Total Operating Revenues ‐$ 
Operating Expenses
     Operation and Maintenance Expenses 158,056$                
     Depreciation Expenses 5,499
     Amortization of Limited Term Plant 34,967
     Taxes Other Than Income 3,429
Regulatory Debits/Credits
     Provision for Deferred Income Taxes (5,278)
     Investment Tax Credit Adjustment 0
     Federal Income Taxes (38,822)
     State Income Taxes (11,800)
Total Operating Expenses 146,051$                
Operating Income ‐146051.1616
Add: IERCO Operating Income 0
Consolidated Operating Income (146,051)$               
Rate of Return as filed ‐3.89%
Annual Authorized Rate of Return 7.86%
Earnings Impact 170633.5795
Net‐to‐Gross Tax Multiplier 1.347
Monthly Revenue Requirement 229,779$                
#
Exhibit No. 2
Case No. IPC-E-23-12 J. Brady, IPC
Page 4 of 25
Idaho Power Company
Western EIM Participation Costs
Idaho Jurisdictional Revenue Requirement
RATE BASE May‐22
Electric Plant in Service
     Intangible Plant 5,792,702$             
     Production Plant 1153936.874
     Transmission Plant 1204191.691
     Distribution Plant 0
     General Plant 0
Total Electric Plant in Service 8150830.238
Less: Accumulated Depreciation 211302.1158
Less: Amortization of Other Plant 4187956.646
Net Electric Plant in Service 3751571.476
Less: Customer Adv for Construction 0
Less: Accumulated Deferred Income Taxes 77992.19575
Add: Plant Held for Future Use 0
Add: Working Capital 0
Add: Other Deferred Amounts 0
Add: Subsidiary Rate Base
TOTAL COMBINED RATE BASE 3,673,579$             
NET INCOME
Operating Revenues
     Sales Revenues 0
     Other Operating Revenues 0
Total Operating Revenues ‐$ 
Operating Expenses
     Operation and Maintenance Expenses 167,098$                
     Depreciation Expenses 5,499
     Amortization of Limited Term Plant 34,967
     Taxes Other Than Income 3,429
Regulatory Debits/Credits
     Provision for Deferred Income Taxes (5,278)
     Investment Tax Credit Adjustment 0
     Federal Income Taxes (40,607)
     State Income Taxes (12,342)
Total Operating Expenses 152,766$                
Operating Income ‐152765.948
Add: IERCO Operating Income 0
Consolidated Operating Income (152,766)$               
Rate of Return as filed ‐4.16%
Annual Authorized Rate of Return 7.86%
Earnings Impact 176827.8923
Net‐to‐Gross Tax Multiplier 1.347
Monthly Revenue Requirement 238,120$                
#
Exhibit No. 2
Case No. IPC-E-23-12 J. Brady, IPC
Page 5 of 25
Idaho Power Company
Western EIM Participation Costs
Idaho Jurisdictional Revenue Requirement
RATE BASE
Electric Plant in Service
     Intangible Plant 5,792,702$             
     Production Plant 1153936.874
     Transmission Plant 1204191.691
     Distribution Plant 0
     General Plant 0
Total Electric Plant in Service 8150830.238
Less: Accumulated Depreciation 216801.0921
Less: Amortization of Other Plant 4222923.196
Net Electric Plant in Service 3711105.951
Less: Customer Adv for Construction 0
Less: Accumulated Deferred Income Taxes 116988.2936
Add: Plant Held for Future Use 0
Add: Working Capital 0
Add: Other Deferred Amounts 0
Add: Subsidiary Rate Base
TOTAL COMBINED RATE BASE 3,594,118$             
NET INCOME
Operating Revenues
     Sales Revenues 0
     Other Operating Revenues 0
Total Operating Revenues ‐$ 
Operating Expenses
     Operation and Maintenance Expenses 128,567$                
     Depreciation Expenses 5,499
     Amortization of Limited Term Plant 34,967
     Taxes Other Than Income 3,429
Regulatory Debits/Credits
     Provision for Deferred Income Taxes (5,278)
     Investment Tax Credit Adjustment 0
     Federal Income Taxes (33,001)
     State Income Taxes (10,031)
Total Operating Expenses 124,152$                
Operating Income ‐124152.3972
Add: IERCO Operating Income 0
