20240515Staff Comments.pdf

RECEIVED
2024 May 15, 3:27PM
IDAHO PUBLIC
Chris Burdin UTILITIES COMMISSION
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
IDAHO BAR NO. 9810
Street Address for Express Mail:
11331 W CHINDEN BLVD, BLDG 8, SUITE 201-A
BOISE, ID 83714
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER )
COMPANY'S APPLICATION FOR ) CASE NO. IPC-E-24-17
AUTHORITY TO IMPLEMENT POWER )
COST ADJUSTMENT ("PCA") RATES FOR )
ELECTRIC SERVICE FROM JUNE 1, 2024 ) COMMENTS OF THE
THROUGH MAY 31, 2025 ) COMMISSION STAFF
COMMISSION STAFF ("STAFF") OF the Idaho Public Utilities Commission
("Commission"), by and through its Attorney of record, Chris Burdin, Deputy Attorney General,
submits the following comments.
BACKGROUND
On April 15, 2024, Idaho Power Company("Company") filed an application
("Application") with the Idaho Public Utilities Commission("Commission")requesting an order
approving an update to Schedule No. 55 based on the Company's quantification of the 2024-
2025 Power Cost Adjustment("PCA"), to become effective June 1, 2024, for the period of June
1, 2024, through May 31, 2025.
The PCA mechanism permits the Company to increase or decrease its PCA rates to
reflect the Company's annual "power supply costs." Due to its diverse generation portfolio, the
Company's actual cost of providing electricity varies from year to year depending on changes in
STAFF COMMENTS 1 MAY 15, 2023

such things as the river streamflow, the amount of purchased power, fuel costs, the market price
of power, and other factors. The annual PCA surcharge or credit is combined with the
Company's "base rates"to produce a customer's overall energy rate.
The PCA quantifies and tracks annual differences between actual Net Power Supply
Expenses ("NPSE") and the normalized or"base level" of NPSE recovered in the Company's
base rates, resulting in a credit or surcharge that is updated annually on June 1. The PCA
mechanism uses a 12-month test period from April through March("PCA Year") and includes a
forecast component and a Balancing Adjustment. The forecast component represents the
difference between the Company's NPSE forecast from the March Operating Plan and base level
NPSE recovered in the Company's base rates. The Balancing Adjustment includes a backward-
looking tracking of differences between the prior PCA Year's forecast and actual NPSE incurred
by the Company, and also tracks the collection of the prior year's Balancing Adjustment.
Except for Public Utility Regulatory Policies Act of 1978 ("PURPA") expenses and
demand response incentive payments, the PCA allows the Company to pass through to customers
95 percent of the annual differences in actual NPSE as compared with base level NPSE, whether
positive or negative. With respect to PURPA expenses and demand response incentive payments
the Company is allowed to pass 100 percent of the difference for recovery or credit through the
PCA. The PCA is also the rate mechanism used by the Company to provide customer benefits
resulting from the revenue sharing mechanism, approved by the Commission in Order No.
34071.
The Company represents that the update to Schedule No. 55, based on the Company's
quantification of the 2024-2025 PCA, will result in an overall decrease to current billed revenue
of approximately $35.7 million, to become effective June 1, 2024. Application at 15.
The Company represents that the system-level forecast of NPSE for the 2024-2025 PCA
Year is $509,555,990, which is $24,648,746 higher than the currently approved base level NPSE
of$484,907,244, and$31,943,394 lower than last year's forecast amount of$541,499,384. Id. at
7-8. The Company states that the 2024-2025 PCA forecast component to be collected from
Idaho customers is $22,712,031. Id. at 8.
The Company represents that the PCA Balancing Adjustment deferral balance at the end
of March 2024, with interest applied, was approximately $90 million, which represents a
decrease to customers rates in this year's PCA Balancing Adjustment. Id.
STAFF COMMENTS 2 MAY 15, 2023

