20250327Application_Direct J. Painter_Exhibits.pdf

_ ROCKY MOUNTAIN 1407 W.North Temple,Suite 330
POWER. Salt Lake City,UT 84116
A DIVISION OF PACIFICORP
March 27, 2025 RECEIVED
March 27, 2025
VIA ELECTRONIC DELIVERY IDAHO PUBLIC
UTILITIES COMMISSION
Commission Secretary
Idaho Public Utilities Commission
11331 W. Chinden Blvd
Building 8 Suite 201A
Boise, ID 83714
RE: CASE NO. PAC-E-25-04
IN THE MATTER OF THE APPLICATION OF ROCKY MOUNTAIN POWER
REQUESTING APPROVAL OF $66.7 MILLION ECAM DEFERRAL
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 and Mr.Robert M.Meredith.
Their workpapers are also provided.
Informal inquiries may be directed to Mark Alder, Idaho Regulatory Manager at(801) 220-2313.
Very truly yours,
a'l-D
Joe Steward 9L
Senior Vice President, 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 ) CASE NO. PAC-E-25-04
OF ROCKY MOUNTAIN POWER )
REQUESTING APPROVAL OF$66.7 ) APPLICATION OF
MILLION ECAM DEFERRAL ) ROCKY MOUNTAIN POWER
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$66.7 million of deferred costs from the deferral
period beginning January 1, 2024, through December 31, 2024, ("Deferral Period") with a 2.2
percent overall increase to Electric Service Schedule No. 94, Energy Cost Adjustment("Schedule
94"). In support of its Application, Rocky Mountain Power states as follows:
I. 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.
APPLICATION OF ROCKY MOUNTAIN POWER Page I

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),
• 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.3
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").
2 Id. at 2-3.
3 Id. at 3.
APPLICATION OF ROCKY MOUNTAIN POWER Page 2

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 Renewable
Energy Credit ("REC") revenues,6 Production Tax Credits ("PTC"),7 the reasonable energy price
("REP"), as defined in the 2020 Protocol, qualified facility ("QF") costs,' 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.
7. PTCs are tracked in the ECAM without applying the sharing band.10 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. 11 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.12 As published in Internal Revenue Service ("IRS")Notice 2024-69, the 2024 PTC rate
for electricity generated from qualifying wind facilities placed in service prior to January 1, 2022,
4 Id. at 4.
5 See In the Matter of the Application of PacifiCorp DBA Rocky Mountain Power forApproval 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 the Application of PacifiCorp DBA Rocky Mountain Power for Approval of Changes to its Electric
Service Schedules, Case No.PAC-E-10-07,Order No.32196 at 17(February 28,2011).
7 In the Matter of PacifiCorp DBA Rocky Mountain Power's Application to Modify 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").
'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).
10 2015 ECAM Order at 5.
"IRC section 45(a).
IRC section 45(a).
APPLICATION OF ROCKY MOUNTAIN POWER Page 3

is 2.9 cents per kilowatt hour.13 The 2024 PTC rate for electricity generated from qualifying wind
facilities placed in service after December 31, 2021 is 3.0 cents per kilowatt hour.14 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.'15 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.
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.
13 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 and Rock River I.
14 Also as published in IRS Notice 2024-69,the 2024 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 and Rock River I were placed in service after December 31, 2021, and began construction prior to January 29,
2023,making the applicable 2024 credit rate for this project 3.0 cents per kilowatt hour.
15 Foote Creek II-IV was placed in service during 2023,and Rock River I was placed in service in 2024. Both facilities
are located in Census Tract Number FIPS Code 56007968100, which is a qualified energy community pursuant to
IRS Notice 2023-29, Appendix C. Therefore, the Foote Creek II-IV and Rock River I 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

PROPOSED ECAM RATE
8. In support of this Application, Rocky Mountain Power has filed the testimony and
exhibits of Company witnesses Jack Painter and Robert M. Meredith. 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. Mr. Meredith's testimony describes
how the Company's proposed rates were set to recover the 2024 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 most recent rate case,
("2021 Rate Case").16 For the Deferral Period the NPC differential was approximately $70.5
million before the 90/10 percent sharing band. Mr. Painter's testimony explains the main drivers
for the net power cost deferral,which include coal fuel supply constraints,increased market power
and natural gas prices, impact from Jim Bridger Unit 1 and Unit 2 taken offline during the
conversion from coal to natural gas, decommissioning of the Company's hydro generating
facilities on the Klamath river, and extreme weather events.
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,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
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-21-07. The test period for
this case was based on a historical twelve-month period ending December 31,2020,with adjustments made for known
and measurable changes through December 31,2021.
APPLICATION OF ROCKY MOUNTAIN POWER Page 5

Idaho load. The LCAR decreased the deferral balance by approximately $1.8 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 decreased the ECAM deferral by $546,980 before
applying the sharing band.
13. The total NPC deferral adjusted for LCAR and EITF 04-6 was approximately$68.2
million for which customers are responsible 90 percent, and the Company is responsible for the
remaining 10 percent. After accounting for the sharing band, the NPC deferral is approximately
$61.4 million.
14. During the Deferral Period the PTC differential, as described in paragraph 7,
increase the deferral approximately $364 thousand.
15. The ECAM also tracks the difference between actual REC revenues during the
Deferral Period and the amount of REC revenues credited to customers in base rates. The REC
revenue true-up included in the ECAM is symmetrical,but no sharing band is applied. During the
Deferral Period actual REC revenue was $791,134 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$100,045.
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
$4.3 million was added to the ECAM balance.
APPLICATION OF ROCKY MOUNTAIN POWER Page 6

18. As described in Mr. Meredith's testimony, the Company is proposing to collect
$76.8 million, including $66.7 million from the 2024 ECAM deferral (inclusive of interest), plus
$22.0 million remaining balance from prior ECAM filing. The Company estimates the ECAM
balance will be reduced by $15.4 million from Schedule 94 revenue collections accrued from
January 1, 2025 through May 31, 2025, resulting in an estimated ECAM balance of$73.2 to be
collected. With the addition of carrying charges during the rate effective period of June 1, 2025
through May 31, 2027, the total estimated recovery by the Company through the ECAM over the
rate effective period is $76.8 million which includes $3.6 million in interest accrued during the
collection period.
19. Based on this rate design,the Company proposes Schedule 94 rates of 1.137, 1.116,
and 1.079 cents per kWh for secondary, primary, and transmission delivery service voltages,
respectively. The proposed rate for Schedule 400 is 1.096 cents per kWh.
COMMUNICATIONS
Communications regarding this filing should be addressed to:
Mark Alder
Idaho Regulatory Affairs Manager
Rocky Mountain Power
1407 West North Temple, Suite 330
Salt Lake City,Utah 84116
Telephone: [phone]
Email: mark.alderkpacificorp.com
Joe Dallas (ISB# 10330)
Senior Attorney
Rocky Mountain Power
825 NE Multnomah, Suite 2000
Portland, OR 97232
Telephone: [phone]
Email:joseph.dallaskpacificorp.com
APPLICATION OF ROCKY MOUNTAIN POWER Page 7

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 NE Multnomah, Suite 2000
Portland, Oregon 97232
Informal questions may be directed to Mark Alder, Idaho Regulatory Affairs Manager at
[phone].
Included with this Application is a copy of the press release,which will be issued on March
27, 2025. Additionally, this Application includes a copy of the customer notice, which will be
included with customers'bills beginning April 3, 2025, 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
APPLICATION OF ROCKY MOUNTAIN POWER Page 8

approximately $66.7 million ECAM deferral; and(3) approving a 2.2 percent increase to Electric
Service Schedule No. 94, Energy Cost Adjustment effective June 1, 2025.
DATED this 27th day of March 2025.
Respectfully submitted,
ROCKY MOUNTAIN POWER
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 9

CUSTOMER NOTICES

-ROCKY MOUNTAIN
POWER.
POWERING YOUR GREATNESS
For information, contact: News Media Hotline [phone]
Annual energy cost adjustment
Higher fuel costs and severe weather prompt price increase request
for Idaho customers of Rocky Mountain Power
BOISE, Idaho (March 27, 2025) — Rocky Mountain Power's costs for fuel and wholesale electricity
increased in 2024 but at a lower rate than the previous year, still necessitating a modest increase in
customer bills.As part of an annual review of these costs, the company requested an average 1.9%
increase for Idaho customers.A typical residential customer using 836 kilowatt-hours per month would
see a 1.7% increase, or$1.94 per month on their electricity bill.The company proposes the increase to
take effect June 1, 2025, subject to review by the Idaho Public Utilities Commission.
"We recognize that in difficult economic conditions, a price increase is not good news," said David
Eskelsen, spokesman for Rocky Mountain Power. "Despite these difficulties, we remain committed to
bringing the best value to our customers for their hard-earned dollars. We've worked diligently to
control the costs we can control. We are strict with our budgets and continue our work to steadily
improve our system to enhance reliability for our 91,453 customers in southeastern Idaho. We know
how important reliable service is for businesses and homes alike.
"The company is working hard to maintain our position as a low-cost energy provider," Eskelsen added.
"The annual adjustment process makes sure Rocky Mountain Power customers always pay a fair price
for the energy they need."
Coal supply constraints that extended into mid-2024, increased prices of wholesale power purchased
from other companies, higher natural gas costs, and lower availability of hydroelectric resources all
contributed to higher costs of these market commodities purchased to serve customers in 2024.
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. Pending commission approval,the
changes would take effect June 1, 2024, with the following impact on each rate schedule:
Residential Schedule 1—1.7% increase
Residential Schedule 36—1.9% increase
General Service Schedule 6—2.2% increase
General Service Schedule 9—2.8% increase
Irrigation Service Schedule 10—2.0% increase