Consolidated Operating Income (124,152)$               
Rate of Return as filed ‐3.45%
#
Exhibit No. 2
Case No. IPC-E-23-12 J. Brady, IPC
Page 6 of 25
Annual Authorized Rate of Return 7.86%
Earnings Impact 147693.8678
Net‐to‐Gross Tax Multiplier 1.347
Monthly Revenue Requirement 198,888$                
Components of Monthly Revenue Requirement
Return on Rate Base 23,541$
Gross-up factor 1.347
Total Monthly Rev Req for Return on Rate Base 31,701
Start-up Costs Amortization 0
Gross-up factor 1.347
Total Monthly Rev Req for Start-Up Costs 0
Other Operating Expense 124,152
Gross-up factor 1.347
Total Monthly Rev Req for Other Operating Exp 167,186
Total Monthly Revenue Requirement 198,888$
#
Exhibit No. 2
Case No. IPC-E-23-12 J. Brady, IPC
Page 7 of 25
Idaho Power Company
Western EIM Participation Costs
Idaho Jurisdictional Revenue Requirement
RATE BASE
Electric Plant in Service
     Intangible Plant 5,792,702$             
     Production Plant 1153936.874
     Transmission Plant 1204191.691
     Distribution Plant 0
     General Plant 0
Total Electric Plant in Service 8150830.238
Less: Accumulated Depreciation 222300.0684
Less: Amortization of Other Plant 4257889.745
Net Electric Plant in Service 3670640.425
Less: Customer Adv for Construction 0
Less: Accumulated Deferred Income Taxes 155984.3915
Add: Plant Held for Future Use 0
Add: Working Capital 0
Add: Other Deferred Amounts 0
Add: Subsidiary Rate Base
TOTAL COMBINED RATE BASE 3,514,656$             
NET INCOME
Operating Revenues
     Sales Revenues 0
     Other Operating Revenues 0
Total Operating Revenues ‐$ 
Operating Expenses
     Operation and Maintenance Expenses 128,743$                
     Depreciation Expenses 5,499
     Amortization of Limited Term Plant 34,967
     Taxes Other Than Income 3,429
Regulatory Debits/Credits
     Provision for Deferred Income Taxes (5,278)
     Investment Tax Credit Adjustment 0
     Federal Income Taxes (33,035)
     State Income Taxes (10,041)
Total Operating Expenses 124,283$                
Operating Income ‐124283.0649
Add: IERCO Operating Income 0
Consolidated Operating Income (124,283)$               
Rate of Return as filed ‐3.54%
#
Exhibit No. 2
Case No. IPC-E-23-12 J. Brady, IPC
Page 8 of 25
Annual Authorized Rate of Return 7.86%
Earnings Impact 147304.0619
Net‐to‐Gross Tax Multiplier 1.347
Monthly Revenue Requirement 198,363$                
Components of Monthly Revenue Requirement
Return on Rate Base 23,021$
Gross-up factor 1.347
Total Monthly Rev Req for Return on Rate Base 31,001
Start-up Costs Amortization 0
Gross-up factor 1.347
Total Monthly Rev Req for Start-Up Costs 0
Other Operating Expense 124,283
Gross-up factor 1.347
Total Monthly Rev Req for Other Operating Exp 167,362
Total Monthly Revenue Requirement 198,363$
#
Exhibit No. 2
Case No. IPC-E-23-12 J. Brady, IPC
Page 9 of 25
Idaho Power Compan
Western EIM Participation Costs
Idaho Jurisdictional Revenue Requiremen
RATE BASE
Electric Plant in Service
     Intangible Plant 5,792,702$            
     Production Plant 1153936.874
     Transmission Plant 1204191.691
     Distribution Plant 0
     General Plant 0
Total Electric Plant in Service 8150830.238
Less: Accumulated Depreciation 227799.0447
Less: Amortization of Other Plant 4292856.294
Net Electric Plant in Service 3630174.9
Less: Customer Adv for Construction 0
Less: Accumulated Deferred Income Taxes 194980.4894
Add: Plant Held for Future Use 0
Add: Working Capital 0
Add: Other Deferred Amounts 0
Add: Subsidiary Rate Base
TOTAL COMBINED RATE BASE 3,435,194$            
NET INCOME
Operating Revenues
     Sales Revenues 0
     Other Operating Revenues 0
Total Operating Revenues ‐$ 
Operating Expenses
     Operation and Maintenance Expenses 157,682$               
     Depreciation Expenses 5,499
