20260401Application and Direct Testimony.pdf

_ ROCKY MOUNTAIN 1407 West North Temple, Suite 330
POWER. Salt Lake City, Utah 84116
A DIVISION OF PACIFICORP
April 1, 2026 RECEIVED
APRIL 1, 2026
VIA ELECTRONIC FILING IDAHO PUBLIC
UTILITIES COMMISSION
Commission Secretary
Idaho Public Utilities Commission
11331 W Chinden Blvd
Building 8 Suite 201A
Boise, Idaho 83714
RE: CASE NO. PAC-E-26-05 -IN THE MATTER OF THE APPLICATION OF
ROCKY MOUNTAIN POWER REQUESTING APPROVAL TO RECOVER $4.1
MILLION ASSOCIATED WITH THE ECAM DEFERRAL AND REFUND $1.4
MILLION ASSOCIATED WITH THE RRA
Attention: Commission Secretary
Please find Rocky Mountain Power's Application in the above referenced matter, along with the
direct testimony and exhibits of Company witnesses Mr. Jack Painter, Mr. Nicholas L.
Highsmith and Mr. Kenneth Lee Elder. Their workpapers are also provided.
All formal correspondence and data requests regarding this filing should be addressed as follows:
By E-mail (preferred): datarequestkpacificorp.com
j ana.saba(&j2acificorp.com
j o s eph.dallas kpacificorp.com
By regular mail: Data Request Response Center
PacifiCorp
825 NE Multnomah, Suite 2000
Portland, OR 97232
Informal inquiries may be directed to Jana Saba, Director Regulation and Regulatory Operations,
at(801) 220-2823.
Sincerely,
0oelle Steward
Senior Vice President of Regulation

Joe Dallas (ISB# 10330)
825 NE Multnomah, Suite 2000
Portland, OR 97232
Telephone: [phone]
Email: joseph.dallas(&,pacificorp.com
Attorney for Rocky Mountain Power
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF ROCKY MOUNTAIN POWER ) CASE NO. PAC-E-26-05
REQUESTING APPROVAL TO RECOVER )
$4.1 MILLION ASSOCIATED WITH THE ) APPLICATION OF
ECAM DEFERRAL AND REFUND $1.4 ) ROCKY MOUNTAIN POWER
MILLION ASSOCIATED WITH THE RRA
Rocky Mountain Power, a division of PacifiCorp ("Company" or "Rocky Mountain
Power"), in accordance with Idaho Code § 61-502, § 61-503, and RP 052, hereby respectfully
submits this application("Application")to the Idaho Public Utilities Commission("Commission")
pursuant to the Company's approved energy cost adjustment mechanism ("ECAM"). The
Company is requesting approval of approximately$4.1 million of deferred costs from the deferral
period beginning January 1, 2025,through December 31, 2025, ("Deferral Period"). This deferral,
plus the requested recovery associated with the previous ECAMs and associate carrying charges
as described herein, results in a 0.7 percent overall average decrease for all Idaho customers.
The Company is also requesting to return$1.4 million related to sales of renewable energy
credits ("RECs") to Idaho customers over a one-year period, beginning June 1, 2026, through
Electric Service Schedule No. 98, REC Revenue Adjustment ("RRA"). This is comprised of the
2026 RRA Deferral Balance of$1.3 million and interest of$32 thousand. This results in a 0.4
percent overall average decrease for all Idaho customers.
In support of its Application, Rocky Mountain Power states as follows:
APPLICATION OF ROCKY MOUNTAIN POWER Page 1

1. Rocky Mountain Power is a division of PacifiCorp, an Oregon corporation, which
provides electric service to retail customers through its Rocky Mountain Power division in the
states of Idaho,Wyoming,and Utah.Rocky Mountain Power is a public utility in the state of Idaho
and is subject to the Commission's jurisdiction with respect to its prices and terms of electric
service to retail customers in Idaho pursuant to Idaho Code §61-129. Rocky Mountain Power is
authorized to do business in the state of Idaho providing retail electric service to approximately
91,000 customers in the state.
I. Energy Cost Adjustment Mechanism (SCAM) —Schedule 94
BACKGROUND
2. The ECAM became effective July 1, 2009, pursuant to an agreement among
parties.' The ECAM allows the Company to collect or credit the difference between the actual net
power costs ("Actual NPC") incurred to serve customers in Idaho and the NPC collected from
Idaho customers through rates set in general rate cases ("Base NPC").
3. Included in the ECAM are NPC as defined in the Company's general rate cases and
modeled by the Company's Generation and Regulation Initiative Decision ("GRID") production
dispatch model.2 Specifically,NPC includes amounts booked to the following FERC accounts:
• Account 447 (sales for resale, excluding on-system wholesale sales and other
revenues not modeled in GRID),
• Account 501 (fuel, steam generation, excluding fuel handling, start-up fuel/gas,
diesel fuel, residual disposal and other costs not modeled in GRID),
• Account 503 (steam from other sources),
1 In the Matter of the Application of Rocky Mountain Power for Approval of an Energy Cost Adjustment Mechanism
(ECAM),Case No.PAC-E-08-08,Order No.30904(September 29,2009)("ECAM Order").
z Id. at 2-3.
APPLICATION OF ROCKY MOUNTAIN POWER Page 2

• Account 547 (fuel, other generation),
• Account 555 (purchased power, excluding BPA residential exchange credit pass-
through if applicable), and
• Account 565 (transmission of electricity by others).
4. On a monthly basis, the Company compares the Actual NPC to the Base NPC and
defers the difference into the ECAM balancing account. This comparison is on a system-wide,
dollar per megawatt-hour basis.'
5. In addition to the difference between Actual NPC and Base NPC, the ECAM
includes the following additional components: the Load Change Adjustment Revenues
("LCAR"),4 coal stripping costs under Emerging Issues Task Force ("EITF") 04-6,5 Production
Tax Credits ("PTC"),6 the reasonable energy price ("REP"), as defined in the 2020 Protocol,
qualified facility("QF")costs,7 and wind availability liquidated damages.'These components are
described in more detail below.
6. The ECAM includes a symmetrical sharing band of 90 percent (customers) / 10
percent (Company) that shares the differential between Actual NPC and Base NPC, LCAR, and
the EITF 04-06 coal stripping costs. The components of the ECAM subject to the sharing band are
described in more detail below.
3 Id. at 3.
4 Id. at 4.
5 See In the Matter of the Application of PacifiCorp DBA Rocky Mountain Power for Approval of an Accounting
Order Authorizing the Deferral of Costs Associated with Coal Mine Stripping Activities, Case No.PAC-E-09-08,
Order No. 30987(January 22,2010).
6 In the Matter of PacifiCorp DBA Rocky Mountain Power's Application to Modem the Energy Cost Adjustment
Mechanism and Increase Rates,Case No.PAC-E-15-09,Order No.33440 at 5 (December 23,2015)(2015 ECAM
Order).
7 In the Matter of the Application for Approval of the 2020 PacifiCorp Inter-Jurisdictional Allocation Protocol,Case
No.PAC-E-19-20,Order No. 34640(April 22,2020).
'In the Matter of Application of Rocky Mountain Power for Binding Ratemaking Treatment for Wind Reporting,
Case No.PAC-E-17-06,Order No.33954 at 5(December 28,2017).
APPLICATION OF ROCKY MOUNTAIN POWER Page 3

7. PTCs are tracked in the ECAM without applying the sharing band.' Under the
Internal Revenue Code ("IRC"), a wind facility generates a PTC equal to an inflation-adjusted 1.5
cents per kilowatt hour of electricity produced and sold to a third-parry. 10 The PTC is in place for
a period of 10 years beginning on the date the facility is placed in-service for income tax
purposes." As published in Internal Revenue Service ("IRS")Notice 2025-38, the 2025 PTC rate
for electricity generated from qualifying wind facilities placed in service prior to January 1, 2022,
is 3.0 cents per kilowatt hour.12 The 2025 PTC rate for electricity generated from qualifying wind
facilities placed in service after December 31, 2021 is 3.0 cents per kilowatt hour.13 Additionally,
facilities placed in service after December 31,2022,may also qualify for a 10%bonus credit if the
facility is located in a qualified `energy community.'14 PTCs are reflected as a reduction to current
income tax expense on the financial statements and for ratemaking purposes.A forecasted level of
PTCs at the then-current IRC value was included in base rates benefiting customers; however, the
quantity and value of PTCs received is dependent on the inflation-adjusted rate effective when
they are produced and the amount of generation at eligible facilities. Generation from these
facilities is highly dependent on weather, varying from year to year as weather patterns fluctuate.
12015 ECAM Order at 5.
10 IRC section 45(a).
11 IRC section 45(a).
12 This rate is applicable to all of the Company's credit-eligible wind projects in service as of December 31,2024,
other than Foote Creek II-IV,Rock River I,and Rock Creek I and II.
"Also as published in IRS Notice 2025-38,the 2025 PTC rate for electricity generated from qualifying wind
facilities placed in service after December 31,2021,is.60 cents per kilowatt hour. If the facility(i)has a maximum
output of less than 1 megawatt,(ii)began construction prior to January 29,2023,or(iii)satisfies the prevailing
wage and apprenticeship requirements,then the credit amount is multiplied by 5,or 3.0 cents per kilowatt hour.
Foote Creek II-IV,Rock River I and Rock Creek I and II were placed in service after December 31,2021,and began
construction prior to January 29,2023,making the applicable 2025 credit rate for these projects 3.0 cents per
kilowatt hour.
14 Foote Creek II-IV and Rock River I are located in Census Tract Number FIPS Code 56007968100,which is a
qualified energy community pursuant to IRS Notice 2023-29,Appendix C. In addition,Rock Creek I and II are
located in Census Tract Number FIBS Code 56001963900,which is also a qualified energy community per IRS
Notice 2023-29,Appendix C. Therefore,all of these projects qualify for a 10%bonus credit.The bonus credit is
calculated by multiplying standard credit by 10%(e.g.,kilowatt hours produced and sold x applicable PTC Rate=
Standard Credit).
APPLICATION OF ROCKY MOUNTAIN POWER Page 4

To the extent that actual generation from these facilities varies from the level in base rates, the
value of the energy is reflected in Actual NPC and a corresponding adjustment is made to the PTC
that customers receive through the ECAM. Facilities that meet IRC qualifications are eligible for
PTCs for the first ten years after becoming commercially operational. While many of the
Company's wind facilities have reached their ten-year anniversary and would no longer be eligible
for PTCs, the repowering program undertaken by the Company has extended this benefit for an
additional ten years.
PROPOSED ECAM RATES
8. In support of the proposed ECAM rates included in this Application, Rocky
Mountain Power has filed the testimony and exhibits of Company witnesses Mr. Jack Painter and
Mr. Kenneth Lee Elder, Jr. Mr. Painter's testimony describes the Actual NPC incurred by the
Company to serve retail load for the Deferral Period and explains the differences between Actual
NPC and Base NPC to support the ECAM rate under Schedule 94. Mr. Elder's testimony describes
how the Company's proposed rates were set to recover the 2025 ECAM deferral balances through
Electric Service Schedule No. 94 -Energy Cost Adjustment, ("Schedule 94").
9. Exhibit No. 1 to Mr. Painter's testimony illustrates the detailed calculation of the
ECAM deferral. The deferral is calculated monthly by comparing Idaho-allocated Actual NPC to
the Base NPC collected in rates that was established in the Company's 2024 Rate Case.15 As a
result of the 2024 Rate Case,REC revenue was removed from the ECAM calculation and separated
into the new RRA mechanism beginning February 1, 2025. Also, wheeling revenues were added
to the ECAM beginning February 1, 2025. For the Deferral Period the NPC differential was
15 In the Matter of Rocky Mountain Power's Application for Authority to Increase Its Rates and Charges in Idaho,
Case No.PAC-E-24-04. (The test period for this case was based on a historical twelve-month test period of January
2024 through December 2024,which became effective February 1,2025).
APPLICATION OF ROCKY MOUNTAIN POWER Page 5

approximately $2.6 million before the 90/10 percent sharing band. Mr. Painter's testimony
explains the main drivers for the net power cost deferral,which include increased coal fuel supply
and lower natural gas market prices and power market prices from their 2023 peaks.
10. Mr. Painter's testimony specifically addresses the LCAR, EITF 04-6 treatment of
coal stripping costs, a true-up of 100 percent of the incremental REC revenues for January 2025,
PTCs, the REP QF charge, and wind availability liquated damages.
11. The LCAR is a symmetrical adjustment to offset over- or under-collection of the
Company's energy-related production revenue requirement, excluding NPC, due to variances in
Idaho load. The LCAR decreased the deferral balance by approximately $2.1 million before
applying the sharing band due to higher usage during the Deferral Period.
12. The difference between including coal stripping costs recorded on the Company's
books under the guidance of the accounting pronouncement EITF 04-6, and expensing coal
stripping costs when the coal was excavated increased the ECAM deferral by $84,392 before
applying the sharing band.
13. The total NPC deferral adjusted for LCAR and EITF 04-6 was approximately
$604,629 for which customers are responsible for 90 percent, and the Company is responsible for
the remaining 10 percent.After accounting for the sharing band,the NPC deferral is approximately
$544,196.
14. During the Deferral Period the PTC differential, as described in paragraph 7,
increases the deferral approximately $1 million.
15. Prior to the implementation of the most recent GRC, the ECAM tracked the
difference between actual REC revenues during the Deferral Period and the amount of REC
revenues credited to customers in base rates.Beginning February 1,2025,REC revenue is removed
APPLICATION OF ROCKY MOUNTAIN POWER Page 6

from the ECAM calculation and included in the new RRA mechanism.The ECAM includes a true-
up for January 2025 actual REC revenue,which was $22 thousand higher than the amount credited
to customers in base rates on an Idaho-allocated basis.
16. In accordance with Order No. 33954, wind availability liquidated damages were
credited to customers in the amount of$265 thousand.
17. Interest is accrued on the uncollected balance at the Commission-approved interest
rate for customer deposits. During the Deferral Period the interest rate was 5.0 percent. Interest of
$3.5 million was added to the ECAM balance.
18. As shown in Table 2 of Mr. Jack Painter's testimony, the Company is proposing to
collect$49.3 million, including $4.1 million from the 2025 ECAM deferral (inclusive of interest),
plus$45.2 million remaining balance from prior ECAM filing.The Company estimates the ECAM
balance will be reduced by $14.3 million from Schedule 94 revenue collections accrued from
January 1, 2026 through May 31, 2026, resulting in an estimated ECAM balance of$35.1 million
to be collected. With the addition of carrying charges during the rate effective period of June 1,
2026 through May 31,2027,the total estimated recovery by the Company through the ECAM over
the rate effective period is $35.7 million which includes $0.6 million in interest accrued during the
collection period.
19. As described in Mr. Elder's testimony, the Company proposes Schedule 94 rates of
1.064, 1.044, and 1.009 cents per kWh for secondary, primary, and transmission delivery service
voltages, respectively. This will result in an average decrease of 0.6 percent for standard tariff
customers, while the Schedule 400 customer will see a decrease of 1.1 percent. This results in an
overall average decrease of 0.7 percent for all Idaho customers.
APPLICATION OF ROCKY MOUNTAIN POWER Page 7