General Service Schedule 23—1.7% increase
General Service Schedule 35—2.1% increase
Public Street Lighting—1.2%increase
Tariff Contract 400—2.9% increase
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-25-04. 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 increase
Rocky Mountain Power requests recovery of power costs
On March 27, 2025, Rocky Mountain Power asked the Idaho Public Utilities Commission to approve the incremental energy-related
costs for 2024 of$76.8 million, over two years.On annual basis,this is a net increase of$7.9 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 increase would take effect June 1,2025.All customer classes will see a net increase to their rates
due to several factors.The main drivers of increased costs in 2024 were coal fuel supply limitations, increased prices for market
power and natural gas purchases,Jim Bridger Unit 1 and Unit 2 being offline during the conversion from coal to natural gas,the
decommissioning of the company's hydroelectric facilities on the Klamath River,and extreme weather events. Prices for market
power and natural gas have risen sharply since 2021,and remain elevated.
A typical residential customer using 836 kilowatt-hours per month would see an increase of approximately$1.94 a month on their
electricity bill.The following is a summary of the percentage impacts by customer class:
• Residential Schedule 1-1.7%increase
• Residential Schedule 36—1.9%increase
• General Service Schedule 6—2.2%increase
• General Service Schedule 9—2.8%increase
• Irrigation Service Schedule 10—2.0%increase
• General Service Schedule 23—1.7%increase
• General Service Schedule 35—2.1%increase
• Public Street Lighting—1.2%increase
• Tariff Contract 400—2.9%increase
We understand the impact that price increases have on our customers and that a price increase is never welcome news.We will
work to mitigate that impact as much 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-25-04.
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.
Idaho Public Utilities Commission
11331 W Chinden Blvd
Building 8,Suite 201A
Boise, ID 83714
www.puc.idaho.gov
Rocky Mountain Power offices
• Rexburg—127 East Main

• Preston—509 S. 2nd E.
• Shelley—852 E. 1400 N.
• Montpelier—24852 U.S. Hwy 89
For more information about your rates and rate schedule,go to RockyMountainPower.net/Rates.

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION ) CASE NO. PAC-E-25-04
OF ROCKY MOUNTAIN POWER )
REQUESTING APPROVAL OF $66 . 7 ) DIRECT TESTIMONY OF
MILLION ECAM DEFERRAL ) JACK PAINTER
ROCKY MOUNTAIN POWER
CASE NO. PAC-E-25-04
March 2025

1 Q. Please state your name, business address, and present
2 position with PacifiCorp d/b/a Rocky Mountain Power
3 ("Rocky Mountain Power" or the "Company") .
4 A. My name is Jack Painter and my business address is 825
5 NE Multnomah Street, Suite 600, Portland, Oregon 97232 .
6 My title is Net Power Cost Adviser.
7 I . QUALIFICATIONS
8 Q. Please describe your education and professional
9 experience.
10 A. I received a Bachelor of Arts degree in Business
11 Administration with a Finance major from Washington
12 State University in 2007 . I have been employed by
13 PacifiCorp since 2008 and have held positions in the
14 regulation and jurisdictional loads departments . I
15 joined the regulatory net power costs group in 2019 and
16 assumed my current role as a Net Power Cost Adviser in
17 2024 .
18 Q. Have you testified in previous regulatory proceedings?
19 A. Yes . I have previously provided testimony to the public
20 utility commissions in Idaho, Utah, Wyoming, Oregon,
21 Washington, and California.
22 II . PURPOSE OF TESTIMONY
23 Q. What is the purpose of your testimony in this proceeding?
24 A. My testimony presents and supports the Company' s
25 calculation of the Energy Cost Adjustment Mechanism
Painter, Di 1
Rocky Mountain Power

1 ("ECAM") balancing account for the 12-month period of
2 January 1, 2024 through December 31, 2024 ("Deferral
3 Period") . More specifically, I provide the following:
4 • A summary of the ECAM calculation, including
5 changes made to comply with Idaho Public Utility
6 Commission ("Commission") orders;
7 • Details supporting the addition of approximately
8 $66 . 7 million to the deferral balance, including
9 $61 . 4 million customers' share of ECAM costs, a
10 $364 thousand decrease in renewable energy
11 production tax credits ("PTCs") , $1 . 5 million in
12 reasonable energy price ("REP") qualified facility
13 ("QF") costs, a credit of $100 thousand for wind
14 availability liquidated damages, a $791 thousand
15 renewable energy credit ("REC") revenue
16 differential, and $4 . 3 million interest accrued
17 during the Deferral Period;
18 • Discussion of the main differences between adjusted
19 actual net power costs ("Actual NPC") and net power
20 costs in rates ("Base NPC") ; and
21 • Discussion about the Company' s participation in the
22 Western Energy Imbalance Market ("WEIM") with the
23 California Independent System Operator ("CAISO")
24 and the benefits from the WEIM that are passed
25 through to customers .
Painter, Di 2
Rocky Mountain Power

1 Q. What other witnesses present testimony for the ECAM and
2 Tariff Schedule 94 in this case?
3 A. Mr. Robert M. Meredith, Director, Regulation, provides
4 testimony on the proposed rates in Electric Service
5 Schedule No. 94, Energy Cost Adjustment ("Schedule 94") .
6 III . SUMMARY OF THE ECAM DEFERRAL CALCULATION
7 Q. Please briefly describe the Company' s ECAM authorized by
8 the Commission.
9 A. The ECAM tracks deviations between Actual NPC and Base
10 NPC. When there is a difference between these two
11 amounts, 90 percent of the difference is deferred for
12 later recovery or return to customers . ' In addition to
13 tracking the difference between Actual and Base NPC, the
14 ECAM also tracks other items including PTCs, the
15 Reasonable Energy Price QF adjustment, wind availability
16 liquidated damages, and revenues from the sale of RECs . 2
17 The purpose for tracking these items is to true-up base
18 rates to actuals . The balance that accumulates over a
19 deferral period is then passed on to customers as a rate
20 surcharge or credit . Schedule 94, described in
21 Mr. Meredith' s testimony, appears as a separate line
22 item on customers' bills and either collects from or
' See Order No. 30904 in Case No. PAC-E-08-08 and Order No. 33440 in Case
No. PAC-E-15-09.
2 See In the Matter of PacifiCorp DBA Rocky Mountain Power's Application
to Modify the Energy Cost Adjustment Mechanism and Increase Rates, Case
No. PAC-E-15-09, Order No. 33440 at 5-6 (December 23, 2015) .
Painter, Di 3
Rocky Mountain Power

1 credits to customers the balance of deferred costs .
2 Schedule 94 is adjusted as needed in the Company' s annual
3 ECAM filings .
4 The Company is required to file an application with
5 the Commission annually by April 1st to request approval
6 of the deferral amount and the new Schedule 94 rates to
7 become effective June 1 .
8 Q. Are there any changes to the ECAM calculation?
9 A. No . The rates for Base NPC, PTCs, RECs, and the Load
10 Change Adjustment Revenue ("LCAR") were established in
11 the Company' s last general rate case ("GRC") Case No .
12 PAC-E-21-07, which became effective January 1, 2022, and
13 are the same rates used in the previous ECAM Case No .
14 PAC-E-23-09 . 3
15 IV. ECAM DEFERRAL CALCULATION
16 Q. Please describe the calculation of the ECAM deferral
17 included in this filing.
18 A. Table 1 summarizes the total ECAM deferral and provides
19 a breakdown of the individual components of the ECAM.
20 For a detailed monthly calculation of the ECAM deferral,
21 please refer to Exhibit No . 1 .
3 In the Matter of Rocky Mountain Power's Application for Authority to
Increase its Rates and Charges in Idaho and Approval of Proposed Electric
Service Schedules and Regulations, Case No. PAC-E-21-07, Order No. 35277
(December 30, 2021) .
Painter, Di 4
Rocky Mountain Power