     Amortization of Limited Term Plant 34,967
     Taxes Other Than Income 3,429
Regulatory Debits/Credits
     Provision for Deferred Income Taxes (5,278)
     Investment Tax Credit Adjustment 0
     Federal Income Taxes (38,748)
     State Income Taxes (11,777)
Total Operating Expenses 145,773$               
Operating Income ‐145773.0579
Add: IERCO Operating Income 0
Consolidated Operating Income (145,773)$              
Rate of Return as filed ‐4.24%
Annual Authorized Rate of Return 7.86%
Earnings Impact 168273.5813
Net‐to‐Gross Tax Multiplier 1.347
Monthly Revenue Requirement 226,601$               
Components of Monthly Revenue Requirement
Return on Rate Base 22,501$
Gross-up factor 1.347
Total Monthly Rev Req for Return on Rate Base 30,300
Start-up Costs Amortization 0
Gross-up factor 1.347
Total Monthly Rev Req for Start-Up Costs 0
Other Operating Expense 145,773
Gross-up factor 1.347
Total Monthly Rev Req for Other Operating Exp 196,301
Total Monthly Revenue Requirement 226,601$
#
Exhibit No. 2
Case No. IPC-E-23-12 J. Brady, IPC
Page 10 of 25
Idaho Power Company
Western EIM Participation Costs
Idaho Jurisdictional Revenue Requirement
RATE BASE
Electric Plant in Service
     Intangible Plant 5,792,702$             
     Production Plant 1153936.874
     Transmission Plant 1204191.691
     Distribution Plant 0
     General Plant 0
Total Electric Plant in Service 8150830.238
Less: Accumulated Depreciation 233298.021
Less: Amortization of Other Plant 4327822.843
Net Electric Plant in Service 3589709.374
Less: Customer Adv for Construction 0
Less: Accumulated Deferred Income Taxes 233976.5872
Add: Plant Held for Future Use 0
Add: Working Capital 0
Add: Other Deferred Amounts 0
Add: Subsidiary Rate Base
TOTAL COMBINED RATE BASE 3,355,733$             
NET INCOME
Operating Revenues
     Sales Revenues 0
     Other Operating Revenues 0
Total Operating Revenues ‐$ 
Operating Expenses
     Operation and Maintenance Expenses 127,733$                
     Depreciation Expenses 5,499
     Amortization of Limited Term Plant 34,967
     Taxes Other Than Income 3,429
Regulatory Debits/Credits
     Provision for Deferred Income Taxes (5,278)
     Investment Tax Credit Adjustment 0
     Federal Income Taxes (32,836)
     State Income Taxes (9,981)
Total Operating Expenses 123,533$                
Operating Income ‐123533.2124
Add: IERCO Operating Income 0
Consolidated Operating Income (123,533)$               
Rate of Return as filed ‐3.68%
Exhibit No. 2
Case No. IPC-E-23-12 J. Brady, IPC
Page 11 of 25
Annual Authorized Rate of Return 7.86%
Earnings Impact 145513.2622
Net‐to‐Gross Tax Multiplier 1.347
Monthly Revenue Requirement 195,951$                
Components of Monthly Revenue Requirement
Return on Rate Base 21,980$
Gross-up factor 1.347
Total Monthly Rev Req for Return on Rate Base 29,599
Start-up Costs Amortization 0
Gross-up factor 1.347
Total Monthly Rev Req for Start-Up Costs 0
Other Operating Expense 123,533
Gross-up factor 1.347
Total Monthly Rev Req for Other Operating Exp 166,352
Total Monthly Revenue Requirement 195,951$
#
Exhibit No. 2
Case No. IPC-E-23-12 J. Brady, IPC
Page 12 of 25
Idaho Power Company
Western EIM Participation Costs
Idaho Jurisdictional Revenue Requirement
RATE BASE
Electric Plant in Service
     Intangible Plant 5,792,702$             
     Production Plant 1153936.874
     Transmission Plant 1204191.691
     Distribution Plant 0
     General Plant 0
Total Electric Plant in Service 8150830.238
Less: Accumulated Depreciation 238796.9973
Less: Amortization of Other Plant 4362789.392
Net Electric Plant in Service 3549243.849
Less: Customer Adv for Construction 0
Less: Accumulated Deferred Income Taxes 272972.6851
Add: Plant Held for Future Use 0
Add: Working Capital 0
Add: Other Deferred Amounts 0
Add: Subsidiary Rate Base