IL Renewable Energy Credit Revenue Adjustment(RRA) -Schedule 98
BACKGROUND OF RRA
20. In the 2024 Rate Case, the Company proposed to remove REC revenue from the
annual ECAM calculation and instead implement a new mechanism, the RRA, to pass back REC
revenue to customers separately from the ECAM.As part of this proposed change, REC revenues
that were previously included in base rates were removed and to be returned to Idaho customers
through the newly established RRA. The Company also proposed a new voluntary REC Option
Program, Schedule 74, allowing customers to elect to have RECs retired on their behalf.
PROPOSED RRA RATES
25. In support of the proposed RRA rates under Schedule 98 included in this
Application, Rocky Mountain Power has filed the testimony and exhibits of Company witnesses
Mr. Nicolas L. Highsmith and Mr. Elder. Mr. Highsmith's testimony describes the newly
implemented RRA, or Schedule 98,which was approved in the Company's 2024 Rate Case16 and
explains the calculation of the balance proposed for refund in this docket. Mr. Elder's testimony
describes the proposed Schedule 98 rates.
21. As described in Mr.Highsmith's testimony,the Company is requesting to return the
$1.4 million balance to Idaho customers over a one-year period,beginning June 1, 2026,pursuant
to Schedule 98. This is comprised of the 2026 RRA Deferral Balance of$1.3 million and interest
of$32 thousand.
22. As described in Mr. Elder's testimony, the Company's proposes Schedule 98 rates
will result in an average decrease of 0.6 percent for standard tariff customers, while there will be
16 In the Matter of the Application of Rocky Mountain Power for Authority to Increase its Rates and Charges in
Idaho and Approval of Proposed Electric Service Schedules and Regulations, Case No.PAC-E-24-04.
APPLICATION OF ROCKY MOUNTAIN POWER Page 8

no change for the Schedule 400 customer.This results in an overall average decrease of 0.4 percent
for all Idaho customers.
23. Mr. Highsmith's testimony also describes how the RRA was calculated, which
includes: the allocation of calendar year 2025 REC revenues,using actual 2025 System Generation
("SG") and System Energy ("SE") allocation factors; the calendar year 2025 actual Schedule 98
surcredit/surcharges included in the period, which was zero in this initial filing period; and the
carrying charges that were applied to the 2025 RBA deferral balance.
COMMUNICATIONS
Communications regarding this filing should be addressed to:
Jana Saba
Director of Regulatory Affairs and Operations
Rocky Mountain Power
1407 West North Temple, Suite 310
Salt Lake City,Utah 84116
Telephone: [phone]
Email:jana.saba&pacificorp.com
Joe Dallas (ISB# 10330)
Senior Attorney
Rocky Mountain Power
825 NE Multnomah, Suite 2000
Portland, OR 97232
Telephone: [phone]
Email:joseph.dallaskpacificorp.com
In addition, Rocky Mountain Power requests that all data requests regarding this
Application be sent in Microsoft Word to the following:
By email (preferred): datarequestkpacificorp.com
By regular mail: Data Request Response Center
PacifiCorp
825 Multnomah, Suite 2000
Portland, Oregon 97232
APPLICATION OF ROCKY MOUNTAIN POWER Page 9

Informal questions may be directed to Jana Saba, Director of Regulation and Regulatory
Operations at(801) 220-2823.
Included with this Application is a copy of the press release,which will be issued on April
2, 2026. Additionally, this Application includes a copy of the customer notice, which will be
included with customers'bills beginning April 3, 2026, and will run for a full billing cycle.
CONFIDENTIAL INFORMATION
This filing, specifically Jack Painter's workpapers, includes confidential information
exempt from public review under Idaho Code §§ 74-104-109 and Idaho Public Utilities
Commission's Rule of Procedure 67.
REQUEST FOR RELIEF
The ECAM allows the Company to collect or credit the difference between the Actual NPC
incurred to serve customers in Idaho and the Base NPC collected through base rates assuring
customers pay the actual NPC after sharing. To the best of the Company's knowledge the ECAM
deferral has been accurately calculated, incorporating all associated Commission Orders in this
Application.
WHEREFORE, Rocky Mountain Power respectfully requests that the Commission issue
an order: (1) authorizing that this matter be processed by Modified Procedure; (2) approving
approximately $4.1 million ECAM deferral; (3) approve the Company's request to return $1.4
million in REC revenue to customers under the RRA; (3) approving a 0.7 percent decrease to
Electric Service Schedule No. 94, Energy Cost Adjustment effective June 1, 2026; and (4)
approving a 0.4 percent decrease to Electric Service Schedule No. 98, REC Revenue Adjustment
effective June 1, 2026.
APPLICATION OF ROCKY MOUNTAIN POWER Page 10

DATED this 1 st day of April 2026.
Respectfully submitted,
ROCKY MOUNTAIN POWER
--A
Joe Dallas (ISB# 10330)
825 NE Multnomah, Suite 2000
Portland, OR 97232
Telephone: [phone]
Email: joseph.dallaskpacificorp.com
Attorney for Rocky Mountain Power
APPLICATION OF ROCKY MOUNTAIN POWER Page 11

CUSTOMER NOTICES

-ROCKY MOUNTAIN
POWER.
POWERING YOUR GREATNESS
For information, contact: News Media Hotline [phone]
Annual energy cost adjustment
Lower fuel costs to reduce bills for Idaho customers of Rocky Mountain Power
BOISE, Idaho (April 2, 2026) — Rocky Mountain Power's costs for fuel and wholesale electricity
decreased in 2025, producing a modest decrease in customer bills for the coming year. As part of an
annual review of these costs,the company requested an average 0.6%decrease for Idaho residential
customers.A typical residential customer using 836 kilowatt-hours per month would see a decrease of
$0.61 per month on their electricity bill. The company proposes the decrease to take effect June 1,
2025, subject to review by the Idaho Public Utilities Commission.
"The company is working hard to maintain our position as a low-cost energy provider," said Tim
Solomon, director, Commercial Accounts and Community Relations for Rocky Mountain Power. "The
annual adjustment process makes sure Rocky Mountain Power customers always pay a fair price for the
energy they need. A winter 2025 survey of prices nationally shows a typical residential electric bill in
Idaho at$119 per month, while the national average is $179." For details,visit Residential customer
price comparison
The annual energy cost adjustment mechanism is designed to track the difference between the
company's actual expenses for fuel and electricity purchased from the wholesale market, against the
amount being collected from customers through current rates.The costs are tracked in a separate
account called the Energy Cost Adjustment Mechanism and adjusted each year. If costs are higher than
the level included in base rates, a surcharge is applied to customer bills as a separate line item. If costs
are lower, a credit is applied.
Testimony supporting the company's application shows fuel supply constraints and price volatility in
previous years stabilized in 2025, resulting in more normal output from low-cost thermal generating
plants. Lower natural gas costs,together with lower wholesale market prices, moderated the cost of
supplying electric service to Idaho customers in 2025.
Pending commission approval, the changes would take effect June 1, 2026, with the following impact on
each rate schedule:
Residential Schedule 1—0.6%decrease
Residential Schedule 36—0.6%decrease
General Service Schedule 6—0.7% decrease
General Service Schedule 9—0.8% decrease
Irrigation Service Schedule 10—0.5%decrease
General Service Schedule 23—0.7%decrease

General Service Schedule 35—0.7%decrease
Public Street Lighting—0.2%decrease
Tariff Contract 400—1.1%decrease
The public will have an opportunity to comment on the proposal as the commission studies the
company's request.The commission must approve the proposed changes before they can take effect.A
copy of the company's application is available for public review on the commission's website,
www.puc.idaho.gov, under Case No. PAC-E-26-05. Customers may also subscribe to the commission's
RSS feed to receive periodic updates via email.The request is required to be available at the company's
offices in Rexburg, Preston, Shelley and Montpelier, although the company urges customers to visit our
website at rockymountainpower.net/rates.
Idaho Public Utilities Commission Rocky Mountain Power offices
www.puc.idaho.gov Rexburg—127 East Main
11331 W. Chinden Blvd. Building 8, Suite 201-A Preston—509 S. 2nd East
Boise, ID 83714 Shelley—852 E. 1400 North
Montpelier—24852 U.S. Hwy 89
About Rocky Mountain Power
Rocky Mountain Power provides safe and reliable electric service to more than 1.2 million customers in
Utah, Wyoming and Idaho.The company supplies customers with electricity from a diverse portfolio of
generating plants including hydroelectric,thermal, wind,geothermal and solar resources. Rocky
Mountain Power is part of PacifiCorp, one of the lowest-cost electricity providers in the United States,
with 2 million customers in six western states. For more information,visit:
www.rockymountainpower.net

Annual energy cost adjustment
Proposed net price decrease
Rocky Mountain Power requests recovery of power costs
On April 1, 2026, Rocky Mountain Power asked the Idaho Public Utilities Commission to approve the
incremental energy-related costs for 2025 of$35.7 million, over two years. On annual basis,this is a
net decrease of$2.7 million from the revenues currently collected through the energy cost adjustment
mechanism. The energy cost adjustment mechanism is designed to track the difference between the
company's actual expenses for fuel and electricity purchased from the wholesale market, against the amount
being collected from customers through current rates.
Pending commission approval, the decrease would take effect June 1, 2026. All customer classes will see a net
decrease to their rates due to several factors. The main drivers of decreased costs in 2025 were an increased
coal fuel supply, and lower natural gas and purchased power market prices, down from their 2023 peaks.
A typical residential customer using 836 kilowatt-hours per month would see a decrease of approximately
$0.61 a month on their electricity bill. The following is a summary of the percentage changes
by customer class:
• Residential Schedule 1 —0.6%decrease • General Service Schedule 23—0.7%decrease
• Residential Schedule 36—0.6%decrease • General Service Schedule 35— 0.7% decrease
• General Service Schedule 6— 0.7% decrease • Public Street Lighting—0.2%decrease
• General Service Schedule 9— 0.8%decrease • Tariff Contract 400— 1.1%decrease
• Irrigation Service Schedule 10—0.5%decrease
Rocky Mountain Power will continue to work to keep costs as low as possible. Customers can visit
RockyMountainPower.net/Wattsmart for energy and money-saving tips and information.
The public will have an opportunity to comment on the proposal during the coming months as the
commission studies the company's request. The commission must approve the proposed changes before they
can take effect.
A copy of the company's application is available for public review on the commission's website at
www.puc.idaho.gov under Case No. PAC-E-26-05.
Customers may file written comments regarding the application with the commission or subscribe to the
commission's RSS feed to receive periodic updates via email about the case. Copies of the proposal are
also available for review at the company's offices in Rexburg, Preston, Shelley and Montpelier, although the
company encourages customers to visit our website at RockyMountainPower.net/Rates.
N
V
Idaho Public Utilities Commission Rocky Mountain Power offices o
11331 W. Chinden Blvd. Building Rexburg— 127 East Main
8,Suite 201-A Preston—509 S. 2nd East o
Boise, ID 83714 Shelley—852 E. 1400 North
www.puc.idaho.gov Montpelier—24852 U.S. Hwy 89
N
O
N
For more information about your rates and rate schedule, _ROCKY MOUNTAIN
go to RockyMountainPower.net/Rates. POWER.