1 Table 1 — 2024 ECAM Deferral
Calendar Year 2024 ECAM Deferral
NPC Differential $ 70,481,775
EITF 04-6 Adjustment (546,980)
LCAR (1,757,888)
Total Deferral Before Sharing $ 68,176,907
Sharing Band 90%
Customer Reponsibility $ 61,359,217
Production Tax Credits $ 363,786
REP QF Adjustment 1,512,726
Wind Liquidated Damages (100,045)
REC Deferral (791,134)
Interest on Deferral 4,314,352
Annual Deferral(Jan-Dec 2024) $ 66,658,903
2 The first section of Table 1 summarizes the Idaho-
3 allocated share of those items for which Idaho customers
4 and the Company share responsibility, including: NPC
5 differential, Emerging Issues Task Force ("EITF") 04-6
6 adjustment, and the LCAR costs . The second section
7 calculates the 90 percent customers' share of these
8 items . Finally, the last section adds the following
9 items that are either refunded or collected in full
10 (i .e . , 100 percent) : PTCs, REP QF costs, wind
11 availability liquidated damages, REC revenues, and
12 interest on the deferral . The total of these items
13 represents the SCAM deferral .
Painter, Di 5
Rocky Mountain Power

1 Q. Based on your calculations , what is the balance expected
2 to be in the ECAM deferral account as of June 1 , 2025?
3 A. Table 2 provides a summary of the ECAM balancing account
4 activity starting with the December 31, 2023, ECAM
5 deferral balance of $73 . 1 million approved in Case No .
6 PAC-E-24-05 . By June 1, 2025, the projected balance in
7 the ECAM deferral account will be approximately $73 . 2
8 million. During the Deferral Period, approximately $66 . 7
9 million is added to the balance from the annual deferral
10 and interest, which is offset by $51 . 1 million of ECAM
11 revenue collections through the Deferral Period, and an
12 estimated collection of $15 . 4 million of Schedule 94
13 revenues, net of interest, between January and May of
14 2025 .
15 Q. Has the Company made any changes to Table 2?
16 A. Yes . The Company has calculated the estimated impact of
17 carrying charges during the rate effective period of
18 June 1, 2025 through May 31, 2027 and has included them
19 in Table 2 below. The total estimated recovery by the
20 Company through the ECAM over the rate effective period
21 is $76 . 8 million which includes the estimated balance of
22 $73 .2 million on June 1, 2025 discussed above plus $3 . 6
23 million in interest accrued during the collection
24 period.
Painter, Di 6
Rocky Mountain Power

1 Q. Why is the Company incorporating carrying charges into
2 its rate calculation for the two-year amortization
3 period?
4 A. The ECAM balance continues to accrue interest during the
5 collection period. Including carrying charges into the
6 rate calculation ensures that the rates are designed to
7 collect the entire SCAM balance, including interest, by
8 the end of the collection period. Mr. Meredith will
9 further explain Schedule 94 rates and the rate
10 collection period.
11 Table 2 - Balancing Account Activity
ECAM Deferral Balance
Deferral Balance - Dec 31, 2023 $ 73,082,282
Annual Deferral (Jan - Dec 2024) 62,344,550
Interest 4,314,352
ECAM Revenue Collection - Schedule 94 (51,121,109)
December 31, 2024 Balance For Collection $ 88,620,076
Schedule 94 Collection - Jan - May 2025 $ (17,040,501)
Interest 1,646,368
Expected Balance as of June 1, 2025 $ 73,225,942
Interest Accrued through Rate Effective Period
June 1, 2025 through May 31, 2027 $ 3,579,537
Total ECAM Balance for Recovery $ 76,805,479
12 Q. Please describe the ECAM calculations in Exhibit No. 1 .
13 A. The ECAM deferral is calculated monthly by comparing
14 Idaho-allocated Actual NPC to the Base NPC collected in
15 rates and then deferring the differences into an SCAM
16 balancing account . Exhibit No . 1 includes details of the
Painter, Di 7
Rocky Mountain Power

1 ECAM calculation. Additionally, I have also provided
2 confidential work papers supporting this exhibit .
3 Q. How are the Base NPC and Actual NPC calculated?
4 A. Exhibit No . 1 provides details of the ECAM calculation.
5 The monthly Base NPC collected in rates, as set forth in
6 Exhibit No . 1 line 6, is calculated by taking the dollar-
7 per-megawatt-hour Base NPC rate multiplied by actual
8 Idaho retail sales . Actual Idaho NPC, as set forth in
9 Exhibit No . 1 line 11, is calculated by dividing the
10 monthly total-Company Actual NPC in the Deferral Period
11 by the actual monthly system megawatt-hours ("MWh") in
12 the Deferral Period. To calculate Actual Idaho NPC, the
13 total Company Actual NPC dollar-per-megawatt-hour basis
14 is then multiplied by Idaho actual monthly MWh.
15 Q. Please describe how the NPC deferral is calculated.
16 A. The deferral is calculated monthly by subtracting the
17 Base NPC collected in rates from the Actual Idaho NPC.
18 For the Deferral Period, the NPC differential was $70 . 5
19 million before applying the 90/10 percent sharing band.
20 Q. What costs are included in the NPC differential for
21 deferral?
22 A. The NPC differential for deferral captures all
23 components of NPC as defined in the Company' s general
24 rate case proceedings and modeled by the Company' s
25 production dispatch model, the Generation and Regulation
Painter, Di 8
Rocky Mountain Power

1 Initiative Decision Tool (`GRID") . Specifically, Base
2 NPC and Actual NPC include amounts booked to the
3 following Federal Energy Regulatory Commission ("FERC")
4 accounts :
5 Account 447 - Sales for resale; excluding on-
6 system wholesale sales and other revenues
7 that are not modeled in GRID
8 Account 501 - Fuel, steam generation; excluding
9 fuel handling, start-up fuel (gas and
10 diesel fuel, residual disposal) , and
11 other costs that are not modeled in GRID
12 Account 503 - Steam from other sources
13 Account 547 - Fuel, other generation
14 Account 555 - Purchased power; excluding the
15 Bonneville Power Administration ("BPA")
16 residential exchange credit pass-through
17 if applicable
18 Account 565 - Transmission of electricity by
19 others
20 Q. Are adjustments made to the Actual NPC before comparing
21 them to Base NPC?
22 A. Yes . The Company adjusts Actual NPC to reflect the
23 ratemaking treatment of several items, including:
24 out of period accounting entries booked in the
25 Deferral Period that relate to operations before
Painter, Di 9
Rocky Mountain Power

1 implementation of the ECAM on July 1, 2009;
2 • buy-through of economic curtailment by
3 interruptible industrial customers;
4 • revenue from a contract related to the Leaning
5 Juniper wind resource;
6 • costs for situs-assigned resources/programs in
7 Oregon and Utah;
8 • coal inventory adjustments to reflect coal costs
9 in the correct period;
10 • legal fees related to fines and citations
11 included in the cost of coal;
12 • compliance costs for Washington greenhouse gas
13 emissions related to the Company' s generation at
14 its Chehalis natural gas generating plant;
15 • wind availability liquidated damages; and
16 • reasonable energy price adjustments to QFs .
17 Q. Why is the July 1 , 2009, cutoff used to determine out of
18 period entries?
19 A. Since the ECAM took effect, customers' rates have been
20 adjusted to recover essentially all of the Company' s
21 actual net power costs, excluding any differences due to
22 the 90/10 percent sharing band. Consequently, any
23 accounting entries made during the current Deferral
24 Period that relate to any operating period since the
25 ECAM took effect should be reflected in customer rates,
Painter, Di 10
Rocky Mountain Power

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

1 a $547 thousand decrease to the ECAM deferral balance,
2 before the application of the 90/10 percent sharing
3 band.
4 Q. Please describe the LCAR adjustment.
5 A. The calculation of the LCAR adjustment is a symmetrical
6 adjustment for over- or under-collection of the energy-
? related portion of the Company' s embedded revenue
8 requirement for production facilities, as specified in
9 Case No. GNR-E-10-03, Order No . 32206 . This adjustment
10 accounts for variances in Idaho load that cause the
11 Company to collect more or less of these production-
12 related costs . The LCAR rate of $8 . 74 per MWh is used
13 for the Deferral Period.
14 Q. How is the LCAR adjustment calculated and what impact
15 does it have on the Deferral Period?
16 A. The LCAR adjustment assumes that the actual production-
17 related costs of the LCAR are equivalent to the base
18 amount on Exhibit No . 1 line 14 . The actual production-
19 related costs are then compared to the LCAR revenue
20 collection in rates, calculated by multiplying the LCAR
21 rate by the actual Idaho retail sales on Exhibit No . 1
22 line 17 . The LCAR adjustment, which is shown on line 18
23 of Exhibit No. 1, is the difference between the actual
24 production-related costs and the LCAR revenue . This
25 adjustment results in a $1 . 8 million decrease to the
Painter, Di 12
Rocky Mountain Power

