20240401Application_Painter Direct Testimony (REDACTED).pdf

1407 W. North Temple, Suite 330 Salt Lake City, UT 84116

April 1, 2024
VIA ELECTRONIC DELIVERY
Commission Secretary
Idaho Public Utilities Commission
11331 W. Chinden Blvd
Building 8 Suite 201A
Boise, ID 83714
RE: CASE NO. PAC-E-24-05
IN THE MATTER OF THE APPLICATION OF ROCKY MOUNTAIN POWER
REQUESTING APPROVAL OF $62.4 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.
Mr. Painter’s direct testimony and workpapers are confidential and are being sent via an encrypted
file. You will receive a separate email to access these files.
Informal inquiries may be directed to Mark Alder, Idaho Regulatory Manager at [phone].
Very truly yours,
Joelle Steward
Senior Vice President, Regulation and Customer & Community Solutions
RECEIVED
Monday, April 1, 2024 12:48:01 PM
IDAHO PUBLIC
UTILITIES COMMISSION

Application of Rocky Mountain Power Page 1
Joe Dallas (ISB# 10330)
825 NE Multnomah, Suite 2000
Portland, OR 97232
Telephone: [phone]
Email: [e-mail]

Attorney for Rocky Mountain Power

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE APPLICATION
OF ROCKY MOUNTAIN POWER
REQUESTING APPROVAL OF $62.4
MILLION ECAM DEFERRAL
) CASE NO. PAC-E-24-05
)
) APPLICATION OF
) 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 $62.4 million of deferred costs from the deferral
period beginning January 1, 2023, through December 31, 2023, (“Deferral Period”) with a 10.5
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:
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
88,780 customers in the state.

Application of Rocky Mountain Power Page 2
BACKGROUND
2. The ECAM became effective July 1, 2009, pursuant to an agreement among
parties.1 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 3
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,8 and wind availability
liquidated damages.9 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-party. 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 2023-51, the 2023 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 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 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).
8 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).
9 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.
11 IRC section 45(a).
12 IRC section 45(a).

Application of Rocky Mountain Power Page 4
is 2.8 cents per kilowatt hour.13 The 2023 PTC rate for electricity generated from qualifying wind
facilities placed in service after December 31, 2021 is 2.75 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, 2023,
other than Foote Creek II-IV.
14 Also as published in IRS Notice 2023-51, the 2023 PTC rate for electricity generated from qualifying wind
facilities placed in service after December 31, 2021, is .55 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 2.75 cents per kilowatt hour.
Foote Creek II-IV was placed in service after December 31, 2021, and began construction prior to January 29, 2023,
making the applicable 2023 credit rate for this project 2.75 cents per kilowatt hour.
15 Foote Creek II-IV was placed in service during 2023 and is 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 project qualifies 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 5
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 2023 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 $65.9
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 power market prices, coal supply
constraints, and decreased hydro generation from the amounts forecasted from the 2021 Rate Case.
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
Idaho load. The LCAR increased the deferral balance by approximately $268,994 before applying
the sharing band due to higher usage during the Deferral Period.

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 6
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 $60,594 before
applying the sharing band.
13. The total NPC deferral adjusted for LCAR and EITF 04-6 was approximately $66.2
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
$59.6 million.
14. During the Deferral Period the PTC differential, as described in paragraph 7,
increased the deferral approximately $900 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 $357,308 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 $310,085.
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 2.0 percent. Interest of
$1.2 million was added to the ECAM balance.
18. The ECAM balance at the end of the Deferral Period was $75.4 million, including
$62.4 million from the 2023 ECAM deferral (inclusive of interest), plus $13.0 million remaining
balance from prior ECAM filing. The Company estimates the ECAM balance will be reduced by

Application of Rocky Mountain Power Page 7
$10.5 million from Schedule 94 revenue collections accrued from January 1 through May 31, 2024,
resulting in an estimated ECAM balance of $64.9 to be collected.
19. Mr. Meredith’s testimony describes how Schedule 94 rates were designed to
recover the May 31, 2024, estimated ECAM balance of $64.9. Based on this rate design, the
Company proposes Schedule 94 rates of 1.878, 1.844, 1.782, and 1.798 cents per kWh for
secondary, primary, transmission delivery service voltages and Schedule 400, respectively.
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: [e-mail]

Joe Dallas (ISB# 10330)
Senior Attorney
Rocky Mountain Power
825 NE Multnomah, Suite 2000
Portland, OR 97232
Telephone: [phone]
Email: [e-mail]

In addition, Rocky Mountain Power requests that all data requests regarding this
Application be sent in Microsoft Word to the following:
By email (preferred): [e-mail]
By regular mail: Data Request Response Center
PacifiCorp
825 Multnomah, Suite 2000
Portland, Oregon 97232

Informal questions may be directed to Mark Alder, Idaho Regulatory Affairs Manager at
[phone].