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION ) CASE NO. PAC-E-26-05
OF ROCKY MOUNTAIN POWER )
REQUESTING APPROVAL TO RECOVER ) DIRECT TESTIMONY OF
$4.1 MILLION ASSOCIATED WITH THE ) JACK PAINTER
ECAM DEFERRAL AND REFUND $1.4 )
MILLION ASSOCIATED WITH THE RRA )
ROCKY MOUNTAIN POWER
CASE NO. PAC-E-26-05
April 2026

I Q. Please state your name,business address,and present position with PacifiCorp
2 d/b/a Rocky Mountain Power("Rocky Mountain Power" or the "Company").
3 A. My name is Jack Painter and my business address is 825 NE Multnomah Street,
4 Suite 600, Portland, Oregon 97232. My title is Net Power Cost Adviser.
5 I. QUALIFICATIONS
6 Q. Please describe your education and professional experience.
7 A. I received a Bachelor of Arts degree in Business Administration with a Finance
8 major from Washington State University in 2007. I have been employed by
9 PacifiCorp since 2008 and have held positions in the regulation and jurisdictional
10 loads departments. I joined the regulatory net power costs ("NPC") group in 2019
11 and assumed my current role as a Net Power Cost Adviser in 2024.
12 Q. Have you testified in previous regulatory proceedings?
13 A. Yes. I have previously provided testimony to the public utility commissions in
14 Idaho, Utah,Wyoming, Oregon,Washington, and California.
15 II. PURPOSE OF TESTIMONY
16 Q. What is the purpose of your testimony in this proceeding?
17 A. My testimony presents and supports the Company's calculation of the Energy Cost
18 Adjustment Mechanism (`SCAM") balancing account for the 12-month period of
19 January 1,2025 through December 31,2025 ("Deferral Period").More specifically,
20 1 provide the following:
21 • A summary of the ECAM calculation, including changes made to comply
22 with Idaho Public Utility Commission("Commission") orders;
23 • Details supporting the addition of approximately$4.1 million to the deferral
Painter, Di 1
Rocky Mountain Power

I balance, including $0.5 million customers' share of ECAM costs, a $1.0
2 million increase in renewable energy production tax credits ("PTCs"), $1.3
3 million in reasonable energy price ("REP") qualified facility ("QF") costs,
4 a credit of$265 thousand for wind availability liquidated damages, a $22
5 thousand renewable energy credit ("REC") revenue differential, and $3.5
6 million interest accrued during the Deferral Period; and
7 • Discussion of the main differences between adjusted actual NPC for
8 calendar years 2025 and 2024.
9 III. SUMMARY OF THE ECAM DEFERRAL CALCULATION
10 Q. Please briefly describe the Company's ECAM authorized by the Commission.
11 A. The ECAM tracks deviations between Actual NPC and Base NPC. When there is a
12 difference between these two amounts, 90 percent of the difference is deferred for
13 later recovery or return to customers.'In addition to tracking the difference between
14 Actual and Base NPC, the ECAM also tracks other items including PTCs, the
15 Reasonable Energy Price QF adjustment,wind availability liquidated damages,the
16 load change adjustment rate ("LCAR"), and wheeling revenues. The purpose for
17 tracking these items is to true-up base rates to actuals. The balance that accumulates
18 over a deferral period is then passed on to customers as a rate surcharge or credit.
19 Schedule 94, described in Company witness Mr.Kenneth Lee Elder Jr.'s testimony,
20 appears as a separate line item on customers'bills and either collects from or credits
21 to customers the balance of deferred costs. Schedule 94 is adjusted as needed in the
22 Company's annual ECAM filings.
'See Order No. 30904 in Case No.PAC-E-08-08 and Order No. 33440 in Case No.PAC-E-15-09.
Painter, Di 2
Rocky Mountain Power

I The Company is required to file an application with the Commission
2 annually by April I" to request approval of the deferral amount and the new
3 Schedule 94 rates to become effective June 1.
4 Q. Are there any changes to the ECAM calculation?
5 A. Yes.The rates for Base NPC,PTCs, and the LCAR were updated in the Company's
6 last general rate case ("GRC") Case No. PAC-E-24-04, which became effective
7 February 1,2025. The GRC also approved two other notable changes;the inclusion
8 of wheeling revenues and the removal of RECs which are now tracked in a new
9 REC Revenue Adjustment ("RRA") mechanism and related Electric Service
10 Schedule No. 98. Company witness Mr. Nicholas L. Highsmith provides the
11 calculation for the RRA and Mr. Elder provides the proposed Schedule 98 rates.
12 IV. ECAM DEFERRAL CALCULATION
13 Q. Please describe the calculation of the ECAM deferral included in this filing.
14 A. Table 1 below summarizes the total ECAM deferral and provides a breakdown of
15 the individual components of the ECAM. For a detailed monthly calculation of the
16 ECAM deferral,please refer to Exhibit No. 1.
Painter, Di 3
Rocky Mountain Power

I Table 1 —Summary of ECAM Deferral
Calendar Year 2025 ECAM Deferral
NPC Differential $ 2, 631, 661
EITF 04-6 Adjustment 84, 392
LCAR (2, 146, 378)
Wheeling Revenues 34, 954
Total Deferral Before Sharing $ 604, 629
Sharing Band 900
Customer Reponsibility $ 544 , 166
Production Tax Credits $ (1, 047, 075)
REP QF Adjustment 1, 308, 827
Wind Liquidated Damages (265, 256)
REC Deferral 21, 598
Interest on Deferral 3, 522, 536
Annual Deferral (Jan - Dec 2025) $ 4, 084, 796
2 The first section of Table 1 above summarizes the Idaho-allocated share of
3 those items for which Idaho customers and the Company share responsibility,
4 including: NPC differential, Emerging Issues Task Force ("EITF") 04-6
5 adjustment,the LCAR costs,and wheeling revenues. The second section calculates
6 the 90 percent customers' share of these items. Finally, the last section adds the
7 following items that are either refunded or collected in full(i.e., 100 percent):PTCs,
8 REP QF costs, wind availability liquidated damages, REC revenues, and interest
9 on the deferral. The total of these items represents the ECAM deferral.
10 Q. Based on your calculations, what is the balance expected to be in the ECAM
I I deferral account as of June 1, 2026?
12 A. Table 2 below provides a summary of the ECAM balancing account activity starting
13 with the December 31, 2024 ECAM deferral balance of$88.6 million approved in
14 Case No. PAC-E-25-04. By June 1, 2026, the projected balance in the ECAM
Painter, Di 4
Rocky Mountain Power

I deferral account will be approximately $35.1 million. During the Deferral Period,
2 approximately $4.1 million is added to the balance from the annual deferral and
3 interest,which is offset by$43.4 million of ECAM revenue collections through the
4 Deferral Period, and an estimated collection of $14.3 million of Schedule 94
5 revenues, net of interest, between January 2026 and May 2026.
6 Q. Has the Company made any changes to Table 2?
7 A. Yes. The Company has calculated the estimated impact of carrying charges during
8 the rate effective period of June 1, 2026 through May 31, 2027 and has included
9 them in Table 2 below. The total estimated recovery by the Company through the
10 ECAM over the rate effective period is $35.7 million which includes the estimated
11 balance of$35.1 million on June 1, 2026 discussed above plus $654 thousand in
12 interest accrued during the collection period.
13 Q. Why is the Company incorporating carrying charges into its rate calculation
14 for the two-year amortization period?
15 A. In Case No. PAC-E-25-04, the Commission authorized the Company to include
16 interest during the rate effective period as part of its rate calculation. The Company
17 is seeking the same treatment in this ECAM because the current ECAM balance
18 still amortizes the previous ECAM balance. The ECAM balance continues to
19 accrue interest during the collection period. Including carrying charges into the rate
20 calculation ensures that the rates are designed to collect the entire ECAM balance,
21 including interest, by the end of the collection period. Not only does including
22 interest as part of its rate calculation create a more accurate rate for customers, it
23 also lowers carrying charges that customers incur. Company witness Mr. Elder will
24 further explain Schedule 94 rates and the rate collection period.
Painter, Di 5
Rocky Mountain Power

I Table 2 - Balancing Account Activity
ECAM Deferral Balance
Deferral Balance - Dec 31, 2024 $ 88, 620, 076
Annual Deferral (Jan - Dec 2025) 562, 260
Interest 3, 522, 536
ECAM Revenue Collection - Schedule 94 (43, 373, 074)
December 31, 2025 Balance For Collection $ 49, 331, 797
Schedule 94 Collection - Jan - May 2026 $ (15, 152, 97 8)
Interest 876, 468
Expected Balance as of June 1 , 2026 $ 35, 055,288
Interest Accrued through Rate Effective
Period June 1, 2026 through May 31, 2027 $ 654, 433
Total ECAM Balance for Recovery $ 35 , 709, 721
2 Q. Please describe the ECAM calculations in Exhibit No. 1.
3 A. The ECAM deferral is calculated monthly by comparing Idaho-allocated Actual
4 NPC to the Base NPC collected in rates and then deferring the differences into an
5 ECAM balancing account. Exhibit No. 1 includes details of the ECAM calculation.
6 Additionally, I have also provided confidential work papers supporting Exhibit
7 No. 1.
8 Q. How are the Base NPC and Actual NPC calculated?
9 A. Exhibit No. 1 provides details of the ECAM calculation. The monthly Base NPC
10 collected in rates, as set forth in line 6 of Exhibit No. 1, is calculated by taking the
11 dollar-per-megawatt-hour ("$/MWh") Base NPC rate multiplied by actual Idaho
12 retail sales.Actual Idaho NPC, as set forth in line 11 of Exhibit No. 1, is calculated
13 by dividing the monthly total-Company Actual NPC in the Deferral Period by the
14 actual monthly system megawatt-hours ("MWh") in the Deferral Period. To
15 calculate Actual Idaho NPC, the total Company Actual NPC $/MWh basis is then
Painter, Di 6
Rocky Mountain Power

I multiplied by Idaho actual monthly MWh.
2 Q. Please describe how the NPC deferral is calculated.
3 A. The deferral is calculated monthly by subtracting the Base NPC collected in rates
4 from the Actual Idaho NPC. For the Deferral Period,the NPC differential was $2.6
5 million before applying the 90/10 percent sharing band.
6 Q. What costs are included in the NPC differential for deferral?
7 A. The NPC differential for deferral captures all components of NPC as defined in the
8 Company's general rate case proceedings and modeled by the Company's
9 production dispatch model. Specifically, Base NPC and Actual NPC include
10 amounts booked to the following Federal Energy Regulatory Commission
11 ("FERC") accounts:
12 Account 447— Sales for resale; excluding on-system wholesale sales and
13 other revenues that are not modeled in GRID
14 Account 501 — Fuel, steam generation; excluding fuel handling, start-up
15 fuel (gas and diesel fuel, residual disposal), and other costs
16 that are not modeled in GRID
17 Account 503 — Steam from other sources
18 Account 509 - Allowances
19 Account 547— Fuel, other generation
20 Account 555 — Purchased power; excluding the Bonneville Power
21 Administration ("BPA") residential exchange credit pass-
22 through if applicable
23 Account 565 — Transmission of electricity by others
Painter, Di 7
Rocky Mountain Power

I Q. Are adjustments made to the Actual NPC before comparing them to Base
2 NPC?
3 A. Yes. The Company adjusts Actual NPC to reflect the ratemaking treatment of
4 several items, including:
5 • out-of-period accounting entries booked in the Deferral Period that
6 relate to operations before implementation of the ECAM on July 1,
7 2009;
8 • out-of-period accounting entries for wheeling revenues booked in the
9 Deferral Period that relate to operations before the inclusion of wheeling
10 revenues in the ECAM on February 1, 2025;
11 • revenue from a contract related to the Leaning Juniper wind resource;
12 • revenue for wheeling expense reimbursement from Orchard Wind QF;
13 • costs for situs-assigned resources/programs in Idaho, Oregon,Utah,and
14 California;
15 • coal inventory adjustments to reflect coal costs in the correct period;
16 • legal fees related to fines and citations included in the cost of coal;
17 • compliance costs for Washington greenhouse gas emissions related to
18 the Company's generation at its Chehalis natural gas generating plant;
19 • wind availability liquidated damages; and
20 • reasonable energy price adjustments to QFs.
21 Q. Why is the July 1, 2009, cutoff used to determine out-of-period entries?
22 A. Since the ECAM took effect, customers' rates have been adjusted to recover
23 essentially all of the Company's actual NPC, excluding any differences due to the
24 90/10 percent sharing band. Consequently, any accounting entries made during the
Painter, Di 8
Rocky Mountain Power

I current Deferral Period that relate to any operating period since the ECAM took
2 effect should be reflected in customer rates, whether they increase or decrease
3 Actual NPC. However, accounting entries related to operating periods before the
4 inception of the ECAM should not impact the ECAM deferral.
5 Q. Should the above principle apply to wheeling revenues with their inclusion in
6 the ECAM?
7 A. Yes. Accounting entries for wheeling revenues prior to February 1, 2025 are not
8 included in the ECAM.
9 Q. In addition to comparing Actual NPC to Base NPC, what other components
10 are included in the ECAM?
11 A. The ECAM calculation includes seven additional components: (i)an adjustment for
12 deferred costs associated with coal mine stripping activities recorded under the
13 Financial Accounting Standards Board ("FASB") EITF 04-6; (ii) the LCAR
14 adjustment; (iii) a true-up of PTCs; (iv) a true-up of Idaho allocated wheeling
15 revenues; (v)wind availability liquidated damages; (vi) a true-up of REC revenues
16 as authorized in Order No. 32196; and (vii) an adjustment for the situs-assigned
17 portion of REP costs.
18 Q. How is the adjustment for accounting pronouncement EITF 04-6 included in
19 the ECAM?
20 A. Line 13 of Exhibit No. 1 calculates coal stripping costs,reflecting Idaho's allocated
21 differences between the coal stripping costs incurred by the Company during
22 excavation, as recorded on the Company's books pursuant to the guidance of the
23 accounting pronouncement EITF 04-6, and the amortization of the coal stripping
24 costs as approved by the Commission in Case No. PAC-E-09-08, Order No. 30987.
25 During the Deferral Period, the total EITF 04-6 coal stripping deferral adjustment
Painter, Di 9
Rocky Mountain Power