1 ECAM deferral balance before application of the 90/10
2 percent sharing band.
3 Q. Please explain the sharing band ratio between the
4 Company and customers in the ECAM.
5 A. The ECAM includes a sharing band with a symmetrical
6 sharing ratio in which customers either pay or receive
7 90 percent of the ECAM deferral balance, and the Company
8 is responsible for the remaining 10 percent . Line 20 of
9 Exhibit No. 1 represents the customers' 90 percent share
10 of the monthly deferral shown on line 19 . For the
11 Deferral Period, the customers' share of the deferred
12 balance is $61 . 4 million. The remaining balance of $6 . 8
13 million associated with the Company' s 10 percent share
14 is not included in the deferral balance as it is not
15 recoverable from customers .
16 Q. What is the amount of the PTC true-up in the current
17 filing?
18 A. The PTC Deferral, on line 25 of Exhibit No . 1, is
19 calculated by comparing the actual Idaho-allocated PTC
20 to the PTC credit customers receive through base rates .
21 The PTC credit in base rates is calculated by multiplying
22 the approved PTC rate of $4 . 16/MWh by Idaho retail sales .
23 The difference results in a $364 thousand increase to
24 the ECAM deferral .
Painter, Di 13
Rocky Mountain Power

1 Q. Please explain the REP QF Adjustment.
2 A. As set forth in the 2020 Inter-Jurisdictional Allocation
3 Protocol ("2020 Protocol") : "For the Interim Period, the
4 energy output of New QF PPAs will be dynamically
5 allocated per this agreement using the SG Factor, priced
6 at a forecasted reasonable energy price defined below,
7 and any cost of a New QF PPA above the forecasted
8 reasonable energy price will be situs assigned to and
9 allocated to the State of Origin. " 4 The Idaho situs-
10 assigned cost, on line 26 of Exhibit No . 1, is $1 . 5
11 million.
12 Q. Please explain the wind availability liquidated damages
13 credit.
14 A. Order No. 33954 in Case No. PAC-E-17-06 provides that
15 "the Stipulation requires the Company to pass on to
16 ratepayers all liquidated damages it receives from
17 equipment suppliers in case the repowered equipment does
18 not meet specified availability, performance, or
19 installation schedule requirements . " The Company first
20 removes the wind availability liquidated damages from
21 total-Company NPC and then allocates them to customers
22 using the System Generation ("SG") allocation factor
23 outside of the 90/10 percent sharing band. The wind
4 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 14
Rocky Mountain Power

1 availability liquidated damages credited to customers in
2 the ECAM is $100 thousand, as shown on line 27 of Exhibit
3 No . 1 .
4 Q. What is the amount of REC revenue adjustment in the
5 current filing?
6 A. The REC revenue adjustment shown on line 32 of Exhibit
7 No . 1 is calculated by comparing the actual Idaho-
8 allocated REC revenue with the REC revenue credit
9 customers receive through base rates . The REC revenue
10 credit in base rates is calculated by multiplying the
11 approved REC revenue rate of $0 . 07/MWh by Idaho retail
12 sales . The resulting difference is a $791 thousand
13 decrease to the SCAM deferral .
14 Q. What is the total ECAM deferred balance calculated in
15 Exhibit No. 1?
16 A. The total ECAM deferred balance as of December 31, 2024,
17 is $62 . 3 million, shown on line 33 of Exhibit No . 1,
18 plus $4 . 3 million of interest on line 42, for a total
19 deferral of $62 . 4 million.
20 Q. Does the calculation of the ECAM deferral in this
21 application comply with the parameters of the Idaho ECAM
22 as approved by the Commission?
23 A. Yes, therefore the Company recommends that the
24 Commission approve the SCAM application for recovery of
25 the $66 . 7 million in prudently incurred ECAM costs .
Painter, Di 15
Rocky Mountain Power

1 V. DIFFERENCES IN NPC
2 Q. Please describe the Base NPC the Company used to
3 calculate the NPC component of the ECAM deferral .
4 A. The total-Company Base NPC of $1 . 368 billion were set in
5 Case No. PAC-E-21-07 ("2021 Rate Case") using a 12-month
6 test period of January 2021 through December 2021 and
7 became effective January 1, 2022 . Based upon a
8 normalized forecast and perfect operating conditions,
9 circumstances have changed significantly since the Base
10 NPC were established. Both higher market power and
11 natural gas prices, increased intermittent renewable
12 energy resources, coal fuel supply constraints, changes
13 to the Company' s dispatchable resources, and extreme
14 weather events have all contributed to current system
15 operations that do not represent the forecast. The
16 Company operates its system on a least cost economic
17 dispatch model for its customers and it is important to
18 note that Base NPC are set for ratemaking purposes only,
19 not the management of actual system operations, nor
20 would it be prudent to operate in such a manner. Figure
21 1 below illustrates the comparison of Base NPC to Actual
22 NPC over time .
Painter, Di 16
Rocky Mountain Power

1 Figure 1 - Base NPC vs . Actual NPC ($ billions)
$3.0
$2.5
$2.0
$1.5
$1.0
$0.5
2019 2020 2021 2022 2023 2024
Actual NPC Base NPC
2 Q. On a total-Company basis, what was the difference
3 between Actual NPC and Base NPC for the Deferral Period?
4 A. On a total-Company basis, Actual NPC for the Deferral
5 Period amounted to $2 . 599 billion, exceeding Base NPC
6 for the Deferral Period by $1 . 231 billion. Table 3
7 provides a high-level summary of the difference between
8 Base NPC and Actual NPC by category on a total-Company
9 basis .
Painter, Di 17
Rocky Mountain Power

1 Table 3 - Net Power Cost Reconciliation ($ millions)
TOTAL
Base NPC $ 1,368
Increase/(Decrease)to NPC:
Wholesale Sales Revenue 357
Purchased Power Expense 578
Coal Fuel Expense (72)
Natural Gas Expense 343
Wheeling and Other Expense 25
Total Increase/(Decrease) $ 1,231
Adjusted Actual NPC $ 2,599
2 Q. Please describe the primary differences between Actual
3 NPC and Base NPC.
4 A. From an accounting perspective, and as shown in Table 3,
5 Actual NPC were higher than Base NPC, established in the
6 2021 Rate Case, due to a $357 million reduction in
7 wholesale sales, a $578 million increase in purchased
8 power expense, a $343 million increase in natural gas
9 expense, and a $25 million increase in wheeling and other
10 expenses . These items were partially offset by a $72
11 million reduction in coal fuel expense .
12 Q. What are the main drivers of increased NPC in 2024?
13 A. For 2024, the main drivers of increased NPC were coal
14 fuel supply constraints, increased market power and
15 natural gas prices, the conversion of Jim Bridger Unit
16 1 and Unit 2 from coal to natural gas, the
17 decommissioning of the Company' s hydro generating
Painter, Di 18
Rocky Mountain Power

1 facilities on the Klamath river, and extreme weather
2 events, all of which are discussed with further detail
3 in my testimony below. Coal supply constraints which
4 began at the end of calendar year 2022, continued through
5 the first part of 2024 . Market power prices and natural
6 gas prices have risen sharply since 2021 . Changes to the
7 Company' s dispatchable resources with the Jim Bridger
8 conversion and Klamath river decommissioning impact
9 overall system operations and NPC through lost mega-watt
10 hours . Extreme weather impacts while small in duration
11 have exponential impacts to NPC due to spiking market
12 prices and demand. These drivers have an overarching
13 influence on all components of the Company' s actual
14 system operations through its least cost economic
15 dispatch model .
16 Q. Please explain the changes in wholesale sales revenue
17 and volumes .
18 A. Wholesale sales volumes declined relative to Base NPC
19 due to an increase in total Company load combined with
20 coal supply constraints that persisted into the first
21 half of 2024 and decreases in renewable resource output
22 and hydro generation. When actual market conditions
23 differ from normalized forecast conditions in the power
24 cost production model, the opportunities for the Company
25 to sell excess generation to the market are limited.
Painter, Di 19
Rocky Mountain Power

1 Higher retail loads, lower coal supplies limiting coal
2 generation levels, the conversion of Jim Bridger 1 & 2
3 to natural gas, the retirement of the Klamath hydro units
4 and lower wind generation compared to the base forecast
5 result in fewer opportunities to sell power on wholesale
6 market . Overall, the above market and system dynamics,
7 decreased wholesale sales revenue by $357 million
8 compared to Base NPC. While the average price of actual
9 market sales transactions was $54 . 35/MWh, or 26 percent
10 higher than the average price in Base NPC, actual
11 wholesale market volumes were 8, 797 gigawatt-hours
12 ("GWh") , or 82 percent, lower than Base NPC. In order to
13 achieve a more accurate level of wholesale sales
14 volumes, the Company included enhancements to its power
15 cost modeling in its most recent general rate case (see
16 Case No . PAC-E-24-04) that reduced wholesale sales
17 volumes from current Base NPC .
18 Q. Please explain the changes in purchased power expense.
19 A. Overall, actual purchased power expense increased $578
20 million over Base NPC because the actual average price
21 from market purchase transactions, represented in the
22 power cost production model as short-term firm and
23 system balancing purchases, significantly increased. On
24 a dollar per megawatt-hour basis, actual market purchase
25 transactions increased from $35 . 77/MWh in Base NPC to
Painter, Di 20
Rocky Mountain Power