TOTAL COMBINED RATE BASE 3,276,271$             
NET INCOME
Operating Revenues
     Sales Revenues 0
     Other Operating Revenues 0
Total Operating Revenues ‐$ 
Operating Expenses
     Operation and Maintenance Expenses 138,274$                
     Depreciation Expenses 5,499
     Amortization of Limited Term Plant 34,967
     Taxes Other Than Income 3,429
Regulatory Debits/Credits
     Provision for Deferred Income Taxes (5,278)
     Investment Tax Credit Adjustment 0
     Federal Income Taxes (34,917)
     State Income Taxes (10,613)
Total Operating Expenses 131,361$                
Operating Income ‐131360.7815
Add: IERCO Operating Income 0
Consolidated Operating Income (131,361)$               
Rate of Return as filed ‐4.01%
#
Exhibit No. 2
Case No. IPC-E-23-12 J. Brady, IPC
Page 13 of 25
Annual Authorized Rate of Return 7.86%
Earnings Impact 152820.3576
Net‐to‐Gross Tax Multiplier 1.347
Monthly Revenue Requirement 205,791$                
Components of Monthly Revenue Requirement
Return on Rate Base 21,460$
Gross-up factor 1.347
Total Monthly Rev Req for Return on Rate Base 28,898
Start-up Costs Amortization 0
Gross-up factor 1.347
Total Monthly Rev Req for Start-Up Costs 0
Other Operating Expense 131,361
Gross-up factor 1.347
Total Monthly Rev Req for Other Operating Exp 176,893
Total Monthly Revenue Requirement 205,791$
#
Exhibit No. 2
Case No. IPC-E-23-12 J. Brady, IPC
Page 14 of 25
Idaho Power Company
Western EIM Participation Costs
Idaho Jurisdictional Revenue Requirement
RATE BASE
Electric Plant in Service
     Intangible Plant 5,792,702$             
     Production Plant 1153936.874
     Transmission Plant 1204191.691
     Distribution Plant 0
     General Plant 0
Total Electric Plant in Service 8150830.238
Less: Accumulated Depreciation 244295.9736
Less: Amortization of Other Plant 4397755.941
Net Electric Plant in Service 3508778.324
Less: Customer Adv for Construction 0
Less: Accumulated Deferred Income Taxes 311968.783
Add: Plant Held for Future Use 0
Add: Working Capital 0
Add: Other Deferred Amounts 0
Add: Subsidiary Rate Base
TOTAL COMBINED RATE BASE 3,196,810$             
NET INCOME
Operating Revenues
     Sales Revenues 0
     Other Operating Revenues 0
Total Operating Revenues ‐$ 
Operating Expenses
     Operation and Maintenance Expenses 104,827$                
     Depreciation Expenses 5,499
     Amortization of Limited Term Plant 34,967
     Taxes Other Than Income 3,429
Regulatory Debits/Credits
     Provision for Deferred Income Taxes (5,278)
     Investment Tax Credit Adjustment 0
     Federal Income Taxes (28,314)
     State Income Taxes (8,606)
Total Operating Expenses 106,523$                
Operating Income ‐106522.9996
Add: IERCO Operating Income 0
Consolidated Operating Income (106,523)$               
Rate of Return as filed ‐3.33%
Exhibit No. 2
Case No. IPC-E-23-12 J. Brady, IPC
Page 15 of 25
Annual Authorized Rate of Return 7.86%
Earnings Impact 127462.1021
Net‐to‐Gross Tax Multiplier 1.347
Monthly Revenue Requirement 171,643$                
Components of Monthly Revenue Requirement
Return on Rate Base 20,939$
Gross-up factor 1.347
Total Monthly Rev Req for Return on Rate Base 28,197
Start-up Costs Amortization 0
Gross-up factor 1.347
Total Monthly Rev Req for Start-Up Costs 0
Other Operating Expense 106,523
Gross-up factor 1.347
Total Monthly Rev Req for Other Operating Exp 143,446
Total Monthly Revenue Requirement 171,643$
Exhibit No. 2
Case No. IPC-E-23-12 J. Brady, IPC
Page 16 of 25
Idaho Power Company
Western EIM Participation Costs
Idaho Jurisdictional Revenue Requirement
RATE BASE
Electric Plant in Service
     Intangible Plant 5,792,701.67          
     Production Plant 1,153,936.87          
     Transmission Plant 1,204,191.69          
     Distribution Plant ‐ 