I results in a $84 thousand increase to the ECAM deferral balance, before the
2 application of the 90/10 percent sharing band.
3 Q. Please describe the LCAR adjustment.
4 A. The calculation of the LCAR adjustment is a symmetrical adjustment for over- or
5 under-collection of the energy-related portion of the Company's embedded revenue
6 requirement for production facilities,as specified in Case No. GNR-E-10-03,Order
7 No. 32206. This adjustment accounts for variances in Idaho load that cause the
8 Company to collect more or less of these production-related costs. The LCAR rate
9 of$8.74/MWh is used for January 2025 and the new LCAR rate effective February
10 1, 2025 and the remainder of the Deferral Period is $6.49/MWh.
11 Q. How is the LCAR adjustment calculated and what impact does it have on the
12 Deferral Period?
13 A. The LCAR adjustment assumes that the actual production-related costs of the
14 LCAR are equivalent to the base amount on line 14 of Exhibit No. 1. The actual
15 production-related costs are then compared to the LCAR revenue collection in
16 rates, calculated by multiplying the LCAR rate by the actual Idaho retail sales on
17 line 17 of Exhibit No. 1. The LCAR adjustment, which is shown on line 18 of
18 Exhibit No. 1, is the difference between the actual production-related costs and the
19 LCAR revenue. This adjustment results in a $2.1 million decrease to the ECAM
20 deferral balance before application of the 90/10 percent sharing band.
21 Q. How is the wheeling revenue deferral calculated and what impact does it have
22 on the Deferral Period?
23 A. The wheeling revenue deferral, on line 23 of Exhibit No. 1, is calculated by
24 comparing the actual Idaho-allocated wheeling revenue to the wheeling revenue
25 credit customers receive through base rates. The wheeling revenue credit in base
Painter, Di 10
Rocky Mountain Power

I rates is calculated by multiplying the approved rate of$2.97/MWh by Idaho retail
2 sales. The difference results in a $35 thousand increase to the ECAM deferral.
3 Q. Please explain the sharing band ratio between the Company and customers in
4 the ECAM.
5 A. The ECAM includes a sharing band with a symmetrical sharing ratio in which
6 customers either pay or receive 90 percent of the ECAM deferral balance, and the
7 Company is responsible for the remaining 10 percent. Line 26 of Exhibit No. 1
8 represents the customers' 90 percent share of the monthly deferral shown on line
9 25 of Exhibit No. 1. For the Deferral Period, the customers' share of the deferred
10 balance is $544 thousand. The remaining balance of$60 thousand associated with
11 the Company's 10 percent share is not included in the deferral balance as it is not
12 recoverable from customers.
13 Q. What is the amount of the PTC true-up in the current filing?
14 A. The PTC Deferral,on line 32 of Exhibit No. 1,is calculated by comparing the actual
15 Idaho-allocated PTC to the PTC credit customers receive through base rates. The
16 PTC credit in base rates is calculated by multiplying the approved PTC rate of
17 $4.16/MWh by Idaho retail sales for January 2025 and the new PTC rate effective
18 February 1, 2025 and the remainder of the Deferral Period is $4.31 per MWh. The
19 difference results in a$1.0 million decrease to the ECAM deferral.
20 Q. Did the Company include the PTC correction in this ECAM filing as ordered
21 by the Commission in Case No. PAC-E-25-04?
22 A. Yes. The Company reduced the ECAM deferral by$52,243 for the PTC correction
23 from the prior ECAM which can be found on line 31 of Exhibit No. 1.
24 Q. Please explain the REP QFAdjustment.
25 A. As set forth in the 2020 Inter-Jurisdictional Allocation Protocol ("2020 Protocol"):
Painter, Di 11
Rocky Mountain Power

I "For the Interim Period, the energy output of New QF PPAs will be dynamically
2 allocated per this agreement using the SG Factor, priced at a forecasted reasonable
3 energy price defined below, and any cost of a New QF PPA above the forecasted
4 reasonable energy price will be situs assigned to and allocated to the State of
5 Origin."2 The Idaho situs-assigned cost,on line 33 of Exhibit No. 1,is$1.3 million.
6 Q. Please explain the wind availability liquidated damages credit.
7 A. Order No. 33954 in Case No. PAC-E-17-06 provides that"the Stipulation requires
8 the Company to pass on to ratepayers all liquidated damages it receives from
9 equipment suppliers in case the repowered equipment does not meet specified
10 availability, performance, or installation schedule requirements." The Company
11 first removes the wind availability liquidated damages from total-Company NPC
12 and then allocates them to customers using the System Generation ("SG")
13 allocation factor outside of the 90/10 percent sharing band. The wind availability
14 liquidated damages credited to customers in the ECAM is$265 thousand,as shown
15 on line 34 of Exhibit No. 1.
16 Q. What is the amount of REC revenue adjustment in the current filing?
17 A. REC revenues have been discontinued in the ECAM beginning February 1, 2025.
18 The REC revenue adjustment shown on line 39 of Exhibit No. 1 is calculated as the
19 REC revenue credit customers received through base rates in January 2025.Actual
20 Idaho-allocated REC revenues for calendar year 2025 will be credited to customers
21 in new Schedule 98 as discussed by Company witness Mr. Highsmith. The REC
22 revenue credit in base rates is calculated by multiplying the approved REC revenue
23 rate of $0.07/MWh by Idaho retail sales. The REC revenue adjustment is a $22
2 In the Matter of the Application for Approval of the 2020 PacifiCorp-Interjurisdictional Allocation
Protocol, Case No.PAC-E-19-20,Order No.34640 at§4.4.2.1,31 (April 22,2020).
Painter, Di 12
Rocky Mountain Power

I thousand increase to the ECAM deferral.
2 Q. What is the total ECAM deferred balance calculated in Exhibit No. 1?
3 A. The total ECAM deferred balance as of December 31, 2025, is $562 thousand,
4 shown on line 40 of Exhibit No. 1,plus$3.5 million of interest on line 49 of Exhibit
5 No. 1, for a total deferral of$4.1 million.
6 Q. Does the calculation of the ECAM deferral in this application comply with the
7 parameters of the Idaho ECAM as approved by the Commission?
8 A. Yes,therefore the Company recommends that the Commission approve the ECAM
9 application for recovery of the $4.1 million in prudently incurred ECAM costs.
10 V. DIFFERENCES IN NPC
11 Q. What is the Actual NPC $/MWh variance between the current Deferral Period
12 and calendar year 2024?
13 A. From a$/MWh perspective,Actual NPC for the Deferral Period was $34.37/MWh
14 while calendar year 2024 Actual NPC was$40.86/MWh,a decrease of$6.49/MWh
15 or 15.9 percent. Table 3 below displays adjusted Actual NPC for 2025 and 2024
16 with a high-level summary of the differences,by cost category, on a total-company
17 basis.
Painter, Di 13
Rocky Mountain Power

I Table 3 —2025 to 2024 NPC Comparison
Net Power Costs $/MWh 2025 2024 Variance
Wholesale Sales $44.81 $54 .35 ($9.54)
Purchased Power $51.55 $69.06 ($17.52)
Coal $30.35 $28. 94 $1.41
Gas $34.38 $33.75 $0. 62
Other 1 $17.22 1 $18.75 1 ($1.53)
Total $/MWh $34.37 $40.86 ($6.49)
Net Power Costs GWh 2025 2024 Variance
Wholesale Sales 4,036 1, 964 2, 072
Purchased Power 18, 743 20, 595 (1, 852)
Coal 23,289 18,225 5, 064
Gas 15, 375 16, 942 (1,567)
Other 10, 846 9, 793 1, 053
Total GWh 64,218 63,591 627
Net Power Costs $ 2025 2024 Variance
Wholesale Sales 180, 849,296 106,724, 822 74, 124, 474
Purchased Power 966, 151, 316 1,422,338,250 (456, 186, 934)
Coal 706, 769, 032 527, 475, 934 179,293, 098
Gas 528, 571, 922 571, 862, 902 (43,290, 980)
Other 186, 744,213 183, 618, 646 3, 125,566
Total $ $2,207,387,187 $2,598,570,911 ($391,183,724)
2 Q. What are the main drivers of decreased NPC from 2024 to 2025?
3 A. For 2025, the main drivers of decreased NPC were increased coal fuel supply and
4 lower natural gas market prices and power market prices from their 2023 peaks.
5 Q. What was the change in output for the Company's coal generating facilities in
6 2025?
7 A. In 2025, the Company's coal fuel supply stabilized after experiencing constraints
8 and force majeure claims from 2022-2024.Coal generating facilities increased their
9 output from approximately 18 thousand gigawatt-hours ("GWh") in 2024 to 23
10 thousand GWh in 2025 as shown in Table 3 above leading to reductions in
11 purchased power volumes and natural gas generation output.
Painter, Di 14
Rocky Mountain Power

I Q. How did lower market power prices decrease NPC in 2025?
2 A. The average price of market purchases decreased from $115/MWh in 2024 to
3 $80/MWh in 2025. When, combined with the increase in coal generation output
4 above, market purchase volumes decreased by 2,716 GWh from 2024 to 2025. The
5 overall impact to 2025 NPC was a reduction of$509 million in market purchase
6 costs.
7 VI. CONCLUSION
8 Q. Please summarize your testimony.
9 A. The ECAM deferral of$4.1 million for the Deferral Period, including interest,was
10 accurately calculated in compliance with previous Commission orders. Therefore,
11 I respectfully request that the Commission approve this application as filed with
12 rates effective June 1, 2026.
13 Q. Does this conclude your direct testimony?
14 A. Yes.
Painter, Di 15
Rocky Mountain Power

Case No. PAC-E-26-05
Exhibit No. 1
Witness: Jack Painter
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Jack Painter
April 2026