Page 8
Included with this Application is a copy of the press release, which will be issued on
April 1, 2024. Additionally, this Application includes a copy of the customer notice, which will be
included with customers’ bills beginning April 3, 2024, and will run for a full billing cycle.
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 $62.4 million ECAM deferral; and (3) approving a 10.5 percent increase to Electric
Service Schedule No. 94, Energy Cost Adjustment effective June 1, 2024.
DATED this 1st day of April 2024.
Respectfully submitted,

ROCKY MOUNTAIN POWER

__________________________
Joe Dallas (ISB# 10330)
825 NE Multnomah, Suite 2000
Portland, OR 97232
Telephone: [phone]
Email: [e-mail]

Attorney for Rocky Mountain Power

CUSTOMER NOTICES
Annual energy cost adjustment
Idaho Public Utilities Commission
www.puc.idaho.gov
11331 W. Chinden Blvd. Building 8,
Suite 201-A
Boise, ID 83714
Rocky Mountain Power offices
Rexburg – 127 East Main
Preston – 509 S. 2nd East
Shelley – 852 E. 1400 North
Montpelier – 24852 U.S. Hwy 89 ©2
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Proposed net price increase
Rocky Mountain Power requests recovery of power costs
On April 1, 2024, Rocky Mountain Power asked the Idaho Public Utilities Commission to approve the incremental
energy related costs for 2023 of $64.9 million, a net increase of $32.6 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, 2024. All customer classes will see a net increase to
their rates due to the increased costs for fuel and wholesale electricity. Extreme weather conditions in 2023 increased
the costs of fuel and purchased power on the wholesale market — two of the main components of the company’s
annual power cost adjustment. Additionally, coal supply restrictions that began in late 2022 continued into 2023 – due
to several factors, including a fire at a major coal mine and higher exports of U.S. coal to Europe – while natural gas
prices soared. These factors caused significant price increases for the resources Rocky Mountain Power must purchase
for power generation to meet demand and balance its system.
Increases in wholesale power prices account for nearly half of the total cost adjustment requested. The proposed
adjustment will allow Rocky Mountain Power to continue to deliver safe, reliable, low-cost power now and for years to
come while navigating a time of volatile energy markets.
A typical residential customer using 783 kilowatt-hours per month would see an increase of approximately $7.39 a
month on their electricity bill. The following is a summary of the percentage impacts by customer class:
• Residential Schedule 1 – 7.6% increase
• Residential Schedule 36 –8.7% increase
• General Service Schedule 6 –10.7% increase
• General Service Schedule 9 –13.1% increase
• Irrigation Service Schedule 10 –9.5% 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-24-05.
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.
• General Service Schedule 23 –9.0% increase
• General Service Schedule 35 –10.3% increase
• Public Street Lighting –5.2% increase
• Tariff Contract 400 –13.5% increase
For more information about your rates and rate schedule, go to
RockyMountainPower.net/Rates.

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 (April 1, 2024) — Rocky Mountain Power’s costs for fuel and wholesale electricity
increased in 2023 because of coal supply disruptions and severe weather, which made purchased power
to serve its customers more expensive. As part of an annual review of these costs, the company
requested an average 10.5% price increase for Idaho customers. A typical residential customer using 783
kilowatt-hours per month would see a 7.6% increase, or $7.39 per month on their electricity bill. The
increase will take effect June 1, 2024, 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 89,163 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.”

The most significant driver in this year’s energy cost adjustment involves coal supply and inventory
restrictions that began in late 2022 and continued into 2023. Historically low coal inventories and
soaring natural gas prices prompted many utilities, including Rocky Mountain Power, to increase coal
purchases for generation and to restock depleted coal inventories. In many coal basins nationally, coal
pricing more than doubled in 2022 and remained high into 2023. This effect on coal pricing was made
worse by the war in Ukraine, when many U.S. mines, including mines in Utah and Colorado, rushed to
take advantage of high coal prices by exporting coal to Europe.

“Due to overall lower coal resource output, the company had to adjust its overall system operations
through increased natural gas power plant output, reduced market sales and increased market
purchases,” said Jack Painter, net power cost specialist for the utility. “In 2023, all of PacifiCorp’s Utah
coal suppliers and one major Wyoming coal supplier made emergency contract declarations that
resulted in significant delivery shortfalls of PacifiCorp’s contracted coal supply. Consequently, the Utah
coal mines experienced a 35% decrease in coal production.”