1 $114 . 86/MWh, or 221 percent . Actual market purchase
2 volumes also increased by 419 or five percent higher
3 than Base NPC.
4 The average monthly price of market transactions at
5 the Mid-Columbia and Four Corners market hubs has risen
6 significantly since 2021 . Between 2016 and 2020, the
7 average monthly Heavy Load Hour ("HLH") market price at
8 the Mid-Columbia market hub was $29 .27/MWh and
9 $35 . 11/MWh at the Four Corners market hub while the
10 average monthly HLH market price in 2024 was $63 . 45/MWh
11 and $47 . 87/MWh respectively. Table 4 and Figure 2
12 illustrate these significant market price increases
13 impacting 2024 NPC.
14 Table 4 — Average HLH Mid-Columbia & Four Corners
15 Market Price
Year Mid-C HLH Average Four-C HLH Average
2016-2020 $29.27 $35.11
2021 $58.36 $65.42
2022 $92.75 $102.59
2023 $85.51 $81.12
2024 $63.45 $47.87
Painter, Di 21
Rocky Mountain Power

1 Figure 2 - Average HLH Mid-Columbia & Four Corners
2 Market Price
$300.00
$250.00
$200.00
$150.00
$100.00
$50.00
$0.00
n n n n m ca ca ca m m m m 0 0 0 0
0 0 0 0 0 0 0 0 0 0 0 0 N N N N N N N N N N N N N N N N N N N N
O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O
N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N N
Q 0 Q 0 9Q 0 9Q 0 Q 0 9Q 0 9Q 0 Q 0
—Mid-Columbia HLH —Four Corners HUH
3 Q. Please explain the changes in coal fuel expense and
4 volumes .
5 A. As discussed in my testimony above, coal supply
6 shortages, primarily at the Hunter and Huntington
7 plants, that began in the fourth quarter of 2022 and
8 extended into mid-2024, had a significant impact on the
9 Company' s coal generating resources and total system
10 operations . 5 Due to overall lower coal fuel availability
11 and newly executed coal contracts in 2024, the Company
12 had to adjust its overall system operations through
13 increased natural gas resource output and reduced
14 wholesale sales . Total coal fuel expense decreased
15 because coal generation volume was 11, 650 GWh, or 39
5 The Company' s 2022 ECAM Confidential Investigative Report submitted to
the Commission in Case No. PAC-E-23-09 on December 22, 2023, provides a
detailed explanation of the issues related to lower coal generation and
coal supplies and the Company' s management of these issues during calendar
year 2022.
Painter, Di 22
Rocky Mountain Power

1 percent lower than Base NPC as presented in Table 5 .
2 Table 5 — Coal Generation
Year Base GWh Actual GWh Variance Percent
2020 ECAM 39,100 30,635 (8,465) (22%)
2021 ECAM 39,100 31,590 (7,510) (19%)
2022 ECAM 29,875 28,391 (1,484) (5%)
2023 ECAM 29,875 21,951 (7,924) (27%)
2024 ECAM 29,875 18,225 (11,650) (39%)
3 Coal supply shortages and new coal contracts also
4 increased the average cost of coal generation from
5 $20 . 08/MWh in Base NPC to $28 . 94/MWh in the Deferral
6 Period. Overall, the lower generation volume results in
7 a decrease of $72 million in coal fuel expense, but the
8 coal supply limitations and new contracts impacted all
9 other aspects of the Company' s system operations and net
10 power costs in 2024 .
11 Q. Please explain the changes in natural gas fuel expense.
12 A. With a reduction in coal generating resource output in
13 2024, the Company increased output at its natural gas
14 generating resources . While natural gas prices and the
15 average cost of natural gas generation are higher than
16 Base NPC, the price for operating the Company' s natural
17 gas generating resources was more economic than market
18 power purchases on average. Overall, the total natural
19 gas fuel expense in Actual NPC increased by $343 million
20 compared to Base NPC. This was due to both an increase
21 in the average cost of natural gas generation from
Painter, Di 23
Rocky Mountain Power

1 $26 . 95/MWh in Base NPC to $33 . 75/MWh in the Deferral
2 period and an increase in gas generation volumes of 8, 455
3 GWh (100 percent) as shown in Table 6 below.
4 Table 6 - Natural Gas Generation
Year Base GWh Actual GWh Variance Percent
2020 ECAM 12,349 12,042 (307) (2%)
2021 ECAM 12,349 13,312 963 8%
2022 ECAM 8,488 13,686 5,198 61%
2023 ECAM 8,488 14,050 5,562 66%
2024 ECAM 1 8,488 1 16,942 1 8,454 100%
5 Q. Please describe how the Jim Bridger units 1 and 2 coal
6 to gas conversion impacted NPC.
7 A. Jim Bridger units 1 and 2 were taken offline at the end
8 of December 2023 for their conversion from coal fired to
9 natural gas fired generating units . Unit 1 was returned
10 to service on 4/16/2024 and Unit 2 was returned to
11 service on 3/12/2024 . The natural gas conversion
12 impacted the overall lower coal generation volumes and
13 increased market purchase volumes while also
14 contributing to increased natural gas generation volumes
15 when the units came back online . Between January 2024
16 and April 2024, 1, 358 GWh were lost that increased NPC
17 by $31 . 9 million.
18 Q. Please describe how hydro conditions and the
19 decommissioned Klamath river hydro generating plants
20 have impacted NPC.
21 A. Weather conditions throughout 2024 have continued to
Painter, Di 24
Rocky Mountain Power

1 lead to lower water volumes for the Company' s hydro
2 resources which reduced the availability of the
3 Company' s hydro resources . Additionally, the Company
4 decommissioned all of its hydro generating facilities on
5 the Klamath river consisting of the Copco #1, Copco #2,
6 Iron Gate, and JC Boyle generating plants . In 2024,
7 actual generation from the Company' s hydro resources was
8 1, 852 GWh (42 percent) lower than forecasted generation
9 from the 2021 Rate Case as shown in Table 7 below and
10 needed to be replaced to meet customer demand which had
11 an estimated impact on total-Company NPC of $111
12 million. The Company has also updated its forecast for
13 hydro generation volumes in its most recent general rate
14 case, Case No. PAC-E-24-04, to better reflect actual
15 operating conditions and the decommissioning of the
16 Klamath river hydro generating facilities .
17 Table 7 - Hydro Generation
Year Base GWh Actual GWh Variance Percent
2020 ECAM 3,812 3,037 (775) (20%)
2021 ECAM 3,812 2,789 (1,023) (27%)
2022 ECAM 4,441 2,936 (1,505) (34%)
2023 ECAM 4,441 3,000 (1,441) (32%)
2024 ECAM 4,441 2,589 (1,852) (42%)
18 Q. Please describe how the January 2024 North America
19 winter storm over the Martin Luther King Jr. holiday
20 weekend impacted NPC.
21 A. Between January 13, 2024 and January 16, 2024, North
Painter, Di 25
Rocky Mountain Power

1 America experienced a significant winter storm with
2 wide-ranging impacts increasing both market and natural
3 gas prices, along with increasing demand. Table 8 and
4 Table 9 below show the large variance between average
5 January market power and gas prices against the average
6 February through December market and gas prices at the
7 Opal and Sumas natural gas hubs and Mid-Columbia and
8 Four Corners market purchase power hubs for 2024 . The
9 total cost of day-ahead and real-time market purchases
10 during this storm was $89 . 9 million.
11 Table 8 - Opal and Sumas Average Monthly Price
12 ($/MMBtu)
Month Opal Sumas
Jan $6.39 $6.33
Feb-Dec $1.82 $1_61
13 Table 9 - Mid-Columbia and Four Corners Average
14 Monthly Price ($/MWh)
Month Mid-C HLH Four-C HLH
Jan $249.95 $91.38
Feb-Dec r $46.50 $43.91
15 VI . IMPACT OF PARTICIPATING IN THE WEIM
16 Q. Are the actual benefits from participating in the WEIM
17 with CAISO included in the ECAM deferral?
18 A. Yes . Participation in the WEIM provides benefits to
19 customers in the form of reduced Actual NPC. The WEIM
20 benefits are embedded in Actual NPC through lower fuel
21 and purchased power costs . According to CAISO' s WEIM
22 benefits report, PacifiCorp has received $192 million in
Painter, Di 26
Rocky Mountain Power

1 benefits in 2024 and $938 million since the inception of
2 the WEIM.
3 VII . CONCLUSION
4 Q. Please summarize your testimony.
5 A. The SCAM deferral of $66 . 7 million, including interest,
6 for the Deferral Period, was accurately calculated in
7 compliance with previous Commission orders . Therefore,
8 I respectfully request that the Commission approve this
9 application as filed with rates effective June 1, 2025 .
10 Q. Does this conclude your direct testimony?
11 A. Yes .
Painter, Di 27
Rocky Mountain Power