     General Plant ‐ 
Total Electric Plant in Service 8,150,830.24          
Less: Accumulated Depreciation 249,794.95             
Less: Amortization of Other Plant 4,432,722.49          
Net Electric Plant in Service 3,468,312.80          
Less: Customer Adv for Construction ‐ 
Less: Accumulated Deferred Income Taxes 350,964.88             
Add: Plant Held for Future Use ‐ 
Add: Working Capital ‐ 
Add: Other Deferred Amounts ‐ 
Add: Subsidiary Rate Base
TOTAL COMBINED RATE BASE 3,117,347.92          
NET INCOME
Operating Revenues
     Sales Revenues ‐ 
     Other Operating Revenues ‐ 
Total Operating Revenues ‐ 
Operating Expenses
     Operation and Maintenance Expenses 141,240.14             
     Depreciation Expenses 5,498.98 
     Amortization of Limited Term Plant 34,966.55               
     Taxes Other Than Income 3,429.02 
Regulatory Debits/Credits
     Provision for Deferred Income Taxes (5,277.88)                
     Investment Tax Credit Adjustment ‐ 
     Federal Income Taxes (35,502.25)              
     State Income Taxes (10,790.96)              
Total Operating Expenses 133,563.60             
Operating Income (133,563.60)            
Add: IERCO Operating Income ‐ 
Consolidated Operating Income (133,563.60)            
Rate of Return as filed (0.04) 
#
Exhibit No. 2
Case No. IPC-E-23-12 J. Brady, IPC
Page 17 of 25
Annual Authorized Rate of Return 0.08 
Earnings Impact 153,982.23             
Net‐to‐Gross Tax Multiplier 1.35 
Monthly Revenue Requirement 207,355.55             
Components of Monthly Revenue Requirement
Return on Rate Base 20,418.63
Gross-up factor 1.35
Total Monthly Rev Req for Return on Rate Base 27,496.13
Start-up Costs Amortization -
Gross-up factor 1.35
Total Monthly Rev Req for Start-Up Costs -
Other Operating Expense 133,563.60
Gross-up factor 1.35
Total Monthly Rev Req for Other Operating Exp 179,859.42
Total Monthly Revenue Requirement 207,355.55
#
Exhibit No. 2
Case No. IPC-E-23-12 J. Brady, IPC
Page 18 of 25
Idaho Power Company
Western EIM Participation Costs
Idaho Jurisdictional Revenue Requirement
RATE BASE
Electric Plant in Service
     Intangible Plant 5,792,701.67          
     Production Plant 1,153,936.87          
     Transmission Plant 1,204,191.69          
     Distribution Plant ‐ 
     General Plant ‐ 
Total Electric Plant in Service 8,150,830.24          
Less: Accumulated Depreciation 255,293.93             
Less: Amortization of Other Plant 4,467,689.04          
Net Electric Plant in Service 3,427,847.27          
Less: Customer Adv for Construction ‐ 
Less: Accumulated Deferred Income Taxes 389,960.98             
Add: Plant Held for Future Use ‐ 
Add: Working Capital ‐ 
Add: Other Deferred Amounts ‐ 
Add: Subsidiary Rate Base
TOTAL COMBINED RATE BASE 3,037,886.29          
NET INCOME
Operating Revenues
     Sales Revenues ‐ 
     Other Operating Revenues ‐ 
Total Operating Revenues ‐ 
Operating Expenses
     Operation and Maintenance Expenses 186,458.36             
     Depreciation Expenses 5,498.98 
     Amortization of Limited Term Plant 34,966.55               
     Taxes Other Than Income 3,429.02 
Regulatory Debits/Credits
     Provision for Deferred Income Taxes (5,277.88)                
     Investment Tax Credit Adjustment ‐ 
     Federal Income Taxes (44,428.32)              
     State Income Taxes (13,504.05)              
Total Operating Expenses 167,142.66             
Operating Income (167,142.66)            
Add: IERCO Operating Income ‐ 
Consolidated Operating Income (167,142.66)            
Rate of Return as filed (0.06) 
#
Exhibit No. 2
Case No. IPC-E-23-12 J. Brady, IPC
Page 19 of 25
Annual Authorized Rate of Return 0.08 
Earnings Impact 187,040.81             
Net‐to‐Gross Tax Multiplier 1.35 
Monthly Revenue Requirement 251,872.90             