The Company represents that the Company's Idaho jurisdictional year-end Return on
Equity("ROE")was below the 10.0 percent ROE threshold for revenue sharing; therefore, the
2024-2025 PCA does not include a revenue sharing component. Id. at 9.
The Company represents that for the 2024-2025 PCA Year, the Company's uniform PCA
is comprised of. (1) the 0.1501 cents per kilowatt-hour("kWh") for the 2024-2025 projected
power cost of serving firm loads under the current PCA methodology and 95 percent sharing;
and(2) the 0.5946 cents per kWh for the 2023-2024 Balancing Adjustment, with the sum of
these two components resulting in a 0.7447 cents per kWh charge for all rate classes. Id. at 9-10.
STAFF ANALYSIS
The Company's proposed update to Schedule 55 reflects an approximate decrease of
$35.7 million, or 2.31 percent, in billed revenue, effective June 1, 2024, through May 31, 2025.
Based on its review of the Application, audit of sampled transactions, examination of the
testimony and workpapers of Company witness Jessica G. Brady, and a review of the Company
responses to Staff s audit and production requests, Staff recommends the Commission approve
the Company's Application and Schedule 55, as filed, effective June 1, 2024.
Staff examined the Company's sales and expenses for the historical 2023-2024 PCA
year and its forecasting methods,projected revenues, and expenses for the upcoming 2024-2025
PCA year. Staff also verified that the Company's filing and methods complied with prior,
relevant Commission Orders. Staff believes that:
1. The Company's forecast for the upcoming PCA year(2024-2025) of electricity
sales, loads, fuel consumption, fuel costs, and purchased power costs are reasonable;
2. The Company should apprise the Commission of how the forecast changes during
the PCA Year; and, if an adjustment to the forecast rate is warranted, the Company
should make an off-cycle filing;
3. The Company's balancing adjustment is accurate and the NPSE is prudent;
4. The NPSE from the previous PCA case is prudent; and
5. The Commission should consider late filed comments by customers.
STAFF COMMENTS 3 MAY 15, 2023

Components of Proposed PCA Increase
The components of the $35.7 million decrease in the PCA are shown in Table No. 1
below.
Table No. 1: Revenue Impact by PCA Rate Component,Idaho Basis
2023-2024 PCA1 2024-2025 PCA2 Difference
PCA Forecast $ 52,202,870 $ 22,712,031 $ (29,490,839)
PCA Balancing Adjustment $ 96,189,461 $ 89,970,511 $ (6,218,950)
PCA Total $ 148,392,331 $ 112,682,542 $ (35,709,789)
Revenue Sharing $ 0 $ 0 $ 0
Total Revenue Impact $ 148,392,331 $ 112,680,542 $ ($35,709,789)
The Company's NPSE varies each year depending on factors, which may include
changes in river streamflow, the amount of purchased power, fuel costs, market energy price of
power, and a limited coal supply. The PCA trues up annually to differences between actual
NPSE and the NPSE collected through base rates. With the PCA, the Company's customers are
paying their actual NPSE.
The Company's power supply costs and surplus sales are subject to a 95 percent/5
percent sharing band, with the Company responsible for 5 percent of the excess NPSE compared
to NPSE revenue the Company collected through base rates. The Commission created this
sharing band to provide a financial incentive for the Company to make careful resource
acquisition and operating decisions to reduce costs. If actual costs are less than revenue
collected, the Company keeps 5 percent of that difference. If costs are more than revenue
collected, customers pay 95 percent of the excess costs, and the Company absorbs 5 percent.
In Order No. 36042, the Company's base rates were changed, effective January 1, 2024.
Because the PCA period runs from April through March, April through December's base rates
are set at the previously authorized levels, while January through March base rates are set at the
1 Because Table No. 1 contains the expected billed revenue impact to customer,the"2023-2024 PCA"column reflects
approved PCA rates applied to the June 2023 through May 2024 sales forecast and will not tie to the specific dollar
amounts approved in the 2023 PCA filing.
2 The"2024-2025 PCA"column reflects the Company's proposed rates applied to the June 2024 through May 2025
forecast and may not tie exactly to the figures listed in the Company's Application due to the rounding of rates to six
digits.
STAFF COMMENTS 4 MAY 15, 2023