Case No. PAC-E-25-04
Exhibit No. 1
Witness : Jack Painter
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Jack Painter
March 2025

Rocky Mountain Power
Exhibit No. 1 Page 1 of 1
Case No. PAC-E-25-04
Witness:Jack Painter
Idaho Energy Cost Adjustment Mechanl.a Dee,-
January 1,2024-December 31,2024
Line
No.
CY 2021
1 ID Base NPC Embedded In Rates(E) PAGE-21- $ 86.53451
2 Annu.l Maho Be.Load @meter(MWT) PAC£-21- 3 52fi 359
3 NPC Rate Embedded In Base Re.(EIMWh) Line I Line2 $ 24.54
1 -24 Fab-L Mar-L At-24 May-24 Jun-24 Jul-24 A.R44 Seo-. Oct-L Nov-41 D.— Total
4 NPC Rate Embedded In Bese Rates(VIfth) Line 3 $ 24.St $ 24.1 $ 24.54 $ 24.54 $ 24.54 $ 24.54 $ 24.54 $ 24.54 $ 24.54 $ 24.54 $ 24.54 $ 24.M
5 ID Actual bales Q Meter(MWh) 28]2M 259852 ...— 24]416 290257 —'Rel 481561 54.S69 302202 2]035] 254M9 288]43
6 ID NPC Corrected in Rates($) Line 4 x Llne5 $ ],049,281 $ 6.376,599$ 6,619,675 $ 6,0]1,43] $ 7,122.723 $ 10,4MO]] $ 11,817.187 $ 4351,$42 $ ],41),815 $ 6,830,698 $ 6,244,020 $ 7,085.579 $ 91.470,434
]T-Compan st y Adjued—I NPC(E) Adjusted A..I NPC$ 329.560,593$ 191MSS.86$172,103.503 $ 156,372.981 $ 161MSS, ,95$ 198,290.576 $ 315.39T.—$284,5315 $ 251,346.919 $ 169,154221 $ 180.319,087$ 188.161,6]6 $2.598,5]0,911
B Total Company Load®Input(MM) 548423] 48]4820 6913]]1 64]92]] 4]04402 5352119 fi103fiW 5600340 69118]8 6]69]06 4953682 5411620 D1.6..50
9 A_1 NPC($)MWh) Line 71 Lin08 $ 60.09 $ 39.32 $ 35.02 $ 34.91 $ 34.3]$ 3].05 $ 51.6]$ 50.09 $ 51.1] $ 35.41 $ 31.40 $ 34.]] $ 42.16
101D Actual Lo.d@Input(MWh) 288551 267— 280461 261930 33553] 461136 464860 .1919 300142 2B3400 261739 W0067
11 A—I ID NPC Line 9 x LIn010 $ 11.33.—$ 10.508,913$ 9,823,088 $ 9.1MM7 $ 11.530,855$ 17,084606 $ 24.031,121 $ 1],126.938 $ 15,358.660 $ 10,055401 $ 9,52],56]$ 10A33,309 $ 161.952,209
12 NPC DIgerential Line 11-LIne6 $ 10.290A24$ 4.132,314$ 3,203A13 $ 3,072,610 $ 4.48,132$ SIM16,520 $ 12,203,934$ 8,769,506 $ ],049,9M$ 3=,703 $ 3.283,540$ 3,34],]30 $ 70,481,—
ERF—Adjustment
13 Meho Allocated EITF 04 D Deferral Adustment($) $ (4,692)It 21,938 It (fi2,849)$ (99,O6T)$ (162,684)It (114,522)$ (61,321)It (63,269)$ (66.1.)$ 60,070 $ (SS,328)It fi0,I29 $ (SM,980)
LCAR
14 Actual Mah"—d1c110naI ECPC minus NPC(A--APAC-E-21-0] $ 2,56&242$ 2,568,242$ 2,568,— $ 2,568,242 $ 2,568,242$ 2,568,242 $ 2,56&242$ 2,W,242 $ 2,568,242 $ 2,568,242 $ 2,56&242$ 2,56&242 $ 30,818,9oe
15 LCAR Rate Q Me.,($NWh) PAC-E-21-0] $ 8.74 $ 8.74 $ 8.74 $ 8.74 $ 8.74 $ 8.74 $ 8.74 $ 8.74 $ 8.74 $ 8.74 $ 8.74 $ 8.74
i61D Actual S.Ie.@ Mete,(MWh) LineS 28]2M 259852 269]58 2A]41fi 29025] 426991 481.1 .0,16. 302282 2]035] 2S4.— 288]43
17 1-0-Revenue Cdlected through Base Rates($) Line 15 x Line 16 $ 2.510,571 $ 2.210,990$ 2,35],568 $ 2,162,316 $ 2.536,]27$ 3,]31J21 $ 4.208,64o$ 2,976,431 $ 2,641.823 $ 2,432,]23 $ 2,223.781 $ 2.523,498 $ 32,576,797
18 LCARAdjustment Line 14-Line 17 $ 5],BTt S 297,2M$ 210,674$ 401,926 $ 31,518$ (1,163A70)$ (1,BM,397)$ (408,189)$ (/3,580)$ 131,119 $ 3"462$ 44,7" $ (1,]5),888)
ECAM Deferral
19 Total ECAM D—I(NPC Deferral,EITF 04£AGustma bum of unea.le' 10343403 445169] 3351]38 33]94]0 42]6963 532052] 10502216 8290138 ]00108fi 3410293 35]2680 345289] fi81]690]
20T—I ECAM Deferral-90%Sharing Line 19.W% E 0309083 E 0.00834T E 30185M$
SM1523 E 38M 28T E /]956]5$
DM19M E T468324$ T0200]] $
30]BAM E 3215412 S 310]60T $ 81359217
Production Tax Credits(PTCa)
21 ID Pllocetetl PTCS In Rates($IMWh) PAGE-21-0] E (4.16)E (4.16)E (4.16)$ (4.16)$ (4.16)E (4.16)$ (4.16)E (4.16)$ (4.16)$ (4.16)$ (4.16)E (4.16)
221D Actual$ales Q 10—(MWh) Linn 287,264 259,852 289,]58 247,416 290,25] 426.991 481,561 340,569 302,282 2]8,35] 254,M9 288,143
231D PTCa in Rates($) Lin.21 xLin.22 $ (1,196,1M)$ (1,082,003)$ (1,123,249)$ (1,030,222)$ (1,208,We)$ (1,T]],955)$ (2,005,1B0)E (1,410,102)$ (1,250,600)$ (1,159,OSfi)$ (1,059,506)E (1,202,305)
241DA lnc. 1Actual PTCS($) (13241851 (13408151 (13596551 (1389099) (14204.) (1362]]11 (]8542]1 (95]30]) (8493001 (101]2]51 (1394698) (1956352)
25 ID PTCS Deferral($) Line 24-Line 23 S (128,000)S (238,612)$ (—.4.. $ (358,8TT)$ (211,852)It 415,184$ 1,219,753 $ 160,715 $ t09,379 $ 141,781 $ (335,192)$ (]5404T) $ 363,186
Situ.Assigned REP OF Mp.tment
261 D REP OF Adjustment($) E 0g105 E 03,958 E 111,888 $ 99,515 $ 1M,352 E 200,230 $ 1401845 E 83,010 $ 100,223 $ I.J.$ 1331808 E 1031050 $ 1,512,M
Wind Liquidated Damages
27 ID Alloceted Wind Liquitleted Damages($) $ - $ - $ - $ - $ - $ (12,620)$ - $ (51.231)$ - $ - $ - $ (36,186) $ (100,OM)
Renewable Energy Credits(REC)Revenue
28 ID REC Revenue In Rates($IMWh) PAC-E-21- E (0.0])$ (0.0])$ (0,0])$ (0.0])$ (0.07
)$ (O.o])$ (0.0])$ (O.o])$ (0.0])$ (0.0])$ (0.0])$ (0.0])
291D Actual Seles�Mete,(MWh) LineS 28]264 259552 269]58 2A]416 29025] 626991 481561 340569 302282 2]035] 254M9 288]43
301D REC Revenue In Rates($) Line 28.U.29 $ (19.663)$ (17,787)$ (18.M5)$ (16.9.)$ (19,868)$ (mm)$ (32,963)$ (23,312)$ (20,691)$ (19,054)$ (17,417)$ (19,765)
31 ID NIDcated A..I REC Revenue($) (15]0017 (243837 (158888) (10 fr14) (36]2) (4149) (34902) (10311) (69453) (78123) (2280391 (47194)
32 REC Revenue Atlju—nt($) Line 31-Line XI (13],338)$ (228,040)$ (14DA31)$ 6,092 $ 1.11.$ 25,DT9 $ (1,939)It iJ,001 $ (M,161)$ (59,069)$ (210,622)$ (27,430) $ (791,134)
33 Total Deferral Sum of Linea 20,25,:It 9141T90 it 3615fM2 It 2751815 $ 2708193 $ 3196S63 It 54295411 $ 10810653 It 7973828 $ 7481818 $ 3309899 $ 2803406 It 2A52.995 $ 62344550
341nterest Rete Ober No.36— 5.00% 5.00% 5.00% 5.00% 5Do% 5.00% 'Do% 5.00% 5.00% 5.00% 5.00% 5.00%
ECAM Balancing Account($)
35 Beginning Balance $ 73,082.282$ 80.2]8,269$ 81,]89,992 $ 82,523,120 $ 83.2M,8]8$ 85,054,582 $ 86,682,690$ 89,356,540 $ et 292,4]8 $ W,489,091 $ 92,313,396 E 90,698,560
36 ECAM Deferral ARer Sh.dng Lin.20 9,309,063 4,006,34] 3,016,Sfi4 3,041,523 3,849,267 4,795,675 9,451,996 ],4SS324 7,020,9]] 3,0]6A64 3,215,412 3,10],60]
37
Me Deferral Line 25 (128,040) (250.612) (236,406) (3568]]) (211,852) 415,184 1,219,]53 460,]15 141,]01 (335,192) (]54.04])
38 REPShus Adjustment Lin.26 98,105 93,958 111,008 99515 143,352 200,239 140,845 53,019 100,223 iM,]20 133,8oa 1fi3,050
38 Wind Liquidated Dam ages Line 27 - - - - - (12,628) - (51,231) - - - (36,186)
60 REC Revenue Atljuslmen[ Line 32 (137,338) (226,050) (140,231) S.. 16,197 25,0]9 (1,939) 13,001 (48,]61) (59,W9) (210,622) (2]A30)
41 Less:Monthly ECAMRidt1 Revenues allocated to ECAM (2,264.640) (2,480,111, (2,340,253) (2,3]1,150) (2,3]].23]) (4,152,412) (8503.18]) (8,412,450) (5,659,30]) (4,8]6900) (4800.]20) (4902,211)
421nterest 31883] 33fi 899 34156fi 344]15 3499]8 35]M2 3fi59M 3]5568 304102 306305 3804]8 3]2800
43 Total ECAM Deferral Baiance($I $ 110278260$ 111769992$ 82523120 $ 832M878 $ BSOM582$ 86882600 $ 803555M$ 91282A18 $ $3499091 $ $2313396 $ 006911560$ 88620076 $ 118620076