Components of Monthly Revenue Requirement
Return on Rate Base 19,898.16
Gross-up factor 1.35
Total Monthly Rev Req for Return on Rate Base 26,795.25
Start-up Costs Amortization -
Gross-up factor 1.35
Total Monthly Rev Req for Start-Up Costs -
Other Operating Expense 167,142.66
Gross-up factor 1.35
Total Monthly Rev Req for Other Operating Exp 225,077.65
Total Monthly Revenue Requirement 251,872.90
#
Exhibit No. 2
Case No. IPC-E-23-12 J. Brady, IPC
Page 20 of 25
Idaho Power Company
Western EIM Participation Costs
Idaho Jurisdictional Revenue Requirement
RATE BASE
Electric Plant in Service
     Intangible Plant 5,792,701.67          
     Production Plant 1,153,936.87          
     Transmission Plant 1,204,191.69          
     Distribution Plant ‐ 
     General Plant ‐ 
Total Electric Plant in Service 8,150,830.24          
Less: Accumulated Depreciation 260,792.90             
Less: Amortization of Other Plant 4,502,655.59          
Net Electric Plant in Service 3,387,381.75          
Less: Customer Adv for Construction ‐ 
Less: Accumulated Deferred Income Taxes 428,957.08             
Add: Plant Held for Future Use ‐ 
Add: Working Capital ‐ 
Add: Other Deferred Amounts ‐ 
Add: Subsidiary Rate Base
TOTAL COMBINED RATE BASE 2,958,424.67          
NET INCOME
Operating Revenues
     Sales Revenues ‐ 
     Other Operating Revenues ‐ 
Total Operating Revenues ‐ 
Operating Expenses
     Operation and Maintenance Expenses 156,674.85             
     Depreciation Expenses 5,498.98 
     Amortization of Limited Term Plant 34,966.55               
     Taxes Other Than Income 3,429.02 
Regulatory Debits/Credits
     Provision for Deferred Income Taxes (5,277.88)                
     Investment Tax Credit Adjustment ‐ 
     Federal Income Taxes (38,549.05)              
     State Income Taxes (11,717.04)              
Total Operating Expenses 145,025.44             
Operating Income (145,025.44)            
Add: IERCO Operating Income ‐ 
Consolidated Operating Income (145,025.44)            
Rate of Return as filed (0.05) 
#
Exhibit No. 2
Case No. IPC-E-23-12 J. Brady, IPC
Page 21 of 25
Annual Authorized Rate of Return 0.08 
Earnings Impact 164,403.12             
Net‐to‐Gross Tax Multiplier 1.35 
Monthly Revenue Requirement 221,388.53             
Components of Monthly Revenue Requirement
Return on Rate Base 19,377.68
Gross-up factor 1.35
Total Monthly Rev Req for Return on Rate Base 26,094.37
Start-up Costs Amortization -
Gross-up factor 1.35
Total Monthly Rev Req for Start-Up Costs -
Other Operating Expense 145,025.44
Gross-up factor 1.35
Total Monthly Rev Req for Other Operating Exp 195,294.16
Total Monthly Revenue Requirement 221,388.53
#
Exhibit No. 2
Case No. IPC-E-23-12 J. Brady, IPC
Page 22 of 25
Idaho Power Company
Western EIM Participation Costs
Idaho Jurisdictional Revenue Requirement
RATE BASE Mar‐23
Electric Plant in Service
     Intangible Plant 5,792,702$             
     Production Plant 1,153,937               
     Transmission Plant 1,204,192               
     Distribution Plant ‐ 
     General Plant ‐ 
Total Electric Plant in Service 8,150,830               
Less: Accumulated Depreciation 266,292 
Less: Amortization of Other Plant 4,537,622               
Net Electric Plant in Service 3,346,916               
Less: Customer Adv for Construction ‐ 
Less: Accumulated Deferred Income Taxes 467,953 
Add: Plant Held for Future Use ‐ 
Add: Working Capital ‐ 
Add: Other Deferred Amounts ‐ 
Add: Subsidiary Rate Base
TOTAL COMBINED RATE BASE 2,878,963               
NET INCOME
Operating Revenues
     Sales Revenues ‐ 
     Other Operating Revenues ‐ 
Total Operating Revenues ‐ 
Operating Expenses
     Operation and Maintenance Expenses 176,216 
     Depreciation Expenses 5,499 
     Amortization of Limited Term Plant 34,967 