newly authorized levels. Staff verified that the Company used the correct base rates for each
month's calculations.
Forecast Analysis
The Company used its March 2024 Operating Plan to forecast the difference between
expenses embedded in base rates and the expenses the Company expects to incur in the coming
year. The Company uses a dispatch simulation model to analyze projected load and to determine
and analyze resource balance and energy supply for the upcoming PCA Year. The forecast also
accounts for forward market energy prices, hydro generation, fuel prices, existing hedge
transactions, and costs associated with PURPA and non-PURPA contracts.
In its forecast, the Company projects that hydro and gas generation will be higher than
average. The former is due to a wet winter that has filled the reservoirs, and the latter is due to a
coal-to-gas conversion of Unit Nos. 1 and 2 at Jim Bridger Power Plan(`Bridger"). The
increased generation from these two resource types will offset the overall increase in system
load, and it will enable the Company to make fewer expensive market purchases. Since the
NPSE of hydro generation is zero, the increased hydro generation helps to reduce the overall
NPSE.
Staff also notes that the Company forecasts an increase of approximately 500 gigawatt-
hours ("GWh") of coal generation from what it was able to generate in the 2023-2024 PCA year.
Since coal on average is the cheapest form of generation after hydro, the increased generation
reduces the forecast NPSE. Staff encourages the Company to actively manage coal operations to
meet or exceed the coal forecast, as long as coal remains cost-effective.
Based on the 2024-2025 PCA forecast, the Company expects to collect$22.7 million
above the amount in base rates from Idaho customers. This results in a decrease of$29.5 million
compared to last year's PCA forecast. Over or under-collected amounts due to forecast variance
will be trued up in the following year. Staff believes the Company's forecast is reasonable and
maximizes the use of the most cost-effective resources.
Balancing Adjustment
The Balancing Account incorporates additional components into the PCA as shown in
Table No. 2 below. In Order No. 35804, the Commission directed the Company to collect the
STAFF COMMENTS 5 MAY 15, 2023

2022-2023 deferral balance over two years. As a result, a majority of the $89.8 million deferral
balance is the balance remaining from the 2022-2023 PCA period.
Table No. 2: Balancing Account Summary
Amount
Beginning Balance $ 190,205,569
2023-2024 Incremental Deferral $ 153,247,264
2023-2024 Forecast Revenues Collections $ (174,657,030)
2023-2024 Prior Balance Revenues Collected $ (82,707,151)
Revenue Sharing $ 0
Current Month Interest $ 3,882,536
2023-2024 Ending Deferral Balance $ 89,791,188
Staff comments below focus on the incremental deferral balance for the period of April
2023 through March 2024 first, followed by the remaining components.
Incremental Deferral Balance
To best explain the incremental deferral balance of$153 million, Staff divided it into two
subordinate components: (1)the NPSE from April 1, 2023, to March 31, 2024; and(2) other
PCA expenses. Table No. 3, below, summarizes the two sub-components, which are the
amounts allocated to Idaho customers after the jurisdictional allocation and the 95 percent/5
percent sharing band are applied.
Table No. 3: PCA Incremental Deferral Balance Summary
Amount
Net Power Supply Expenses $ 144,289,803
Other PCA Expenses $ 8,957,461
Total Incremental Deferral Balance $ 153,247,264
STAFF COMMENTS 6 MAY 15, 2023

Staff s review included: (1) an audit of the deferral components; (2) an analysis of the
methods and the basis used to calculate the cost deferrals and account balances; (3) an
examination of the actual NPSE, including the Company's energy risk management policies and
actions; and(4) an analysis to determine if the Company prudently dispatched resources,
purchased power, and sold power in the wholesale market. Based on its review, Staff has
confidence that the Company's proposed deferral is accurate and that it conforms to past
Commission orders.
Net Power Supply Expense
NPSE Analysis
The $144 million NPSE was the main contributor to the $153 million incremental
deferral balance. Staff reviewed the major sub-components of the NPSE and believes they were
prudent. A brief discussion of each resource type follows, with all the cost and megawatt-hour
("MWh") quantities obtained from Brady's testimony.
Because hydro generation incurs zero NPSE, it was the most cost-effective power
generation option for the Company. Due to abundant snowpack, the Company was able to
generate approximately 1,463 GWh more than the previous PCA year, which translated into a
significant NPSE reduction.
The next most cost-effective resource was coal, with an average unit cost of
approximately $41 per megawatt-hour("MWh"). The Company generated approximately 695
GWh less than the previous year, which meant the Company had to make up for the under-
production with a more expensive option. Staff has thoroughly researched the ongoing coal-
supply challenges faced by the Company and believes that the Company did all that it could to
maximize its coal supply. Staff is encouraged that the Company forecasts coal generation to
increase next year by 496 GWh compared to the actual generation this year.
The third most cost-effective resource was gas,with an average unit cost of
approximately $56 per MWh. Annual gas generation increased by approximately 369 GWh (14
percent) from the previous year. Staff believes this increased quantity of gas generation was
reasonable because the only alternative to supply the system load was market purchases, which
were slightly more expensive, on average, than gas.
STAFF COMMENTS 7 MAY 15, 2023