Rocky Mountain Power
Exhibit No. 1 Page 1 of 1
Case No. PAC-E-26-05
Witness:Jack Painter
Idaho Energy Cost Adjustment Mechanism Deferral
January 1,2025-December 31,2025
Line
No.
PAC-E-21-07 PAC-E-24-04
1 ID Base NPC Embedded in Rates($) $ 86,534,565 $ 128,240,000
2 Annual Idaho Base Load @ meter(MWh) 3,526,359 3,474,835
3 NPC Rate Embetltletl in Base Rates($/MWh) Line 1/Line 2 $ 24.54 $ 36.91
Jan-25 Feb-25 Mar-25 Apr-25 fil Jun-25 Jul-25 Aug-25 Sep-25 Oct-25 Nov-25 Dec-25 Total
4 NPC Rate Embedded in Base Rates($/MWh) Line 3 $ 24.54 $ 36.91 $ 36.91 $ 36.91 $ 36.91 $ 36.91 $ 36.91 $ 36.91 $ 36.91 $ 36.91 $ 36.91 $ 36.91
5 ID Actual Sales@ Meter(MWh) 315,522 265,317 244.944 265,791 353.521 425,697 495.028 380,588 274.741 264,381 231,254 285,459
6 ID NPC Collectetl in Rates($) Line 4 x Line 5 $ 7,742,702 $ 9,791,609 $ 9,039,735 $ 9,809,103 $ 13,046,830 $ 15,710,491 $ 18,269,197 $ 14,045,719 $ 10,139,399 $ 9,757,081 $ 8,534,500 $ 10,534,957 $ 136,421,322
7 Total Company Adjustetl Actual NPC($) Adjusted Actual NPC $201,646,800 $ 190,009,009 $ 160,442,913 $ 149,372,484 $ 154,289,205 $ 188,416,113 $245,813,526 $233,684,603 $ 199,513,552 $ 152,398,422 $ 167,996,082 $ 163,804,477 $ 2,207,387,187
8 Total Company Load @ Input(MWh) 5,615,143 4,952,265 4,913,527 4,536,666 4,941,372 5,507,477 6,170,782 5,887,554 4,995,007 4,818,874 4,831,592 5,306,781 62,477,040
9 Actual NPC($/MWh) Line 7/Line 8 $ 35.91 $ 38.37 $ 32.65 $ 32.93 $ 31.22 $ 34.21 $ 39.84 $ 39.69 $ 39.94 $ 31.63 $ 34.77 $ 30.87 $ 35.33
10 ID Actual Load @ Input(MWh) 314,818 276,065 248.308 278,111 368.796 488,880 480.429 391,504 293,474 268,754 233.873 279,244
11 Actual ID NPC Line 9x Line 10 $ 11,305,513 $ 10,592,100 $ 8,108,079 $ 9,156,983 $ 11,515,257 $ 16,725,050 $ 19,137,912 $ 15,539,311 $ 11,722,099 $ 8,499,419 $ 8,131,833 $ 8,619,427 $ 139,052,984
12 NPC Differential Line 11-Line 6 $ 3,562,811 $ 800,491 $ (931,656)$ (652,120)$ (1,531,573)$ 1,014,560 $ 868,715 $ 1,493,592 $ 1,582,700 $ (1,257,662)$ (402,667)$ (1,915,529) $ 2,631,661
EITF 04-6 Adjustment
13 Idaho Allocated EITF 04-6 Deferral Adjustment($) $ 55,289 $ (41,215)$ (106,683)$ (71,508)$ (118,619)$ 48,014 $ 200,102 $ 70,598 $ (9,361)$ (13,901)$ 63,609 $ 8,066 $ 94,392
LCAR
14 Actual Idaho Jurisdictional ECPC minus NPC(Actual=Base) $ 2,568,242 $ 1,879,932 $ 1,879,932 $ 1,879,932 $ 1,879,932 $ 1,879,932 $ 1,879,932 $ 1,879,932 $ 1,879,932 $ 1,879,932 $ 1,879,932 $ 1,879,932 $ 23,247,489
15 LCAR Rate @ Meter($/MWh) $ 8.74 $ 6.49 $ 6.49 $ 6.49 $ 6.49 $ 6.49 $ 6.49 $ 6.49 $ 6.49 $ 6.49 $ 6.49 $ 6.49
i6 ID Actual Sales @ Meter(MWh) Line 315.522 265,317 244.944 265,791 353.521 425,697 495,028 380,588 274,741 264,381 231,254 285,459
17 LCAR Revenue Collected through Base Rates($) Line 15 x Line 16 $ 2,757,530 $ 1,722,479 $ 1,590,214 $ 1,725,556 $ 2,295,117 $ 2,763,691 $ 3,213,803 $ 2,470,835 $ 1,783,660 $ 1,716,405 $ 1,501,336 $ 1,853,244 $ 25,393,867
18 LCAR Adjustment Line 14-Line 17 $ (189,287)$ 157,453 $ 289,718 $ 154,376 $ (415,185)$ (883,760)$ (1,333,871)$ (590,904)$ 96,272 $ 163,527 $ 378,596 $ 26,688 $ (2,146,378)
Wheeling Revenues
19 ID Allocated Wheeling Revenues In Rates($/MWh) $ (2.97)$ (2.97)$ (2.97)$ (2.97)$ (2.97)$ (2.97)$ (2.97)$ (2.97)$ (2.97)$ (2.97)$ (2.97)
20 ID Actual Sales @ Meter(MWh) Line 5 265,317 244,944 265,791 353,521 425,697 495,028 380,588 274,741 264,381 231,254 285,459
21 ID Wheeling Revenues Collected In Rates($) Line 19 x Line 20 $ (788,832)$ (728,259)$ (790,241)$ (1,051,079)$ (1,265,669)$ (1,471,804)$ (1,131,552)$ (816.851)$ (786,050)$ (687.557)$ (848,717)
22 ID Allocated Actual Wheeling Revenues($) (1,038,802) (864,667) (577,905) (676,483) (871,465) (1,019,214) (964,428) (838,317) (743,371) (604,772) (2,132,235)
23 ID Wheeling Revenues Deferral($) Line 22-Line 21 $ (249,970)$ (136,408)$ 212,336 $ 37"96 $ 394,204 $ 452,590 $ 167,124 $ (21,466)$ 42,680 $ 82,785 $ (1,283,517) $ 34,954
24 ECAM Deferral
25 Total ECAM Deferral(NPC Deferral,EITF 04-6 Atljustment,LCAR) Sum of Lines:12,13,18,23 3,428,813 666,759 (885,028) (356,916) (1,690,780) 573,018 187,535 1,140,410 1,648,145 (1,065,356) 122,322 (3,164,292) 604,629
26 Total ECAM Deferral after 90%Sharing Line 25 x90% It 3,085,931 $ 600,083 $ (796,525)$ (321,224)$ (1,521,702)$ 515,717 $ 168,782 $ 1,026,369 $ 1,483,330 $ (958,820)$ 110,090 $ (2,947,863) $ 544,166
Production Tax Credits(PTCs)
27 ID Allocated PTCs in Rates($/MWh) $ (4.16)$ (4.31)$ (4.31)$ (4.31)$ (4.31)$ (4.31)$ (4.31)$ (4.31)$ (4.31)$ (4.31)$ (4.31)$ (4.31)
28 ID Actual Sales@ Meter(MWh) Line 315,522 265,317 244.944 265,791 353.521 425,697 495.028 380,588 274.741 264,381 231.254 285,459
29 ID PTCs in Rates($) Line 27 x Line 28 $ (1,313,808)$ (1,143,515)$ (1,055,708)$ (1,145,559)$ (1,523,677)$ (1,834,754)$ (2,133,573)$ (1,640,333)$ (1,184,132)$ (1,139,483)$ (996,704)$ (1,230,328)
30 IDAIIocated Acual PTCs($) (1,700,525) (1,599,622) (1,697,128) (1,357,228) (1,247,053) (1,038,106) (1,045,695) (860,145) (854,840) (1,461,708) (1,803,744) (2,670,610)
31 ID Allocated PTC Credit from Previous ECAM Commission Order Order No.36621 (52,243)
32 ID PTC.Deferral S) Line 30-Line 29 $ (438,960)$ (466,106)$ (641,421)$ (211,669)$ 276,624 $ 796,647 $ 1,087,878 $ 780,188 $ 329,292 $ (322,224)$ (807,041)$ (1,440,283) $ (1,047,075)
Situ,Assigned REP OF Adpidon rat
33 ID REP OF Adjustment($) $ 58,154 $ 73,306 $ 143,277 $ 98,521 $ 90,643 $ 193,809 S 112,866 $ 46,420 S 66,464 $ 158,043 $ 128,369 $ 138,955 $ 1,308,827
Wind Liquidated Damages
34 ID Allocated Wind Liquidated Damages($) $ (30,555)$ - $ - $ - $ - $ - $ - $ (80,90)$ (86,319)$ (41,681)$ (23,258)$ (2,489) $ (265,256)
Renewable Energy Credits(REC)Revenue
35 ID REC Revenue in Rates($/MWh) $ (0.07)
36 ID Actual Sales @ Meter(MWh) Line 5 315,522
37 ID REC Revenue in Rates($) Line 35 x Line 36 $ (21.598)
38 ID Allocated Actual REC Revenue($)
39 REC Revenue Adjustment S) Line 38-Line 37 $ 21,598 $ 21,598
40 Total Deferral Sum of Lines 26,32,33.34,39 $ 2,696,168 $ 217,282 $ (1,294,669)$ (434,373)$ (1,154,435)$ 1,506,173 $ 1,369,526 $ 1,772,023 $ 1,792,768 $ (1,164,683)$ (591,839)$ (4,151,680) $ 562,260
41 Interest Rate Order No.36390 5.00% 5.00% 5.00% 5.00% 5.00% 5.00% 5.00% 5.00% 5.00% 5.00% 5.00% 5.00%
:CAM Balancing Account($)
42 Beginning Balance $ 88,620,076 $ 86,143,236 $ 82,084,363 $ 78,636,468 $ 76,468,303 $ 73,010,589 $ 70,923,604 $ 67,327,118 $ 64,843,681 $ 63,246,856 $ 59,362,354 $ 56,147,353
43 ECAM Defend After Sharing Line 26 3.085.931 600,083 (796,525) (321,224) (1,521,702) 515,717 168.782 1,026,369 1.483,330 (958,820) 110.090 (2,847,863)
44 PTCs Deferral Line 32 (438,960) (456,106) (641,421) (211,669) 276,624 796,647 1,087,878 780,188 329,292 (322,224) (807,041) (1,440,283)
45 REP Silus Adjustment Line 33 58.154 73,306 143,277 98,521 90,643 193,809 112,866 46,420 66,464 158,043 128,369 138,955
46 Wind Liquitlatetl Damages Line 34 (30,555) - - - - - - (80,953) (86,319) (41,681) (23,258) (2,489)
47 REC Revenue Adjustment Line 39 21.598 - - - - - - - - - - -
48 Less:Monthly ECAM Rider Revenues allocated to ECAM (5,536,341) (4,625,901) (2,487,365) (2,056,255) (2,614,047) (3,892,397) (5,253,435) (4,530,243) (3,655,892) (2,974,724) (2,863,306) (2,883,167)
49 Interest 363.333 349,746 334.139 322,463 310.767 299,239 287.424 274,783 266.300 254,905 240.145 219,291
50 Total ECAM Deferral Balance($) $ 86,143,236 $ 82.084.363 $ 78,636,468 $ 76.468.303 $ 73,010,589 $ 70.923.604 $ 67,327,118 $ 64.843.681 $ 63,246,856 $ 59.362,354 $ 56,147,353 $ 49.331.797 $ 49,331,797

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION ) CASE NO. PAC-E-26-05
OF ROCKY MOUNTAIN POWER )
REQUESTING APPROVAL TO RECOVER ) DIRECT TESTIMONY OF
$4.1 MILLION ASSOCIATED WITH THE ) NICHOLAS L. HIGHSMITH
ECAM DEFERRAL AND REFUND $1.4 )
MILLION ASSOCIATED WITH THE RRA )
ROCKY MOUNTAIN POWER
CASE NO. PAC-E-26-05
April 2026

I Q. Please state your name, business address, and present position with
2 PacifiCorp, d/b/a Rocky Mountain Power ("Rocky Mountain Power" or the
3 "Company").
4 A. My name is Nicholas L. Highsmith, and my business address is 1407 W. North
5 Temple, Suite 330, Salt Lake City, Utah 84116. I am currently employed as the
6 Revenue Requirement Manager.
7 I. QUALIFICATIONS
8 Q. Please describe your education and professional background.
9 A. I hold a Master of Business Administration with an emphasis in Finance and a
10 Bachelor of Science degree in Finance from Weber State University. In addition to
11 my formal education, I have also attended several utility accounting, ratemaking,
12 and leadership seminars and courses. I have been employed with PacifiCorp since
13 July 2013. My experience includes various positions with regulation and finance.
14 Q. What are your current responsibilities as Revenue Requirement Manager?
15 A. My primary responsibilities include overseeing the calculation of PacifiCorp's
16 revenue requirement and the preparation of various regulatory filings in Utah,
17 Idaho, and Wyoming. I am also responsible for the calculation and reporting of
18 PacifiCorp's regulated earnings and the application of the inter jurisdictional cost
19 allocation methodologies.
20 Q. Have you testified in previous proceedings?
21 A. Yes.I have testified in multiple proceedings before the Public Service Commissions
22 of Wyoming and Utah.
Highsmith, Di 1
Rocky Mountain Power

23 II. PURPOSE AND SUMMARY OF TESTIMONY
24 Q. What is the purpose of your testimony?
25 A. My testimony discusses the newly implemented Renewable Energy Credit("REC")
26 Revenue Adjustment ("RRA"), or Schedule 98, that was approved in the
27 Company's most recent General Rate Case' ("GRC") and explains the calculation
28 of the balance proposed for refund in this docket. Specifically, the Company is
29 requesting to return the $1.4 million balance to Idaho customers over a one-year
30 period beginning June 1, 2025, pursuant to Schedule 98. My testimony provides
31 details on how these numbers were calculated, including:
32 • The allocation of calendar year 2025 REC revenues using actual 2025 System
33 Generation("SG") and System Energy ("SE") allocation factors;
34 • The calendar year 2025 actual Schedule 98 surcredit/surcharges included for
35 the period, which in this initial filing is zero; and
36 • The carrying charges that were applied to the 2025 RBA deferral balance.
37 Q. Please provide a brief summary of how the RRA was established.
38 A. Prior to the effective date of the GRC, REC revenues were returned to customers
39 primarily through a revenue requirement credit embedded in base rates, with any
40 differences reconciled annually through the Energy Cost Adjustment Mechanism
41 ("ECAM"). This treatment changed in the GRC, when the Company proposed a
42 voluntary REC Option Program, Schedule 74, allowing customers to elect to have
43 RECs retired on their behalf. As part of this change, REC revenues previously
44 included in base rates were removed to be returned to Idaho customers through the
' Case No.PAC-E-24-04.
Highsmith, Di 2
Rocky Mountain Power

45 newly established RRA. Together, these two new tariffs provide the framework
46 necessary for effective implementation of the voluntary REC option.
47 Q. Is the move to the RRA necessary?
48 A. Yes.An important aspect of the REC Option Program is that customers who enroll
49 not receive any credits for the sales of RECs in their rates. Embedding a forecast of
50 REC revenue into base rates makes it difficult to isolate and remove the impact of
51 REC revenues from REC Option customers. Additionally, it is not possible to
52 remove the impact of the REC revenue true-up in the ECAM for those customers
53 participating in the REC Option Program. Therefore, the Company determined a
54 separate RRA to be the best option to lessen the administrative burden and customer
55 confusion that may result from the new REC option program.
56 Q. Is this process new for the RRA?
57 A. No. The RRA will operate in a similar manner as the ECAM in how it captures and
58 balances actual costs, or in this case, revenues. The key difference is that REC
59 revenues are not included in base rates, so the full REC revenue balance is returned
60 to customers through the RRA. Notably, the ECAM previously included a similar
61 true-up for REC revenues prior to the implementation of the REC option tariff
62 approved in the GRC.
63 Q. Can you explain how the RRA is calculated?
64 A. The RRA serves as a balancing account for REC revenues and provides customers
65 with actual REC revenue credits through a two-step process. First, the Company
66 uses accounting actuals to determine the Idaho-allocated REC revenues to be
67 refunded to customers. In this docket, actual 2025 REC revenues will be refunded.
Highsmith, Di 3
Rocky Mountain Power

68 These revenues are then used to calculate a volumetric sur-credit under Schedule
69 98, as further supported by Company witness Mr. Kenneth Lee Elder, Jr. Second,
70 any differences between projected and actual REC revenues, including applicable
71 carrying charges, will be deferred and trued up in the subsequent RRA filing.
72 Q. Please confirm the deferral period for Company's 2026 RRA filing.
73 A. The deferral period for this 2026 RRA filing is January 1, 2025, through
74 December 31, 2025.
75 Q. Please describe how your Exhibit No. 2 is organized.
76 A. Exhibit No. 2 provides the detailed calculation of the $1.4 million total deferral
77 balance which is comprised of actual Idaho-allocated REC sales of$1.3 million and
78 interest of$32 thousand. This exhibit shows: the monthly REC revenue deferral
79 calculation for calendar year 2025; the calculation of Idaho-allocated actual 2025
80 REC revenues after applying the reallocation of revenue for renewable portfolio
81 standard ("RPS") eligibility (Page 2.1); and the calculation of the SE and SG
82 allocation factors used on page 1.1 as the basis to allocate REC revenue to Idaho
83 (Page 2.2).These allocation factors are consistent with those used in the Company's
84 energy balancing account filing.
85 III. CALCULATION OF THE 2026 RRA DEFERRAL BALANCE
86 Q. Please describe how the 2026 RRA Deferral Balance was calculated.
87 A. The$1.3 million 2026 RRA Deferral Balance represents the difference between the
88 actual REC revenue booked by the Company during calendar 2025 and the amount
89 of REC revenue set in base rates, which in this filing is zero. This balance accrued
90 carrying charges during the deferral period (calendar year 2025). Each item is
Highsmith, Di 4
Rocky Mountain Power