     Taxes Other Than Income 3,429 
Regulatory Debits/Credits
     Provision for Deferred Income Taxes (5,278) 
     Investment Tax Credit Adjustment ‐ 
     Federal Income Taxes (42,407) 
     State Income Taxes (12,890) 
Total Operating Expenses 159,537 
Operating Income (159,537) 
Add: IERCO Operating Income ‐ 
Consolidated Operating Income (159,537) 
Rate of Return as filed (0) 
#
Exhibit No. 2
Case No. IPC-E-23-12 J. Brady, IPC
Page 23 of 25
Annual Authorized Rate of Return 0 
Earnings Impact 178,394 
Net‐to‐Gross Tax Multiplier 1 
Monthly Revenue Requirement 240,229 
Components of Monthly Revenue Requirement
Return on Rate Base 18,857$
Gross-up factor 1.347
Total Monthly Rev Req for Return on Rate Base 25,393
Start-up Costs Amortization 0
Gross-up factor 1.347
Total Monthly Rev Req for Start-Up Costs 0
Other Operating Expense 159,537
Gross-up factor 1.347
Total Monthly Rev Req for Other Operating Exp 214,836
Total Monthly Revenue Requirement 240,229$
#
Exhibit No. 2
Case No. IPC-E-23-12 J. Brady, IPC
Page 24 of 25
Power Cost Adjustment Calendar Month Accrual Calculations
2015-2019 2020 Total 2021 Total 2022 Total Total
Cumulative Total January February March April May June July August September October November December All Years
Sales Based Adjustment Prior New (Effective 6/1/15)Actual Idaho Jurisdictional Calendar Month Sales Mwh 68,807,570 14,160,172 14,720,217 15,127,055 1,255,296 1,120,338 1,156,785Normalized Idaho Jurisdictional Calendar Month Sales Mwh 67,494,460 13,498,892 13,498,892 13,498,892 1,169,255 990,343 981,891 0 0 0 0 0 0 0 0 0 107,991,136
Sales Change Mwh 1,313,110 661,280 1,221,325 1,628,163 86,041 129,995 174,894 0 0 0 0 0 0 0 0 0 (107,991,136)
% of Prior Period Billings at Old Rate 0.000%0.000%0.000%0.000%0.000%0.000%0.000%0.000%0.000%0.000%0.000%0.000%
% of Current Period Billings at New Rate 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000%
Sales Adjustment Prior To Sharing @ 26.72$ $(35,086,299.20) (17,669,401.60) (32,633,804.00) (43,504,509.03) (2,299,003.13)(3,473,460.32) (4,673,164.93)0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 (128,894,013.83)
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%Calendar Month Sales Based Adjustment $(33,331,984.24) (16,785,931.52) (31,002,113.81) (41,329,283.58) (2,184,052.97) (3,299,787.30) (4,439,506.68)0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 (122,449,313.15) Billing Month Sales Based Adjustment (from PCA Worksheet)$(31,321,930.20) (15,344,094.93) (31,319,972.25) (40,271,037.70) (2,327,687.42) (3,053,060.60) (4,171,704.25)0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 (118,257,035.08)
Net Calendar Month Deferral / Accrual $(2,010,054.04) (1,441,836.59)317,858.44 (1,058,245.88)143,634.45 (246,726.70) (267,802.43)0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 (4,192,278.07)
Accounting:Dr (Cr)Dr (Cr)Dr (Cr)Dr (Cr)Dr (Cr)Dr (Cr)Dr (Cr)Dr (Cr)Dr (Cr)Dr (Cr)Dr (Cr)Dr (Cr)Dr (Cr)
799 X00001 999 182326 (2,010,054.04) (1,441,836.59)317,858.44 (1,058,245.88)143,634.45 (246,726.70) (267,802.43)0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 (4,563,172.75)
693 M30108 441 557001 2,010,054.04 1,441,836.59 (317,858.44)1,058,245.88 (143,634.45)246,726.70 267,802.43 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 4,563,172.75
2023
\\dallas\Reg_Pricing\Employees\Brady\PCA\2023\March\Filing\Exhibit No. 2 - PCA Deferral Report - Balancing Adjustment.xlsx
Exhibit No. 2
Case No. IPC-E-23-12 J. Brady, IPC
Page 25 of 25

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-23-12

IDAHO POWER COMPANY

BRADY, DI
TESTIMONY

EXHIBIT NO. 3

1
2
3
4
5
6
7 TOTAL TOTAL
8 SYSTEM IDAHO IDAHO %SYSTEM IDAHO IDAHO %
9 * * * SUMMARY OF RESULTS * * *
10 TOTAL COMBINED RATE BASE 3,816,760,459 3,659,529,896 95.881%