The most-expensive power option for the Company (except for must-take Qualified
Facility("QF")purchases)was market purchases, with an average unit cost of approximately
$58 per MWh. The Company purchased approximately 385 GWh less than the previous year,
which helped reduce the NPSE from last year's record high. Staff believes this outcome is
reasonable. However, given that market purchases have been the most expensive non-QF
resource for the past two years, Staff is concerned with the Company's heavy dependence on
them. Market purchases supplied 20 to 25 percent of the Company's annual load each of the past
two years. Furthermore, the Company's focus on acquiring additional transmission resources to
meet future load growth will only increase the Company's reliance on market purchases.
NPSE Observations
First, Staff requests that the Company consider adjusting its annual PCA testimony to
focus more on the actual expenses incurred, and less on the PCA forecast. Because the PCA is
fundamentally a true-up of actual expenses, Staff believes the testimony should emphasize
analysis of the actual expenses and actual generation. Staff also requests that the Company
provide a table that lists the actual expenses and actual MWh for each resource type. Currently
some of this information is dispersed in the narrative and some is not available.
Second, Staff notes that gas and market purchases continued to be the primary
contributors to the high NPSE, contributing 98 percent of the non-QF deficit. Table No. 4
compares the actual gas and market purchase expenses to the base expenses for the previous two
years.
Table No. 4: Comparison of Actual and Base Expenses for Gas and Market Purchases
2022-2023 2023-2024
Expense Base Actual Difference Basel Actual Difference
Gas $ 33,367,563 $ 178,317,314 $ 144,949,751 $ 53,513,746 $ 171,893,815 $ 118,380,070
Market Purchase $ 62,606,593 $ 404,938,271 $ 342,331,678 $ 70,816,616 $ 218,730,125 $ (147,913,509)
Note 1:The base amount increased for January-March 2024,in accordance with the 2023 rate case.
Upon examination of the expenses month-by-month, Staff observed that actual expenses
exceeded base expenses every month of the year. However, the biggest differences occurred in
the peak summer months (June, July, and August) and especially during the peak winter months
(November, December, and January). These six months incurred 77 percent of the entire year's
STAFF COMMENTS 8 MAY 15, 2023

deficit. The data is similar for the previous year. Even after incorporating the new higher base
amounts in January 2024, the Company's actual gas and market purchase expenses for that
month exceeded the base by approximately $59 million.
Staff is concerned that underlying market conditions may be shifting, and the Company's
reliance on gas and market purchases in the peak months may continue to be exorbitantly
expensive. Staff encourages the Company to search for solutions to mitigate the cost risk in the
peak months, and to discuss its efforts in the next PCA filing.
Lack of Coal Supply and NPSE Prudence for 2022-2023 PCA
Staff recommends that the Commission recognize the NPSE from the 2022-2023 PCA as
prudent.
In last year's PCA case (IPC-E-23-12), Staff expressed concern about the Company's
coal supply shortfall, which resulted in under-generation of inexpensive coal power, and required
the Company to compensate with more expensive Gas generation and Market Purchases. The
Commission withheld a determination of prudence for the NPSE and ordered Staff to investigate
and issue a report. Order 35804 at 8. Staff filed its report, which the Company included in this
case as Confidential Attachment 3. The Company provided its response to Staff s report via
Attachments 4, 5, and 6.
Staff reviewed the Company's response and agrees that the Company made reasonable
efforts to procure additional coal for Bridger in the first half of the PCA year. Furthermore, Staff
accepts the Company's counterfactual analysis, which concludes that early hedging actions
would not have avoided additional NPSE.
Accordingly, Staff believes that the Company's NPSE for 2022-2023 was prudent.
Hells Canyon Unit No. 3
As part of last year's PCA case, the Commission ordered the Company to inform it of the
outcome of the damage claim to Hells Canyon Unit No. 3. Order 35804 at 9.
The Company complied by reporting the outcome of the damage claim in its current
application. Application at 12. Staff confirmed that the liquidated damages were credited to the
NPSE, reducing the total expense.
STAFF COMMENTS 9 MAY 15, 2023