91 described below.
92 Q. How does the Company determine the REC revenue beginning deferred
93 balance?
94 A. Given this is the Company's first RRA filing,no beginning deferral balance exists.
95 However, the ending balance of this filing will become the beginning balance for
96 the 2027 RRA filing, which will true up all calendar year 2026 balances.
97 Q. Please describe how the 2025 Idaho allocated booked REC revenue was
98 calculated.
99 A. During calendar year 2025,the Company booked$21.8 million from REC sales on
100 a total-Company basis. Idaho's allocated share of REC revenue is determined using
101 the SG factor, including a reallocation of revenue initially allocated system wide to
102 reflect compliance with state RPSs.Revenue from the sale of RECs associated with
103 those not eligible for RPS compliance are allocated on an SG factor. The resulting
104 Idaho-allocated amount of REC revenue during 2025 was $1.9 million, as shown
105 in Exhibit No. 2 on page 2.1.
106 Q. Are any adjustments applied to the 2025 Idaho allocated REC revenues?
107 A. Yes.P4 Production entered into an agreement to retire rather than sell their allocated
108 share of RECs generated from Company resources.This treatment was approved in
109 Case No. PAC-E-21-08. To implement this, the Company uses confidential,
110 customer-specific load data to determine the portion of the Idaho SG factor
111 attributable to P4 Production. For the 2026 ECAM, this portion is approximately
112 31.5% of the overall Idaho SG factor. Because P4's RECs were retired, not sold,
113 the associated revenues should not be refunded to Idaho customers. Therefore, the
Highsmith, Di 5
Rocky Mountain Power

114 Company applies a decrement to total REC revenues to remove the value of those
115 retired RECs from the amount returned to customers. This reduces the Idaho-
116 allocate REC revenue from $1.9 million to $1.3 million, and is showing in Exhibit
117 No. 2.
118 Q. How was the amount of actual Schedule 98 surcredits or surcharges
119 determined?
120 A. As previously mentioned, the Company introduced a new REC Option program in
121 the GRC, under which REC revenues are removed from base rates and instead
122 refunded through the RRA mechanism. Because this is the Company's first RRA
123 filing, there are no surcredits or surcharges included in Idaho rates for the 2025
124 deferral period.
125 Q. Did you apply carrying charges to the 2026 RRA Deferral Balance in this
126 filing?
127 A. Yes.Approximately $32 thousand in carrying charge credits were applied to arrive
128 at the total $1.4 million in 2026 RRA deferral balance. The Commission's most
129 recently approved interest rate of 5.00 percent in Order No. 36390.
130 Q. What is the status of the new REC Tariff Option program?
131 A. The first year of the REC Tariff Option program was calendar year 2026, however
132 the Company did not receive any enrollments. Enrollment for the calendar year
133 2027 program year is open now and will close October 1, 2026.
134 Q. Can you please describe the reporting requirements outlined in the GRC for
135 future reporting regarding the REC Option Program?
136 A. Yes. There were two formal reporting requirements established in the GRC. First,
Highsmith, Di 6
Rocky Mountain Power

137 in Paragraph 16 of the settlement stipulation of the GRC, the Company agreed to
138 report on its annual generation from hydro, wind, solar, geothermal, biogas, and
139 biomass as a percentage of total system generation. Second, as identified in the
140 Direct Testimony of Company witness Craig M. Eller of the GRC, the Company
141 acknowledged it will provide the number of program participants for the year,
142 amount of aggregate load associated with program participants, a calculation of the
143 percentage of the program, and a REC retirement report.
144 Q. Are these reports provided within your testimony or exhibits in this filing?
145 A. No. Since the Company has not had participation in Schedule 74, no additional
146 reporting has been provided in this filing.
147 Q. Does this conclude your direct testimony?
148 A. Yes.
Highsmith, Di 7
Rocky Mountain Power

Case No. PAC-E-26-05
Exhibit No. 2
Witness: Nicholas L. Highsmith
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Nicholas L. Highsmith
April 2026

Rocky Mountain Power
Exhibit No.2 Page 1 of 4
Case No. PAC-E-26-05
Witness: Nicholas L. Highsmith
Rocky Mountain Power
Idaho REC Revenue Adjustment Mechanism
Summary of Idaho REC and Revenue Adjustment Mechanism (Schedule 98)
Line No. Reference
1 2025 RBA Deferral Balance Calculation
2 2025 Actual REC Revenue 1,348,951 Exhibit 2, Line 5
3 2025 Interest 32,401 Exhibit 2, Line 11
4 2025 RRA Deferral Balance $ 1,381,352
5 Present RRA Surcredit -
6 Change in RRA Schedule 98 $ 1,381,352

Rocky Mountain Power
Exhibit No.2 Page 2 of 4
Case No. PAC-E-26-05
Witness:Nicholas L.Highsmith
a Adj et Deferral
N0 Reference Oct-25
RBnavnbla Enargy Cretl0e(REC)Ravano.
nua IS) Page 2.1 1 1 1 1 21
ItleboIREC AIIocelion ege.1 885.9]% ]05.B]% 305.9]% �S.B]% 5 5.9]% %5.B]% 0 5.9]% �S.B]% 21)5.9]% 195.B]% 3015.9]% a05.B]% i85.9]%
J.II �CMe'
O,005 4, C,0 ]A, 3C,00 54, AC 04,00 2, ] OC,05 aA,005 1341L a 1 06
5 1-1 l0e10 Aeocaed REC R11enue(E1 'Ka 105,u1 et,e0s 17],]5A W113 5a,]0A a1,]80 113,421 tv,eta 75,6% 2m,8]] 1 ,823 1,9u,B5t
6urcretlN6urUargea
] Total DaNmale 100,M6 168 Nt 81 BN 177.]60 %1B) %]4 Y,760 ­.121 152823 1,34881
8 Interest Rate Ober No.36390 5.00% 5.00% 500% 500% 5— 500% 500% 500% 5— 500% 500% 500%
ECAB Balancing Aca 1(81
Beglnning Balance
REC Revenue Atljusenent Above 10a,]25 165,H1 81,861 ],]$a %,183 $A,]6a M,]60 113A21 133,016 ]5,555 20],0]] 152,023
7.
12=ECAB Deferral Balano.(1) %q8N 116] M., .3.111 ..A, 628%] -1. TB9603 891002 1010%9 1R ,14 1%1312 1,381,352

Rocky Mountain Power
Exhibit No.2 Page 3 of 4
Case No. PAC-E-26-05
Witness:Nicholas L.Highsmith
Rocky Mountain Power
Idaho REC Revenue Adjustment Deferral
Calculation of Idaho Allocated REC Actuals for CY 2025
Jan-Dec 2025-Actual REC Revenues-CAIOR/WA Eligible Resources $ 18,006,735
Jan-Dec 2025-Actual REC Revenues-CA/OR Eligible Resources $ 1,724,178
Jan-Dec 2025-Actual REC Revenues-CA Eligible Resources $ 20,269
Jan-Dec 2025-Actual REC Revenues-CANJA Eligible Resources $ 953,875
Jan-Dec 2025-Actual REC Revenues-ORNJA Eligible Resources $ 392,740
Jan-Dec 2025-Actual REC Revenues-OR Eligible Resources $ 129,547
Jan-Dec 2025-Actual REC Revenues-Not Eligibile for RPS Compliance $ 553,736
Total Jan-Dec 2025 REC Revenues $ 21,781,080
Reallocate Jan-Dec 2025 REC Revenues for Renewable Portfolio Standards
Factor Total California Oregon Washington Wyoming Utah Idaho FERC
CY 2025 Actual SG Factor-See Page 2.2 SG 100.000% 1.304% 26.319% 7.308% 13.168% 46.027% 5.854% 0.021%
Actual Jan-Dec 2025 REC Rev-Eligible for CA/OR/WA RPS SG 18,006,735 234,854 4,739,265 1,315,878 2,371,070 8,287,898 1,054,025 3,745
Adjustment for RPS/Commission Order SG 9,666,710 126,079 2,544,220 706,414 1,272,882 4,449,263 565,841 2,011
Adjustment for RPS/Commission Order Situs 9,666,710 360,933 7,283,485 2,022,293
Actual Jan-Dec 2025 REC Revenues-Reallocated totals 18,006,735 3,643,952 12,737,161 1,619,866 5,756
Actual Jan-Dec 2025 REC Rev-Eligible for CAIOR RPS SG 1,724,178 22,488 453,793 125,998 227,034 793,581 100,925 359
Adjustment for RPS/Commission Order SG 658,062 8,583 173,198 48,089 86,651 302,884 38,520 137
Adjustment for RPS/Commission Order Situs 658,062 31,071 626,991
Actual Jan-Dec 2025 REC Revenues-Reallocated totals 1,724,178 174,087 313,686 1,096,465 139,444 496
Actual Jan-Dec 2025 REC Rev-Eligible for CA RPS Only SG 20,269 264 5,335 1,481 2,669 9,329 1,186 4
Adjustment for RPS/Commission Order SG 268 3 70 20 35 123 16 0
Adjustment for RPS/Commission Order Situs 268 268
Actual Jan-Dec 2025 REC Revenues-Reallocated totals 20,269 5,405 1,501 2,704 9,453 1,202 4
Actual Jan-Dec 2025 REC Rev-Eligible for CANNA RPS SG 953,875 12,441 251,054 69,706 125,603 439,037 55,835 198
Adjustment for RPS/Commission Order SG 89,888 1,172 23,658 6,569 11,836 41,373 5,262 19
Adjustment for RPS/Commission Order Situs 89,888 13,613 76,275
Actual Jan-Dec 2025 REC Revenues-Reallocated totals 953,875 274,712 137,440 480,409 61,097 217
Actual Jan-Dec 2025 REC Rev-Eligible for ORIWA RPS SG 392,740 5,122 103,367 28,700 51,715 180,765 22,989 82
Adjuslmenl for RPS/Commission Order SG 198,977 2,595 52,370 14,541 26,201 91,583 11,647 41
Adjustment for RPS/Commission Order Situs 198,977 155,736 43,241
Actual Jan-Dec 2025 REC Revenues-Reallocated totals 392,740 7,718 77,916 272,348 34,636 123
Actual Jan-Dec 2025 REC Rev-Eligible for OR RPS SG 129,547 1,690 34,096 9,467 17,058 59,626 7,583 27
Adjuslmenl for RPS/Commission Order SG 46,275 604 12,179 3,382 6,093 21,299 2,709 10
Adjustment for RPS/Commission Order Situs 46,275 46,275
Actual Jan-Dec 2025 REC Revenues-Reallocated totals 129,547 2,293 12,849 23,152 80,925 10,292 37
Reallocated REC Revenues for Jan-Dec 2025 SG 10,660,181 139,036 2,805,696 779,014 1,403,699 4,906,525 623,994 2,217
Situs 10:660,181 405,884 8,112,488 2,141,809
Actual Jan-Dec 2025 REC Rev-Not Eligible for RPS Compliance SG F 553,736 7,222 145,740 40,465 72,914 254,866 32,413 115
Actual Jan-Dec 2025 REC Revenues-Total Reallocated 21,781,080 17,233 425,858 228,902 4,271,763 14,931,627 1,898,950 6,748
(A) P4 Production RECs(1) 31.49%
1,300,889
Reference (B)
Idaho%of Actual CY 2025 REC sales 5.97% C=B/A
Idaho allocated CY 2025 REC revenue 1,300,889 D=C"A
SG Factor Total
Leaning Juniper and Pryor Mountain-amounts booked in SAP 821,069
Idaho allocated Leaning Juniper Revenue 5.85% 48,061
Footnotes:
1)P4 Production entered an agreement to retire,rather than sell,P4's allocated share of RECs generated from system resources in Case No.PAC-E-21-08.
Page 2.1

Rocky Mountain Power
Exhibit No.2 Page 4 of 4
Case No. PAC-E-26-05
Witness: Nicholas L. Highsmith
Rocky Mountain Power
Idaho REC Revenue Adjustment Deferral
Calculation of Allocation Factors
Coincident Peaks:
Year Month Day hour CA OR WA UT ID WY FERC Total
2025 1 28 8 143 2,750 784 3,576 472 1,164 1.6 8,891
2025 2 12 8 167 2,989 876 3,477 472 1,173 1.6 9,155
2025 3 18 8 128 2,279 608 3,474 356 1,073 1.5 7,919
2025 4 1 9 117 2,156 539 3,243 413 1,131 1.3 7,600
2025 5 30 18 108 2,160 562 4,554 704 1,109 2.0 9,199
2025 6 30 18 122 2,644 745 5,357 845 1,173 2.7 10,889
2025 7 14 18 138 2,720 757 5,525 671 1,298 2.9 11,111
2025 8 12 18 129 2,908 780 5,338 605 1,187 2.7 10,950
2025 9 2 18 109 2,507 777 4,957 501 1,144 2.2 9,997
2025 10 2 18 84 1,694 495 3,783 413 1,014 1.4 7,485
2025 11 24 18 105 2,162 574 3,605 373 1,152 1.5 7,973
2025 12 1 18 102 2,300 649 3,776 437 1,197 1.8 8,463
Total 12 CP 1,452 29,269 8,146 50,664 6,262 13,817 23 109,632
System Capacity Factor 1.3246% 26.6971% 7.4300% 46.2124% 5.7120% 12.6026% 0.0212% 100.0000%
Energy:
Year Month CA OR WA UT ID WY FERC Total
2025 1 76,019 1,532,691 443,890 2,394,360 314,818 852,188 1,177 5,615,143
2025 2 71,045 1,362,760 395,962 2,084,886 276,065 760,606 940 4,952,265
2025 3 66,800 1,304,377 338,335 2,169,531 248,308 785,210 967 4,913,527
2025 4 55,704 1,147,350 293,546 2,035,053 278,111 726,051 851 4,536,666
2025 5 62,294 1,178,799 305,887 2,258,862 368,796 765,874 861 4,941,372
2025 6 66,531 1,241,190 352,429 2,610,096 488,880 747,262 1,090 5,507,477
2025 7 73,093 1,425,128 400,574 2,979,164 480,429 811,089 1,305 6,170,782
2025 8 67,868 1,407,447 390,517 2,848,019 391,504 780,956 1,241 5,887,554
2025 9 55,127 1,224,465 353,499 2,341,093 293,474 726,431 919 4,995,007
2025 10 58,020 1,218,007 331,897 2,191,898 268,754 749,426 872 4,818,874
2025 11 59,339 1,279,913 345,265 2,151,723 233,873 760,552 927 4,831,592
2025 12 64,864 1,413,539 384,598 2,343,231 279,244 820,193 1,111 5,306,781
Total Energy 776,705 15,735,666 4,336,400 28,407,914 3,922,255 9,285,839 12,262 62,477,040
System Energy Factor 1.2432% 25.1863% 6.9408% 45.4694% 6.2779% 14.8628% 0.0196% 100.000%
System Generation Factor 1.3043% 26.3194% 7.3077% 46.0267% 5.8535% 13.1677% 0.0208% 100.000%
Page 2.2