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION ) CASE NO. PAC-E-25-04
OF ROCKY MOUNTAIN POWER )
REQUESTING APPROVAL OF $66 . 7 ) DIRECT TESTIMONY OF
MILLION ECAM DEFERRAL ) ROBERT M. MEREDITH
ROCKY MOUNTAIN POWER
CASE NO. PAC-E-25-04
March 2025

1 Q. Please state your name, business address and present
2 position with PacifiCorp, dba Rocky Mountain Power ("the
3 Company") .
4 A. My name is Robert M. Meredith. My business address is
5 825 NE Multnomah Street, Suite 2000, Portland, Oregon
6 97232 . My present position is Director, Regulation.
7 I . QUALIFICATIONS
8 Q. Briefly describe your educational and professional
9 background.
10 A. I graduated from Oregon State University with a Bachelor
11 of Science degree in Business Administration and a minor
12 in Economics . In addition to my formal education, I have
13 attended various industry-related seminars . I have
14 worked for the Company for 20 years in various roles of
15 increasing responsibility in the Customer Service,
16 Regulation, and Integrated Resource Planning
17 departments . I have over 14 years of experience
18 preparing cost of service and pricing related analyses
19 for all of the six states that PacifiCorp serves . In
20 March 2016, I became Manager, Pricing and Cost of
21 Service . In March 2025, I assumed my current position.
22 Q. Have you testified in previous regulatory proceedings?
23 A. Yes . I have previously filed testimony on behalf of the
24 Company in regulatory proceedings in Idaho, Utah,
25 Wyoming, Oregon, Washington, and California.
Meredith, Di 1
Rocky Mountain Power

1 Q. What is the purpose of your testimony in this proceeding?
2 A. My testimony presents and supports the Company' s
3 proposed rates to recover the 2024 Energy Cost
4 Adjustment Mechanism ("ECAM") deferral balances through
5 Electric Service Schedule No. 94, Energy Cost Adjustment
6 ("Schedule 94") .
7 II . BACKGROUND
8 Q. What level of revenue is Schedule 94 currently designed
9 to collect?
10 A. Schedule 94 is currently designed to collect
11 approximately $30 . 5 million—$11 . 4 million for the
12 Electric Service Schedule No . 400 ("Schedule 400")
13 customer and $19 . 1 million for standard tariff
14 customers—based on Idaho loads from Case No. PAC-E-24-
15 04 .
16 III . PROPOSED RATE CHANGE FOR SCHEDULE 94
17 Q. Please describe the Company' s proposed rate change in
18 this case.
19 A. The 2024 ECAM application proposes to increase Schedule
20 94 rates to recover approximately $76 . 8 million from
21 June 1, 2025 to May 31, 2027 ($38 . 4 million on an annual-
22 basis) . The $76 . 8 million includes $66 . 7 million for the
23 2024 ECAM Deferral, approximately $22 . 0 million
24 remaining from the 2023 ECAM balance, for a total balance
25 of $88 . 6 million as of December 31, 2024, offset by $15 . 4
Meredith, Di 2
Rocky Mountain Power

1 million Schedule 94 forecasted revenue collection and
2 interest charge from January 1, 2025 through May 31,
3 2025, and the estimated interest charge of $3 . 6 million
4 from June 1, 2025 through May 31, 2027 as shown in Table
5 2 of Company witness Jack Painter' s testimony. Mr.
6 Painter explains in his testimony the components of the
7 2024 SCAM deferred balance .
8 Q. What is the impact of the proposed ECAM rates?
9 A. As summarized in my Exhibit No . 2, these rate change
10 proposals result in an increase of 2 . 9 percent for
11 Schedule 400 . Standard tariff customers will see an
12 average increase of 1 . 9 percent .
13 IV. RENEWABLE ENERGY CREDIT ("REC") REVENUE TREATMENT FOR
14 SCHEDULE 400
15 Q. Did the Company make any adjustments to the Schedule 94
16 ECAM price for Schedule 400?
17 A. Yes . Consistent with the 2023 SCAM, the Company created
18 a different ECAM rate for Schedule 400 to exclude the
19 REC revenues in the ECAM from Schedule 400' s rates .
20 Q. Why are REC revenues excluded from Schedule 400 rates?
21 A. On March 29, 2021, PacifiCorp filed an application
22 requesting Commission approval of an agreement entered
23 into with the sole Schedule 400 customer under which the
24 Company will retire, rather than sell, this customer' s
25 allocated share of RECs generated post-2020 from system
Meredith, Di 3
Rocky Mountain Power

1 resources . ' The Company discontinued sale of Idaho-
2 allocated system RECs associated with the Schedule 400
3 load in 2021, so that the Schedule 400 customer' s
4 allocated share of system RECs could be retired on its
5 behalf. The REC revenue that Schedule 400 would
6 otherwise have been allocated from the sale of post-2020
7 system RECs is removed from Schedule 400' s base rates .
8 Schedule 400 will continue to receive REC revenue from
9 the sale of any RECs generated prior to 2021 .
10 On August 11, 2021, Commission Order No . 35131
11 approved this agreement. Based on the terms of the
12 agreement, the Company withheld the Schedule 400
13 customer' s share of 2021 RECs from any auctions or sales .
14 Beginning on January 1, 2021, the Schedule 400 customer
15 will no longer receive a REC revenue credit for RECs
16 generated after December 31, 2020 . If the Company was
17 able to sell RECs generated prior to 2021, Schedule 400
18 will receive credit for its share of those REC revenues .
19 Q. How did you calculate the Schedule 400 ECAM rate?
20 A. To calculate the Schedule 400 ECAM rate, the Company
21 removed REC revenue credits in the ECAM from the
22 transmission voltage rate .
' 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.
Meredith, Di 4
Rocky Mountain Power

1 Q. Did you remove all of the REC revenue credits in Schedule
2 400 rates through the ECAM?
3 A. No . The ECAM only tracks the incremental difference
4 between actual REC revenues received during the deferral
5 period and the REC revenue credit in base rates . The
6 base rates were established in Case No. PAC-E-21-07 with
7 a REC revenue credit of 7 cents per megawatt hour. Base
8 REC sales were removed from Schedule 400' s base rates to
9 reflect Schedule 400' s agreement with the Company to
10 retire its share of RECs on its behalf.
11 V. CALCULATION OF PROPOSED RATES FOR SCHEDULE 94
12 Q. How were the proposed Schedule 94 rates developed for
13 all customers?
14 A. The proposed rates for all customers were developed in
15 five steps . First, kilowatt-hour ("kWh") consumption at
16 the generation level was developed by multiplying their
17 retail loads at the delivery service voltage level with
18 the corresponding line loss factors . Second, an overall
19 average rate at the generation level was developed by
20 dividing the total collection target identified above
21 with their kWh consumption at the generation level .
22 Third, rates by delivery voltage level were developed by
23 multiplying the above overall average rate at the
24 generation level with the corresponding line loss
25 factors . Fourth, the rate for Schedule 400 was increased
Meredith, Di 5
Rocky Mountain Power