Other PCA Expenses
Other PCA expenses include the difference between forecast expenses from the prior
PCA Year and what is embedded in base rates: (1) Idaho Jurisdictional QF, PURPA Expense
Deferral, and Export Credit Rate ("ECR"); (2) the Idaho Revenue Adjustment from the Sales
Based Adjustment ("SBA") Rate; (3)the difference between actual DR incentive payments and
amounts recovered in base rates; (4)the Actual Renewable Energy Credit ("REC") revenues; and
(5) Idaho Power Energy Imbalance Market("EIM") Participation Costs.
1. QFIPURPA/ECR. PURPA and QF contracts are not subject to the 95 percent sharing
band but are subject to jurisdictional allocation between the Company's Idaho and Oregon
customers. Additionally, as established in Order No. 36048, the Commission approved the
Company's proposal to implement an ECR subject to 100%recovery through the PCA as a
NPSE, effective January 1, 2024. The effective date of the order creates an overlap with the
PCA balancing adjustment between Jan 1, 2024, and March 31, 2024.
For the PCA deferral year, the Company calculated that QF, PURPA, and ECR expenses
were $50.5 million above the amount recovered in base rates. Staff reviewed QF, PURPA, and
ECR expenses and agrees with the Company's calculation of an increase of$50.5 million to the
deferral balance.
2. SBA Rate. The SBA is used to determine the over- or under-recovery of actual NPSE
due to sales that are higher or lower than sales used to determine base rates (subject to 95 percent
customer sharing). It is the difference in actual and base rate sales multiplied by the SBA rate.
The SBA Rate is $26.72/MWh between April and December 31, 2023, of the PCA year, as
established in Order No. 33307, and $30.90/MWh beginning January 1, 2024, through March, as
established in Order No. 36042.
The Company calculated a decrease of$24.1 million due to the Company's over-
recovery of actual NPSE. Staff determined that the correct SBA Rate was used for each month's
calculation and agrees with the Company's calculation of a $24.1 million decrease to the deferral
balance.
3. DR Incentive Payments. The Company's DR incentive payments are not subject to
the sharing band and are wholly allocated to Idaho. The Company calculates a $2.5 million DR
STAFF COMMENTS 10 MAY 15, 2023

incentive decrease due to the actual DR incentive payments being less than those recovered in
the base. The prudence of DR incentive payments will be determined in the Company's annual
Demand-Side Management prudency filing currently before the Commission(Case No. IPC-E-
24-11). If there are any DR disallowances in that case they will be reflected in next year's PCA
deferral balance. Staff reviewed the DR incentive expenses and agrees with the Company's
calculation of a $2.5 million decrease to the deferral balance.
4. REC Revenues. In Order No. 30818, the Commission required the Company to sell
all RECs it receives for renewable generation to benefit its customers. REC sales are not
included in the base and all sales are returned to customers at the 95 percent sharing band. The
Company calculates a $18.4 million decrease due to the sales of RECs. Staff reviewed the
Company's REC transactions and agrees with the Company's calculation of a$18.4 million
decrease to the deferral balance.
5. EIM Participation Costs. The Company's operation and maintenance expenses
attributed to its participation in the EIM are included in the PCA deferral in compliance with
Order No. 34100. The benefits of the EIM market, such as lower energy purchase prices and
increased sales volume, flow through the PCA. Including participation costs appropriately
matches costs with benefits of sales on the EIM. As established in Order No. 36042, EIM
participation costs are no longer tracked through the PCA and now are included in customer base
rates beginning January 1, 2024. However, EIM participation costs still occurred in this past
PCA period from April through December 31, 2023. The Company calculated a$1.9 million
increase based upon costs of EIM participation. Staff reviewed EIM participation expenses and
agrees with the Company's calculation of an increase of$1.9 million to the deferral balance.
Forecasted Revenues Collected
The Company calculated $174.7 million in revenue collected from its 2023-2024 PCA
forecast. Staff reviewed the components of the Company's calculation and agrees with the
$174.7 million decrease to the deferral balance.
STAFF COMMENTS 11 MAY 15, 2023

Collections of the 2022-2023 Deferral Balance
The Company calculated $82.7 million in revenue collected from its balancing
adjustment in the 2023-2024 PCA year. Staff reviewed the components of the Company's
calculation and agrees with the Company's calculation of a$82.7 million decrease to the deferral
balance.
Interest
The deferral balance accrues interest monthly at the Commission-approved customer
deposit rate of two percent in 2023 and five percent in 2024. The Company calculated an
interest balance of$3.9 million. Staff agrees with the monthly balance amounts and determined
that interest rates applied to each month's balance were accurate, resulting in the $3.9 million
increase to the deferral balance, as calculated by the Company.
Revenue Sharing and Rate Calculation
The revenue sharing mechanism, established in 2010 and last modified in Order No.
34071 in 2018, requires the Company to share revenues with customers based on its actual Idaho
jurisdictional year-end ROE, if it exceeds ten percent. In 2023, the Company calculated that
ROE was below ten percent, resulting in no revenue sharing benefit to customers. Staff
reviewed the revenue sharing inputs and calculations and agree with the Company's
determination.
PCA Rate Calculations
Staff reviewed the components that make up this year's PCA rates. Based on its review,
Staff believes that the methods used comply with Commission orders and are calculated
accurately.
Staff s review of all the rate components included verification that rates were calculated
accurately and that the Company's methods comply with Commission orders. Staff confirmed
that the revenue requirement was allocated across customer classes on an equal cents per kWh
basis, which ensures that customers share the PCA revenue requirement based on the amount of
energy consumed.
STAFF COMMENTS 12 MAY 15, 2023