These challenges included a coal mine fire that occurred at American Consolidated Natural Resources’
Lila Canyon mine in central Utah. The mine had produced more than 25% of Utah’s coal production in
recent years. The mine first stopped production in September 2022 and the owners announced the
permanent closure of the Lila Canyon mine in November 2023 after determining that it was not possible
to safely remediate and operate the mine. In response, the company explored the purchase of
reasonably priced coal from a variety of other sources, as well as using surplus coal reserves held by the
company.

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 – 7.6% increase
Residential Schedule 36 – 8.7% increase
General Service Schedule 6 – 10.7% increase
General Service Schedule 9 – 13.1% increase
Irrigation Service Schedule 10 – 9.5% increase
General Service Schedule 23 – 9.0% increase
General Service Schedule 35 – 10.3% increase
Public Street Lighting – 5.2% increase
Tariff Contract 400 – 13.5% 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-24-05. 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
www.puc.idaho.gov
11331 W. Chinden Blvd. Building 8, Suite 201-A
Boise, ID 83714
Rocky Mountain Power offices
Rexburg – 127 East Main
Preston – 509 S. 2nd East
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

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE APPLICATION
OF ROCKY MOUNTAIN POWER
REQUESTING APPROVAL OF $62.4
MILLION ECAM DEFERRAL
) CASE NO. PAC-E-24-05
)
) DIRECT TESTIMONY OF
) JACK PAINTER
) REDACTED

ROCKY MOUNTAIN POWER

CASE NO. PAC-E-24-05

April 2024

Painter, Di-1
Rocky Mountain Power
Q. Please state your name, business address, and present position with PacifiCorp 1
d/b/a Rocky Mountain Power (“Rocky Mountain Power” or the “Company”). 2
A. My name is Jack Painter and my business address is 825 NE Multnomah Street, Suite 3
600, Portland, Oregon 97232. My title is Net Power Cost Specialist. 4
QUALIFICATIONS 5
Q. Please describe your education and professional experience. 6
A. I received a Bachelor of Arts degree in Business Administration with a Finance major 7
from Washington State University in 2007. I have been employed by PacifiCorp since 8
2008 and have held positions in the regulation and jurisdictional loads departments. I 9
joined the regulatory net power costs group in 2019 and assumed my current role as a 10
Net Power Cost Specialist in 2020. 11
Q. Have you testified in previous regulatory proceedings? 12
A. Yes. I have previously provided testimony to the public utility commissions in Idaho, 13
Utah, Wyoming, Oregon, Washington, and California. 14
PURPOSE OF TESTIMONY 15
Q. What is the purpose of your testimony in this proceeding? 16
A. My testimony presents and supports the Company’s calculation of the Energy Cost 17
Adjustment Mechanism (“ECAM”) balancing account for the 12-month period of 18
January 1, 2023 through December 31, 2023 (“Deferral Period”). More specifically, I 19
provide the following: 20
• A summary of the ECAM calculation, including changes made to comply with 21
Idaho Public Utility Commission (“Commission”) orders; 22
• Details supporting the addition of approximately $62.4 million to the deferral 23

Painter, Di-2
Rocky Mountain Power
balance, including $59.6 million customers’ share of ECAM costs, a $900 1
thousand decrease in renewable energy production tax credits (“PTCs”), $1.5 2
million in reasonable energy price (“REP”) qualified facility (“QF”) costs, a 3
credit of $310 thousand for wind availability liquidated damages, a $357 4
thousand renewable energy credit (“REC”) revenue differential, and $1.2 5
million interest accrued; 6
• Discussion of the main differences between adjusted actual net power costs 7
(“Actual NPC”) and net power costs in rates (“Base NPC”); and 8
• Discussion about the Company’s participation in the Western Energy Imbalance 9
Market (“WEIM”) with the California Independent System Operator 10
(“CAISO”) and the benefits from the WEIM that are passed through to 11
customers. 12
Q. What other witnesses present testimony for the ECAM and Tariff Schedule 94 in 13
this case? 14
A. Mr. Robert M. Meredith, Director, Pricing & Tariff Policy, provides testimony on the 15
proposed rates in Electric Service Schedule No. 94, Energy Cost Adjustment 16
(“Schedule 94”). 17
SUMMARY OF THE ECAM DEFERRAL CALCULATION 18
Q. Please briefly describe the Company’s ECAM authorized by the Commission. 19
A. The ECAM tracks deviations between Actual NPC and Base NPC. When there is a 20
difference between these two amounts, 90 percent of the difference is deferred for later 21
recovery or return to customers.1 In addition to tracking the difference between Actual 22