11
12 DEVELOPMENT OF NET INCOME
13 OPERATING REVENUES
14 RETAIL SALES REVENUES (Incl 449.1 Rev)1,048,578,872 1,003,074,365 Direct Assign 1,372,758,056 1,312,548,812 Direct Assign
15 OTHER OPERATING REVENUES 167,118,182 160,109,387 95.8%264,369,926 253,282,475 95.8%
16 TOTAL OPERATING REVENUES 1,215,697,054 1,163,183,751 1,637,127,982 1,565,831,287
17
18 OPERATING EXPENSES
19 OPERATION & MAINTENANCE EXPENSES 793,265,607 755,302,382 95.2%1,105,868,787 1,052,945,345 95.2%
20 DEPRECIATION EXPENSE 120,425,620 115,582,841 96.0%163,581,418 157,003,177 96.0%
21 AMORTIZATION OF LIMITED TERM PLANT 3,510,742 3,369,427 96.0%4,852,904 4,657,563 96.0%
22 TAXES OTHER THAN INCOME 25,015,497 23,226,349 92.8%28,701,676 26,648,887 92.8%
23 REGULATORY DEBITS/CREDITS 1,249,451 1,022,156 81.8%1,753,318 1,434,363 81.8%
24 PROVISION FOR DEFERRED INCOME TAXES (7,519,188) (7,114,821) 94.6%(10,828,285) (10,245,961)94.6%
25 INVESTMENT TAX CREDIT ADJUSTMENT 3,334,345 3,199,107 95.9%5,825,740 5,589,454 95.9%
26 FEDERAL INCOME TAXES 26,089,683 25,397,531 97.3%42,187,659 41,068,433 97.3%
27 STATE INCOME TAXES 9,757,987 9,513,728 97.5%1,940,619 1,892,042 97.5%
28 TOTAL OPERATING EXPENSES 975,129,745 929,498,701 1,343,883,837 1,280,993,303
29
30 OPERATING INCOME 240,567,309 233,685,051 293,244,145 284,837,983
31 ADD: IERCO OPERATING INCOME 6,559,424 6,269,611 95.6%8,782,042 8,394,028 95.6%
32
33 OPERATING INCOME BEFORE OTHER INCOME AND DEDUCTION 247,126,732 239,954,662 302,026,187 293,232,011 97.1%
34 ADD: AFUDC EQUITY 37,285,494 35,749,526 95.9% (L 10)
35 ADD: OTHER INCOME AND DEDUCTIONS 4,596,024 4,462,201 97.1% (L 33)
36
37 INCOME BEFORE INTEREST CHARGES 343,907,704 333,443,738
38 LESS: INTEREST CHARGES 89,041,036 85,373,011 95.9% (L 10)
39
40 NET INCOME 254,866,668 248,070,726
41
42 ACTUAL YEAR-END RESULTS - BEFORE ITC ADJUSTMENT
43 EARNINGS ON COMMON STOCK 254,866,668 248,070,726
44 COMMON EQUITY AT YEAR END 2,631,661,816 2,523,251,118 95.9% (L10)
45
46 RETURN ON YEAR-END COMMON EQUITY 9.68%9.83%
47
48 EARNINGS ON COMMON STOCK @ 9.40 ROE 250,007,873 237,185,605 (L44 * 9.4%)
49 EARNINGS ON COMMON STOCK @ 10 ROE 263,166,182 252,325,112 (L44 * 10%)
50 EARNINGS ON COMMON STOCK @ 10.50 ROE 276,324,491 264,941,367 (L44 * 10.5%)
51
52
53 ACTUAL YEAR-END RESULTS - AFTER ITC ADJUSTMENT:
54 INVESTMENT TAX CREDIT ADJUSTMENT (12,014,483) (L48-L43) / (1-9.4%)
55 ADJUSTED EARNINGS ON COMMON STOCK 236,056,244
56 ADJUSTED COMMON EQUITY AT YEAR-END 2,511,236,635
57 ADJUSTED RETURN ON YEAR-END COMMON EQUITY 9.40%
58
59 IF IDAHO RETURN ON COMMON EQUITY (Line 46) <9.4%
60 ADDITIONAL ITC ADJUSTMENT (Annualized) If L 54 is negative, then 0; if positive, then smaller of L54 or $25,000,000 0
61
62 IF IDAHO RETURN ON COMMON EQUITY (Line 46) >10%
63 IDAHO EARNINGS GREATER THAN 10% ROE BUT LESS THAN 10.5%0 (L43-L49)/(1-10%)
64
65 IF IDAHO RETURN ON COMMON EQUITY (Line 46) >10.5%
66 INCREMENTAL IDAHO EARNINGS GREATER THAN 10.50% ROE 0 (L43-L50)/(1-10.5%)
67
68 Per Order #34071:After Tax Tax Gross Up
69 ROE between 10%-10.5% --CUSTOMER SHARE - 80% (Reduction to rates)0 -
70 ROE between 10%-10.5% --COMPANY SHARE - 20% 0
71 ROE greater than 10.5% (Incremental) -- CUSTOMER SHARE - 55% (Reduction to rates)0 -
ROE greater than 10.5% (Incremental) -- CUSTOMER SHARE - 25% (Offset to Pension balance)0 -
72 ROE greater than 10.5% (Incremental) --COMPANY SHARE - 20% 0
73 0
74
Prepared by: Kelley Noe
Reviewed by:
September Allocations/Ratios
IDAHO POWER COMPANY
ADDITIONAL INVESTMENT TAX CREDIT ANALYSIS
For the Twelve Months Ended December 31, 2022
Actual September 30, 2022 Actual December 31, 2022
Exhibit No. 3
Case No. IPC-E-23-12 J. Brady, IPC
Page 1 of 1
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-23-12
IDAHO POWER COMPANY
BRADY, DI
TESTIMONY
EXHIBIT NO. 4
CONFIDENTIAL