Overall Impact of Filings Effective June 1, 2023
On March 15, 2024, the Company filed its annual Fixed Cost Adjustment ("FCA") in
Case No. IPC-E-24-10. The Company's 2024 FCA filing proposes a$10.6 million increase in
current billed revenue, or a 1.44 percent increase, for Idaho Residential and Small General
Service customers, effective June 1, 2024, through May 31, 2025.
If the PCA and FCA applications are approved as filed, the combined impact is an overall
decrease in current billed revenue of$25.1 million, or 1.63 percent. The Company has
proposed to implement the PCA and FCA rates on June 1, 2024. The impact by revenue class is
reflected in the following tables.
Proposed 2023-2024 Revenue Impact by Class:
Percentage Increase from Current Billed Rates by Proposed Change PCA
Small Large
General General
Residential Service Service Large Power Irrigation
-1.91% -1.57% -2.57% -3.12% -2.33%
FCA
Small Large
General General
Residential Service Service Large Power Irrigation
1.44% 1.39% N/A N/A N/A
Total Combined Im act
Small Large
General General
Residential Service Service Large Power Irrigation
-0.47% -0.17% -2.57% -3.12% -2.33%
Customer Notice and Press Release
The Company's press release and customer notice were included with its Application.
Staff reviewed the documents and determined that both meet the requirements of Rule 125 of the
Commission's Rules of Procedure (IDAPA 31.01.01.125). The notice was or will be included
with bills mailed to customers beginning April 18 and ending May 25, 2024. Customers whose
bills will be mailed on May 18, 21, 22, 23, 24, and 25 were sent a direct mail postcard, mailed no
later than May 17, outlining the Company's filing.
STAFF COMMENTS 13 MAY 15, 2023

Even with the Company's attempt to provide earlier notice to some customers, many will
not have a reasonable opportunity to file timely comments with the Commission by the May 15
comment deadline. Customers should have the opportunity to file comments and have those
comments considered by the Commission. Staff recommends that the Commission consider late
filed comments by customers. As of May 14, 2024, no customer comments had been filed.
STAFF RECOMMENDATIONS
Staff recommends that the Commission approve the Company's Application and Schedule
55, as filed, effective June 1, 2024. Staff also believes that:
1. The Company's forecast for the upcoming PCA year(2024-2025) of electricity
sales, loads, fuel consumption, fuel costs, and purchased power costs are reasonable;
2. The Company should apprise the Commission of how the forecast changes during
the PCA Year•, and, if an adjustment to the forecast rate is warranted, the Company
should make an off-cycle filing;
3. The Company's balancing adjustment is accurate and the NPSE is prudent;
4. The NPSE from the previous PCA case is prudent; and
5. The Commission should consider late filed comments by customers.
Respectfully submitted this 151h day of May 2024.
b�-,A Z4- A
Chris Burdin
Deputy Attorney General
Technical Staff. James Chandler
Matt Suess
Jason Talford
Curtis Thaden
1:\Utility\UMISC\COMMENTS\IPC-E-24-17 Comments.doex
STAFF COMMENTS 14 MAY 15, 2023

CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS DAY OF MAY 2024,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN CASE
NO. IPC-E-24-17, BY E-MAILING A COPY THEREOF, TO THE FOLLOWING:
MEGAN GOICOECHEA ALLEN MATTHEW T. LARKIN
LISA NORDSTROM TIM TATUM
IDAHO POWER COMPANY JESSI BRADY
PO BOX 70 IDAHO POWER COMPANY
BOISE ID 83707-0070 PO BOX 70
E-MAIL: BOISE ID 83707-0070
mgoicoecheaallenaa,,idahopower.com E-MAIL: [e-mail]
Inordstrom(a,idahopower.com ttatum(cDidahopower.com
dockets a,idahopower.com jbrady0midahopower.com
PATRICIA JORDA , SECRETARY
CERTIFICATE OF SERVICE