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION ) CASE NO. PAC-E-26-05
OF ROCKY MOUNTAIN POWER )
REQUESTING APPROVAL TO RECOVER ) DIRECT TESTIMONY OF
$4.1 MILLION ASSOCIATED WITH THE ) KENNETH LEE ELDER JR.
ECAM DEFERRAL AND REFUND $1.4 )
MILLION ASSOCIATED WITH THE RRA )
ROCKY MOUNTAIN POWER
CASE NO. PAC-E-26-05
April 2026

I Q. Please state your name,business address,and present position with PacifiCorp
2 d/b/a Rocky Mountain Power ("PacifiCorp" or "Company").
3 A. My name is Kenneth Lee Elder, Jr. My business address is 825 NE Multnomah
4 Street,Suite 2000,Portland,Oregon 97232.My present position is Director,Pricing
5 and Tariff Policy.
6 I. QUALIFICATIONS
7 Q. Please describe your education and professional background.
8 A. I have a Bachelor's Degree in Agriculture Business from Tarleton State University
9 and a Master's Degree in Agricultural and Resource Economics from Colorado
10 State University.I have been employed by PacifiCorp since July 2016,where I have
11 managed load forecasting and load research. From 2008 through 2016, I was an
12 economist for a natural resource consulting firm. From 2004 through 2008, I was
13 an economist for the University of Alaska Fairbanks. In May 2025, I assumed my
14 current position.
15 Q. What are your responsibilities?
16 A. I am responsible for regulated retail rates and cost of service analysis in the
17 Company's six state service territory.
18 Q. Have you testified in previous regulatory proceedings?
19 A. Yes. I have previously filed testimony on behalf of the Company in regulatory
20 proceedings in Utah, Oregon, Wyoming and Washington.
21 Q. What is the purpose of your testimony?
22 A. The purpose of my testimony is to present (1) the Company's proposed rates to
23 recover the 2025 Energy Cost Adjustment Mechanism("ECAM")deferral balances
Elder, Di 1
Rocky Mountain Power

I through Electric Service Schedule No. 94, Energy Cost Adjustment ("Schedule
2 94") and (2) the Company's proposed rate spread and rates to refund the 2025
3 Renewable Energy Credits (REC) deferral balances through Electric Service
4 Schedule No. 98, REC Revenue Adjustment("Schedule 98").
5 II. SCHEDULE NO. 94, ENERGY COST ADJUSTMENT
6 Q. What level of revenues is Schedule 94 currently designed to collect?
7 A. Schedule 94 is currently designed to collect approximately $38.4 million—$14.4
8 million for the Electric Service Schedule No. 400 ("Schedule 400") customer and
9 $24.0 million for standard tariff customers—based on Idaho loads from Case No.
10 PAC-E-24-04 ("2024 GRC").
11 III. PROPOSED RATE CHANGE FOR SCHEDULE 94
12 Q. Please describe the Company's proposed Schedule 94 rate change in this case.
13 A. The 2026 ECAM application proposes to change Schedule 94 rates to recover
14 approximately $35.7 million from June 1, 2026 to May 31, 2027 as shown in
15 Table 2 of Company witness Mr. Jack Painter's testimony.
16 Q. Please explain the proposed Schedule 94 rate change for Tariff Contract 400.
17 A. The proposed rate for Tariff Contract 400 is the same as for standard tariff
18 customers with transmission delivery service voltage.
19 Q. What is the impact of the proposed Schedule 94 rates?
20 A. As summarized in Exhibit No. 3,these rate change proposals result in a decrease of
21 1.1 percent for Schedule 400. Standard tariff customers will see an average decrease
22 of 0.6 percent.
Elder, Di 2
Rocky Mountain Power

I IV. CALCULATION OF PROPOSED RATES FOR SCHEDULE 94
2 Q. How were the proposed Schedule 94 rates developed for all customers?
3 A. The proposed rates for all customers were developed in three steps. First, I
4 developed their kilowatt-hour ("kWh") consumption at the generation level by
5 multiplying their retail loads at the delivery service voltage level with the
6 corresponding line loss factors. Second, an overall average rate at the generation
7 level was developed by dividing their total collection target identified above with
8 their kWh consumption at the generation level. Finally, rates by delivery voltage
9 level were developed by multiplying the above overall average rate at the
10 generation level with the corresponding line loss factors. As a result,the Company
11 proposes Schedule 94 rates of 1.064, 1.044 and 1.009 cents per kWh for secondary,
12 primary and transmission delivery service voltages,respectively, for all customers.
13 V. SCHEDULE NO. 98, REC REVENUE ADJUSTMENT (RRA)
14 Q. What level of revenues is Schedule 98 currently designed to collect?
15 A. Schedule 98 is currently designed to refund zero revenue for the Electric Service
16 Schedule No. 400 ("Schedule 400") customer and standard tariff customers based
17 on Idaho loads from Case No. PAC-E-24-04.
18 VI. PROPOSED RATE CHANGE FOR SCHEDULE 98
19 Q. Please describe the Company's proposed Schedule 98 rate change in this case.
20 A. The 2026 RRA application proposes to change Schedule 98 rates to refund
21 approximately$1.4 million from June 1, 2026 to May 31,2027 as shown in Exhibit
22 No. 2 of Company witness Mr. Nicholas L. Highsmith's testimony.
Elder, Di 3
Rocky Mountain Power

I Q. Please explain the proposed Schedule 98 rate change for Tariff Contract 400.
2 A. The proposed rate for Tariff Contract 400 is zero because REC revenues are
3 excluded from Schedule 400 rates.
4 Q. Why are REC revenues excluded from Schedule 400 rates?
5 A. On March 29, 2021, PacifiCorp filed an application requesting Commission
6 approval of an agreement entered into with the sole Schedule 400 customer under
7 which the Company will retire, rather than sell, this customer's allocated share of
8 RECs generated post-2020 from system resources.' The Company discontinued
9 sale of Idaho-allocated system RECs associated with the Schedule 400 load in 2021,
10 so that the Schedule 400 customer's allocated share of system RECs could be
11 retired on its behalf. The REC revenue that Schedule 400 would otherwise have
12 been allocated from the sale of post-2020 system RECs is removed from Schedule
13 400's base rates. Schedule 400 will continue to receive REC revenue from the sale
14 of any RECs generated prior to 2021.
15 On August 11, 2021, Commission Order No. 35131 approved this
16 agreement. Based on the terms of the agreement, the Company withheld the
17 Schedule 400 customer's share of 2021 RECs from any auctions or sales.Beginning
18 on January 1, 2021, the Schedule 400 customer will no longer receive a REC
19 revenue credit for RECs generated after December 31, 2020. If the Company was
20 able to sell RECs generated prior to January 1, 2021, Schedule 400 will receive
21 credit for its share of those REC revenues.
1 In the Matter of the Joint Application Between Rocky Mountain Power and P4 Production, L.L.C.
Requesting Approval of an Agreement to Retire RECs, Case No.PAC-E-21-08,Order No. 35131.
Elder, Di 4
Rocky Mountain Power

I Q. What is the impact of the proposed Schedule 98 rates?
2 A. As summarized in my Exhibit No. 4,these rate change proposals result in no
3 change for Schedule 400. Standard tariff customers will see an average decrease
4 of 0.6 percent.
5 VII. PROPOSED REC RATE SPREAD FOR SCHEDULE 98
6 Q. How does the Company propose to allocate the 2025 REC deferral revenue
7 across customer classes for Schedule 98?
8 A. The Company proposes to allocate the 2025 REC deferral revenue across customer
9 classes based on the cost of service factor 10 used in the 2024 general rate case,
10 Case No. PAC-E-24-04 ("2024 GRC"). The Company proposes using this
11 allocation, because RECs are produced from renewable resources, and renewable
12 resources are allocated to customer classes on cost of service factor 10.
13 Q. Did the Company make any other modifications to rate spread for Schedule
14 98?
15 A. Yes,the Company made two modifications to rate spread.First,Tariff Contract 400
16 is excluded from the rate spread. Second,the rate spread based on factor 10 for the
17 standard tariff customers is proportionally adjusted to reach the total target REC
18 revenues.
19 VIII. CALCULATION OF PROPOSED RATES FOR SCHEDULE 98
20 Q. How were the proposed Schedule 98 rates developed for all customers?
21 A. The proposed rates for all customers were developed by dividing the REC revenue
22 with the corresponding kilowatt-hour("kWh") consumption for each schedule.
Elder, Di 5
Rocky Mountain Power

I Q. Please describe Exhibit No. 3.
2 A. Exhibit No. 3 shows the 2023 loads used to develop rates, the line loss adjusted
3 loads,the allocation of the ECAM price change, and the percentage change by rate
4 schedule for Schedule 94.
5 Q. Please describe Exhibit No. 4.
6 A. Exhibit No.4 shows the 2023 loads used to develop rates,the allocation of the REC
7 price change, and the percentage change by rate schedule for Schedule 98.
8 Q. Please describe Exhibit No. 5.
9 A. Exhibit No. 5 contains clean and legislative copies of the proposed Electric Service
10 Schedule No. 94, Energy Cost Adjustment and the proposed Electric Service
11 Schedule No. 98, REC Revenue Adjustment. The Company requests that the
12 proposed Schedule 94 rates and Schedule 98 rates become effective on June 1,
13 2026.
14 Q. Does this conclude your direct testimony?
15 A. Yes, it does.
Elder, Di 6
Rocky Mountain Power

Case No. PAC-E-26-05
Exhibit No. 3
Witness: Kenneth Lee Elder, Jr.
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Kenneth Lee Elder, Jr.
April 2026

Rocky Mountain Power
Exhibit No.3 Page 1 of 1
Case No. PAC-E-26-05
Witness:Kenneth Lee Elder,Jr.
EXHIBIT NO.3
ROCKY MOUNTAIN POWER
ESTIMATED IMPACT OF PROPOSED ECAM ADJUSTMENT
FROM ELECTRIC SALES TO ULTIMATE CONSUMERS
DISTRIBUTED BY RATE SCHEDULES IN IDAHO
ADJUSTED HISTORICAL 12 MONTHS ENDED DECEMBER 2023
Present At Meter At Sch 94 ECAM Proposal Present
Line Average Base MWh by Voltage Generation Rev Rate 0/kWh ECAM Rev Net Change
No. Description Sch. Customers MWH ($000) S P T MWh ($000) S P T ($000) ($000) %
(1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11) (12) (13) (14) (15) (16)
Residential
1 Residential Service 1 61,756 619,659 $79,827 619,659 675,807 $6,590 1.064 1.044 1.009 $7,046 ($455) -0.5%
2 Residential Optional TOD 36 10,176 172,088 $19,704 172,088 187,681 $1,830 1.064 1.044 1.009 $1,957 ($126) -0.6%
3 AGA Revenue $1
4 Total Residential 71,933 791,748 $99,532 791,748 0 0 863,488 $8,421 $9,002 ($581) -0.5%
5 Commercial&Industrial
6 General Service-Large Power 6 1,120 305,548 $28,816 279,600 25,948 332,720 $3,245 1.064 1.044 1.009 $3,469 ($224) -0.7%
7 General Svc.-Lg.Power(R&F) 6A 186 22,162 $2,242 22,103 59 24,169 $236 1.064 1.044 1.009 $252 ($16) -0.7%
8 Subtotal-Schedule 6 1,306 327,711 $31,058 301,703 26,007 0 356,890 $3,480 $3,721 ($240) -0.7%
9 General Service-High Voltage 9 17 221,839 $15,539 0 0 222,699 230,500 $2,248 1.064 1.044 1.009 $2,403 ($155) -0.9%
10 Irrigation 10 5,726 551,496 $59,052 551,496 601,467 $5,866 1.064 1.044 1.009 $6,271 ($405) -0.6%
11 General Service 23 8,666 217,574 $23,810 182,662 353 0 199,592 $1,946 1.064 1.044 1.009 $2,081 ($134) -0.5%
12 General Service(R&F) 23A 2,565 42,247 $4,797 42,246 1 46,075 $449 1.064 1.044 1.009 $480 ($31) -0.6%
13 Subtotal-Schedule 23 11,230 259,822 28,608 224,909 354 0 245,667 Z396 2,561 (165) -0.5%
14 General Service Optional TOD 35 3 323 $33 323 352 $3 1.064 1.044 1.009 $4 ($0) -0.6%
15 General Service Optional TOD(R&F) 35A 1 56 $9 56 61 $1 1.064 1.044 1.009 $1 ($0)
16 Subtotal-Schedule 35 4 379 42 379 0 0 413 4 1.064 1.044 1.009 4 (0) -0.6%
17 Special Contract 400 1 1,314,200 $91,220 1,314,200 1,360,236 $13,265 1.009 $14,404 ($1,139) -1.1%
18 AGA Revenue $520
19 Total Commercial&Industrial 18,284 2,675,446 $226,038 1,078,487 26,362 1,536,899 2,795,174 $27,259 $29,363 ($2,105) -0.8%
20 Public Street Liehtine
21 Security Area Lighting 7 174 230 $46 230 251 $2 1.064 1.044 1.009 $3 ($0) -0.4%
22 Security Area Lighting(R&F) 7A 119 93 $22 93 102 $1 1.064 1.044 1.009 $1 ($0) -0.3%
23 Street Lighting-Company 11 61 182 $81 182 198 $2 1.064 1.044 1.009 $2 ($0) -0.2%
24 Street Lighting-Customer 12 266 2,360 $356 2,360 2,574 $25 1.064 1.044 1.009 $27 ($2) -0.5%
25 AGA Revenue $0
26 Total Public Street Lighting 620 2,866 $506 2,866 0 0 3,125 $30 $33 ($2) -0.4%
27 Total Sales to Ultimate Customers 90,837 3,470,059 $326,076 1,873,100 26,362 1,536,899 3,661,787 $35,710 $38,398 ($2,688 -0.7%
28 Total Excluding Special Contract 400 90,836 2,155,859 $234,856 1,873,100 26,362 222,699 2,301,550 $22,445 $23,994 $( 1,550) -0.6%
Rev.Rqmt Unallocated Allocated Proposed Rates Current Rates
29 Voltage Line Loss Factors applied to rates(2018 Study): 1.09061 1.07082 1.03503 S P T S P T
30 Tariff Customer ECAM deferral and Rate(cents/kWh): $22,445 0.975 1.064 1.044 1.009 Tariff Customer Rate 1.064 1.044 1.009 1.137 1.116 1.079
31 REC Adjustment and Rate(cents/kWh): $0 0.000 0.000 0.000 0.000 Schedule 400 Rate 1.009 1.096
32 Total Idaho ECAM Rate(cents/kWh): $35,710 0.975 1.064 1.044 1.009 REC Adj $0