1 by 0 . 011 cents per kWh to account for the $0 . 4 million
2 adjustment to REC revenue included in the 2024 ECAM,
3 which Contract Tariff 400 had elected to forego per the
4 terms of the REC agreement. This results in a proposed
5 annual $14 . 4 million ECAM recovery from the Schedule 400
6 customer. Finally, the overall proposed annual collection
7 of $38 . 4 million was reduced by the $14 . 4 million share
8 for Schedule 400, and rates for standard tariff customers
9 were developed to collect the remaining annual $23 . 4
10 million using similar logic to that described in the
11 third step. As a result, the Company proposes Schedule
12 94 rates for standard tariff customers of 1 . 137, 1 . 116
13 and 1 . 079 cents per kWh for secondary, primary and
14 transmission delivery service voltages, respectively.
15 The rate for Schedule 400 is 1 . 096 cents per kWh.
16 Q. Please describe Exhibit No. 2 .
17 A. Exhibit No . 2 shows the 2023 loads used to develop rates,
18 the line loss adjusted loads, the allocation of the ECAM
19 price change, and the percentage change by rate schedule.
20 Q. Please describe Exhibit No. 3 .
21 A. Exhibit No . 3 contains clean and legislative copies of
22 the proposed Electric Service Schedule No. 94, Energy
23 Cost Adjustment. The Company requests that the proposed
24 Schedule 94 rates become effective on June 1, 2025 .
Meredith, Di 6
Rocky Mountain Power

1 Q. Does this conclude your direct testimony?
2 A. Yes .
Meredith, Di 7
Rocky Mountain Power

Case No. PAC-E-25-04
Exhibit No. 2
Witness : Robert M. Meredith
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Robert M. Meredith
March 2025

Rocky Mountain Power
Exhibit No.2 Page 1 of 1
Case No. PAC-E-25-04
Witness: Robert M.Meredith
EXHIBIT NO.2
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 ECAM Proposal Present
Line Average Base MWh by Voltage Generation Rev Rate¢/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 $7,044 1.137 1.116 1.079 $5,608 $1,436 1.7%
2 Residential Optional TOD 36 10,176 172,088 $19,704 172,088 187,681 $1,956 1.137 1.116 1.079 $1,557 $399 1.9%
3 AGA Revenue $1
4 Total Residential 71,933 791,748 $99,532 791,748 0 0 863,488 $9,001 $7,165 $1,835 1.7%
5 Commercial&Industrial
6 General Service-Large Power 6 1,120 305,548 $28,816 279,600 25,948 332,720 $3,468 1.137 1.116 1.079 $2,761 $707 2.2%
7 General Svc.-Lg.Power(R&F) 6A 186 22,162 $2,242 22,103 59 24,169 $252 1.137 1.116 1.079 $201 $51 2.1%
8 Subtotal-Schedule 6 1,306 327,711 $31,058 301,703 26,007 0 356,890 $3,720 $2,961 $759 2.2%
9 General Service-High Voltage 9 17 221,839 $15,539 0 0 222,699 230,500 $2,403 1.137 1.116 1.079 $1,913 $490 2.8%
10 Irrigation 10 5,726 551,496 $59,052 551,496 601,467 $6,269 1.137 1.116 1.079 $4,991 $1,278 2.0%
11 General Service 23 8,666 217,574 $23,810 182,662 353 0 199,592 $2,080 1.137 1.116 1.079 $1,656 $424 1.7%
12 General Service(R&F) 23A 2,565 42,247 $4,797 42,246 1 46,075 $480 1.137 1.116 1.079 $382 $98 1.9%
13 Subtotal-Schedule 23 11,230 259,822 28,608 224,909 354 0 245,667 Z561 2,039 522 1.7%
14 General Service Optional TOD 35 3 323 $33 323 352 $4 1.137 1.116 1.079 $3 $1 2.1%
15 General Service Optional TOD(R&F) 35A 1 56 $9 56 61 $1 1.137 1.116 1.079 $1 $0
16 Subtotal-Schedule 35 4 379 42 379 0 0 413 4 1.137 1.116 1.079 3 1 1.9%
17 Special Contract 400 1 1,314,200 $91,220 1,314,200 1,360,236 $14,412 1.096 $11,394 $3,018 2.9%
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 $29,370 $23,301 $6,068 2.4%
20 Public Street Lighting
21 Security Area Lighting 7 174 230 $46 230 251 $3 1.137 1.116 1.079 $2 $1 1.1%
22 Security Area Lighting(R&F) 7A 119 93 $22 93 102 $1 1.137 1.116 1.079 $1 $0 0.9%
23 Street Lighting-Company 11 61 182 $81 182 198 $2 1.137 1.116 1.079 $2 $0 0.5%
24 Street Lighting-Customer 12 266 2,360 $356 2,360 2,574 $27 1.137 1.116 1.079 $21 $5 1.4%
25 AGA Revenue $0
26 Total Public Street Lighting 620 2,866 $506 2,866 0 0 3,125 $33 $26 $7 1.2%
27 Total Sales to Ultimate Customers 90,837 3,470,059 $326,076 1,873,100 26,362 1,536,899 3,661,787 $38,403 $30,493 $7,910 2.2%
28 Total Excluding Special Contract 400 90,836 2,155,859 $234,856 1,873,100 26,362 222,699 2,301,550 $2379 00 $19,099 $4,892 1.9%
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): $23,990 1.042 1.137 1.116 1.079 Tariff Customer Rate 1.137 1.116 1.079 0.905 0.888 0.859
31 REC Adjustment and Rate(cents/kWh): ($396) -0.011 -0.012 -0.012 -0.011 Schedule 400 Rate 1.096 0.867
32 Total Idaho ECAM Rate(cents/kWh): $38,403 1.049 1.144 1.123 1.085 REC Adj -$147

Case No. PAC-E-25-04
Exhibit No. 3
Witness : Robert M. Meredith
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Robert M. Meredith
March 2025

Rocky Mountain Power
Exhibit No.3 Page 1 of 2
_ROCKY MOUNTAIN Case PAGE
Witness: Robert M.Meredith
POWER
A DIVISION OF PACIFICORP
Seventeenth Sixteenth Revision of Sheet No. 94.1
LP.U.C.No. 1 Canceling SixteenthFifteent h 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 0.9051.1370 per kWh
Schedule 6 0.9051.1370 per kWh 0.9981.1160 per kWh
Schedule 6A 0.9051.1370 per kWh 0.9881.1160 per kWh
Schedule 7 0.9051.1370 per kWh
Schedule 7A 0.9051.1370 per kWh
Schedule 9 0- 591.079¢per kWh
Schedule 10 0.9051.1370 per kWh
Schedule 11 0.9051.1370 per kWh
Schedule 12 0.9051.1370 per kWh
Schedule 23 0.9051.1370 per kWh 0.8881.1160 per kWh
Schedule 23A 0.9051.1370 per kWh 0.8881.1160 per kWh
Schedule 24 0.9051.1370 per kWh 0.8881.1160 per kWh
Schedule 35 0.9051.1370 per kWh 0.8881.1160 per kWh
Schedule 35A 0.9051.1370 per kWh 0.8881.1160 per kWh
Schedule 36 0.9051.1370 per kWh
Schedule 400 0- 1.096¢per kWh
Submitted Under Case No. PAC-E-254-04
ISSUED: Feb March 2743,2025 EFFECTIVE: Febnd iny-june 1,2025

Rocky Mountain Power
Exhibit No.3 Page 2 of 2
_ Case PAGE
ROCKY MOUNTAIN Witness: Robert M.Meredith
POWER
A DIVISION OF PACIFICORP
Seventeenth Revision of Sheet No. 94.1
I.P.U.C.No. 1 Canceling Sixteenth 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 1.137¢per kWh
Schedule 6 1.137¢per kWh 1.116¢per kWh
Schedule 6A 1.137¢per kWh 1.116¢per kWh
Schedule 7 1.137¢per kWh
Schedule 7A 1.137¢per kWh
Schedule 9 1.0790 per kWh
Schedule 10 1.137¢per kWh
Schedule 11 1.1370 per kWh
Schedule 12 1.1370 per kWh
Schedule 23 1.1370 per kWh 1.1160 per kWh
Schedule 23A 1.137¢per kWh 1.116¢per kWh
Schedule 24 1.137¢per kWh 1.116¢per kWh
Schedule 35 1.137¢per kWh 1.116¢per kWh
Schedule 35A 1.137¢per kWh 1.116¢per kWh
Schedule 36 1.137¢per kWh
Schedule 400 1.096¢per kWh
Submitted Under Case No. PAC-E-25-04
ISSUED: March 27, 2025 EFFECTIVE: June 1,2025