Case No. PAC-E-26-05
Exhibit No. 4
Witness: Kenneth Lee Elder, Jr.
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Kenneth Lee Elder, Jr.
April 2026

Rocky Mountain Power
Exhibit No.4 Page 1 of 1
Case No. PAC-E-26-05
Witness:Kenneth Lee Elder,Jr.
EXHIBIT NO.4
ROCKY MOUNTAIN POWER
ESTIMATED IMPACT OF PROPOSED RRA
FROM ELECTRIC SALES TO ULTIMATE CONSUMERS
DISTRIBUTED BY RATE SCHEDULES IN IDAHO
ADJUSTED HISTORICAL 12 MONTHS ENDED DECEMBER 2023
Present Sch 98 RRA
Line Average Base 2024 GRC 2025 Deferral
No. Description Sch. Customers MWH ($000) F10 ($000) % Rate(0/kWh)
(1) (2) (3) (4) (5) (6) (7) (8) (9)
Residential
1 Residential Service 1 61,756 619,659 $79,827 0.21754 ($452) -0.6% -0.0729
2 Residential Optional TOD 36 10,176 172,088 $19,704 0.05860 ($122) -0.6% -0.0707
3 AGA Revenue $1
4 Total Residential 71,933 791,748 $99,532 ($574) -0.6%
5 Commercial&Industrial
6 General Service-Large Power 6 1,120 305,548 $28,816 ($203) -0.7% -0.0666
7 General Svc.-Lg.Power(R&F) 6A 186 22,162 $2,242 ($16) -0.7% -0.0666
8 Subtotal-Schedule 6 1,306 327,711 $31,058 0.10522 ($218) -0.7%
9 General Service-High Voltage 9 17 221,839 $15,539 0.06004 ($125) -0.8% -0.0562
10 Irrigation 10 5,726 551,496 $59,052 0.13173 ($274) -0.5% -0.0496
11 General Service 23 8,666 217,574 $23,810 ($158) -0.7% -0.0731
12 General Service(R&F) 23A 2,565 42,247 $4,797 ($32) -0.7% -0.0731
13 Subtotal-Schedule 23 11,230 259,822 28,608 0.09146 (190) -0.7%
14 General Service Optional TOD 35 3 323 $33 ($0) -0.7% -0.0782
15 General Service Optional TOD(R&F) 35A 1 56 $9 ($0) -0.7% -0.0782
16 Subtotal-Schedule 35 4 379 42 (0) -0.7%
17 Special Contract 400 1 1,314,200 $91,220 0.33502 $0 0.0% 0.0000
18 AGA Revenue $520 0.0%
19 Total Commercial&Industrial 18,284 2,675,446 $226,038 ($807) -0.4%
20 Public Street Lighting
21 Security Area Lighting 7 174 230 $46 ($0) -0.2% -0.0329
22 Security Area Lighting(R&F) 7A 119 93 $22 ($0) -0.2% -0.0329
23 Street Lighting-Company 11 61 182 $81 ($0) -0.2% -0.0702
24 Street Lighting-Customer 12 266 2,360 $356 ($1) -0.2% -0.0237
25 AGA Revenue $0
26 Total Public Street Lighting 620 2,866 $506 0.00038 ($1) -0.2%
27 Total Sales to Ultimate Customers 90,837 3,470,059 $326,076 ($1,381) -0.4%
28 Total Excluding Special Contract 400 90,836 2,155,859 $234,856 1.00000 ($1,381) -0.6%

Case No. PAC-E-26-05
Exhibit No. 5
Witness: Kenneth Lee Elder, Jr.
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Kenneth Lee Elder, Jr.
April 2026

Rocky Mountain Power
Exhibit No.5 Page 1 of 5
Case No. PAC-E-26-05
_ ROCKY MOUNTAIN Witness:Kenneth Lee Elder,Jr.
POWER
A DIVISION OF PACIFICORP
Eighteenth Seventeenth Revision of Sheet No. 94.1
LP.U.C.No. 1 Canceling SeventeenthSixteentth Revision of Sheet No. 94.1
ROCKY MOUNTAIN POWER
ELECTRIC SERVICE SCHEDULE NO.94
STATE OF IDAHO
Energy Cost Adjustment
AVAILABILITY: At any point on the Company's interconnected system.
APPLICATION: This Schedule shall be applicable to all retail tariff Customers taking service under the
Company's electric service schedules.
ENERGY COST ADJUSTMENT: The Energy Cost Adjustment is calculated to collect the
accumulated difference between total Company Base Net Power Cost and total Company Actual Net Power Cost
calculated on a cents per kWh basis.
MONTHLY BILL: In addition to the Monthly Charges contained in the Customer's applicable
schedule,all monthly bills shall have applied the following cents per kilowatt-hour rate by delivery voltage.
Delivery Voltage
Secondary Primary Transmission
Schedule 1 1.4-3-70640 per kWh
Schedule 6 1.4-3-70640 per kWh 1.4460440 per kWh
Schedule 6A 1.4-7064¢per kWh 1.4460440 per kWh
Schedule 7 1.4-7064¢per kWh
Schedule 7A 1.�0640 per kWh
Schedule 9 1.009-790 per kWh
Schedule 10 1.4370640 per kWh
Schedule 11 1.�0640 per kWh
Schedule 12 1.4-3-7064¢per kWh
Schedule 23 1.43-70640 per kWh 14"044¢per kWh
Schedule 23A 1.1-3-70640 per kWh 1.1"044¢per kWh
Schedule 24 1.1-3-70640 per kWh 1.1"044¢per kWh
Schedule 35 1.4-3-70640 per kWh 14"044¢per kWh
Schedule 35A 1.4-370640 per kWh 1.44,60440 per kWh
Schedule 36 1.4-370640 per kWh
Schedule 400 1.00960 per kWh
Submitted Under Case No.PAC-E-26-5-054
ISSUED: "April 1,2026-5 EFFECTIVE: June 1, 20265

Rocky Mountain Power
Exhibit No.5 Page 2 of 5
Case No. PAC-E-26-05
qw ROCKY MOUNTAIN Witness:Kenneth Lee Elder,Jr.
POWER
A DIVISION OF PACIFICORP
First Revision of Sheet No.98.1
LP.U.C. No. 1 Canceling Original Sheet No. 98.1
ROCKY MOUNTAIN POWER
ELECTRIC SERVICE SCHEDULE NO.98
STATE OF IDAHO
REC Revenue Adjustment
PURPOSE: The REC Revenue Adjustment is designed to refund actual REC revenue to customers.
APPLICATION: This Schedule shall be applicable to all retail tariff Customers taking service
under the Company's electric service schedules.
MONTHLY BILL: In addition to the Monthly Charges contained in the Customer's applicable
schedule, all monthly bills shall have applied the following cents per kilowatt-hour rate.
Submitted Under Case No.PAC-E-264-054
ISSUED: April 1-3,20265 EFFECTIVE: June 1,202624

Rocky Mountain Power
Exhibit No.5 Page 3 of 5
Case No. PAC-E-26-05
_ ROCKY MOUNTAIN Witness:Kenneth Lee Elder,Jr.
POWER
A DIVISION OF PACIFICORP
First Revision of Sheet No.98.1
I.P.U.C.No. 1 Canceling Original Sheet No. 98.1
Schedule 1 0.000-0.07290 per
kWh
Schedule 6 0.000-0.06660 per
kWh
Schedule 6A 0.000-0.06660 per
kWh
Schedule 7 0.000-0.03290 per
kWh
Schedule 7A 0.000-0.03290 per
kWh
Schedule 9 0.000-0.05620 per
kWh
Schedule 10 0.000-0.04960 per
kWh
Schedule 11 0.000-0.07020 per
kWh
Schedule 12 0.000-0.02370 per
kWh
Schedule 23 0.000-0.0731¢per
kWh
Schedule 23A 0.000-0.0731¢per
kWh
Schedule 35 0.000-0.07820 per
kWh
Schedule 35A 0.000-0.07820 per
kWh
Schedule 36 0.000-0.07070 per
kWh
Schedule 400 0.000¢ per kWh
Submitted Under Case No.PAC-E-264-054
ISSUED: April 1-3,20265 EFFECTIVE: June 1,202624

Rocky Mountain Power
Exhibit No.5 Page 4 of 5
Case No. PAC-E-26-05
_ROCKY MOUNTAIN Witness:Kenneth Lee Elder,Jr.
POWER
A DIVISION OF PACIFICORP
Eighteenth Revision of Sheet No. 94.1
I.P.U.C.No. 1 Canceling Seventeenth Revision of Sheet No. 94.1
ROCKY MOUNTAIN POWER
ELECTRIC SERVICE SCHEDULE NO. 94
STATE OF IDAHO
Energy Cost Adjustment
AVAILABILITY: At any point on the Company's interconnected system.
APPLICATION: This Schedule shall be applicable to all retail tariff Customers taking service under the
Company's electric service schedules.
ENERGY COST ADJUSTMENT: The Energy Cost Adjustment is calculated to collect the
accumulated difference between total Company Base Net Power Cost and total Company Actual Net Power Cost
calculated on a cents per kWh basis.
MONTHLY BILL: In addition to the Monthly Charges contained in the Customer's applicable
schedule,all monthly bills shall have applied the following cents per kilowatt-hour rate by delivery voltage.
Delivery Voltage
Secondary Primary Transmission
Schedule 1 1.064¢per kWh
Schedule 6 1.064¢per kWh 1.044¢per kWh
Schedule 6A 1.064¢per kWh 1.044¢per kWh
Schedule 7 1.064¢per kWh
Schedule 7A 1.064¢per kWh
Schedule 9 1.0090 per kWh
Schedule 10 1.0640 per kWh
Schedule 11 1.0640 per kWh
Schedule 12 1.0640 per kWh
Schedule 23 1.0640 per kWh 1.0440 per kWh
Schedule 23A 1.064¢per kWh 1.044¢per kWh
Schedule 24 1.064¢per kWh 1.044¢per kWh
Schedule 35 1.064¢per kWh 1.044¢per kWh
Schedule 35A 1.064¢per kWh 1.044¢per kWh
Schedule 36 1.064¢per kWh
Schedule 400 1.009¢per kWh
Submitted Under Case No. PAC-E-26-05
ISSUED: April 1, 2026 EFFECTIVE: June 1,2026

Rocky Mountain Power
Exhibit No.5 Page 5 of 5
Case No. PAC-E-26-05
_ROCKY MOUNTAIN Witness:Kenneth Lee Elder,Jr.
POWER
A DIVISION OF PACIFICORP
First Revision of Sheet No. 98.1
I.P.U.C. No. 1 Canceling Original Sheet No. 98.1
ROCKY MOUNTAIN POWER
ELECTRIC SERVICE SCHEDULE NO. 98
STATE OF IDAHO
REC Revenue Adjustment
PURPOSE: The REC Revenue Adjustment is designed to refund actual REC revenue to customers.
APPLICATION: This Schedule shall be applicable to all retail tariff Customers taking service
under the Company's electric service schedules.
MONTHLY BILL: In addition to the Monthly Charges contained in the Customer's applicable
schedule, all monthly bills shall have applied the following cents per kilowatt-hour rate.
Schedule 1 -0.07290 per kWh
Schedule 6 -0.06660 per kWh
Schedule 6A -0.06660 per kWh
Schedule 7 -0.03290 per kWh
Schedule 7A -0.03290 per kWh
Schedule 9 -0.05620 per kWh
Schedule 10 -0.04960 per kWh
Schedule 11 -0.07020 per kWh
Schedule 12 -0.02370 per kWh
Schedule 23 -0.0731¢per kWh
Schedule 23A -0.0731¢per kWh
Schedule 35 -0.07820 per kWh
Schedule 35A -0.07820 per kWh
Schedule 36 -0.07070 per kWh
Schedule 400 0.000¢per kWh
Submitted Under Case No. PAC-E-26-05
ISSUED: April 1, 2026 EFFECTIVE: June 1,2026