1 See Order No. 30904 in Case No. PAC-E-08-08 and Order No. 33440 in Case No. PAC-E-15-09.

Painter, Di-3
Rocky Mountain Power
and Base NPC, the ECAM also tracks other items including PTCs, the Reasonable 1
Energy Price QF adjustment, wind availability liquidated damages, and revenues from 2
the sale of RECs.2 The purpose for tracking these items is to true-up base rates to 3
actuals. The balance that accumulates over a deferral period is then passed on to 4
customers as a rate surcharge or credit. Schedule 94, described in Mr. Meredith’s 5
testimony, appears as a separate line item on customers’ bills and either collects from 6
or credits to customers the balance of deferred costs. Schedule 94 is adjusted as needed 7
in the Company’s annual ECAM filings. 8
The Company is required to file an application with the Commission annually 9
by April 1st to request approval of the deferral amount and the new Schedule 94 rates 10
to become effective June 1. 11
Q. Are there any changes to the ECAM calculation? 12
A. No. The rates for Base NPC, PTCs, RECs, and the Load Change Adjustment Revenue 13
(“LCAR”) were established in the Company’s last general rate case (“GRC”) Case No. 14
PAC-E-21-07, which became effective January 1, 2022 and are the same rates used in 15
the previous ECAM Case No. PAC-E-23-09.3 Changes in the previous ECAM included 16
the removal of wind integration costs for third party wind because PacifiCorp’s Open 17
Access Transmission Tariff (“OATT”) Schedule 3 and 3A rates include intra-hour wind 18
integration costs and offset Base rates in FERC Account 456, liquidated damages for 19
wind availability were included and are passed to customers outside of the sharing 20

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).
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
band, and both the Resource Tracking Mechanism (“RTM”) and the Lake Side 2 1
Resource Adder were eliminated as part of the Company’s last GRC. 2
ECAM DEFERRAL CALCULATION 3
Q. Please describe the calculation of the ECAM deferral included in this filing. 4
A. Table 1 summarizes the total ECAM deferral and provides a breakdown of the 5
individual components of the ECAM. For a detailed monthly calculation of the ECAM 6
deferral, please refer to Exhibit No. 1. 7
Table 1 – 2023 ECAM Deferral 8

The first section of Table 1 summarizes the Idaho-allocated share of those items 9
for which Idaho customers and the Company share responsibility, including: NPC 10
differential, Emerging Issues Task Force (“EITF”) 04-6 adjustment, and the LCAR 11
costs. The second section calculates the 90 percent customers’ share of these items. 12
Finally, the last section adds the following items that are either refunded or collected in 13
full (i.e., 100 percent): PTCs, REP QF costs, wind availability liquidated damages, REC 14
Calendar Year 2023 ECAM Deferral
NPC Differential 65,874,728$
EITF 04-6 Adjustment 60,594
LCAR 268,994
Total Deferral Before Sharing 66,204,316$
Sharing Band 90%
Customer Reponsibility 59,583,884$
Production Tax Credits 907,177$
REP QF Adjustment 1,450,130
Wind Liquidated Damages (310,085)
REC Deferral (357,308)
Interest on Deferral 1,157,387
Annual Deferral (Jan - Dec 2023)62,431,185$

Painter, Di-5
Rocky Mountain Power
revenues, and interest on the deferral. The total of these items represents the ECAM 1
deferral. 2
Q. Based on your calculations, what is the balance expected to be in the ECAM 3
deferral account as of June 1, 2024? 4
A. Table 2 provides a summary of the ECAM balancing account activity starting with the 5
December 31, 2022, ECAM deferral balance of $41.9 million approved in Case No. 6
PAC-E-23-09. By June 1, 2024, the projected balance in the ECAM deferral account 7
will be approximately $64.9 million. During the Deferral Period, approximately $62.4 8
million is added to the balance from the annual deferral and interest, which is offset by 9
$29.0 million of ECAM revenue collections through the Deferral Period, and an 10
estimated collection of $10.5 million of Schedule 94 revenues, net of interest, between 11
January and May of 2024. 12
Table 2 - Balancing Account Activity 13

Q. Please describe the ECAM calculations in Exhibit No. 1. 14
A. The ECAM deferral is calculated monthly by comparing Idaho-allocated Actual NPC 15
to the Base NPC collected in rates, and then deferring the differences into an ECAM 16
balancing account. Exhibit No. 1 includes details of the ECAM calculation. 17
Additionally, I have also provided confidential work papers supporting this exhibit. 18
ECAM Deferral Balance
Deferral Balance - Dec 31, 2022 41,941,478$
Annual Deferral (Jan - Dec 2023)61,273,798
Interest 1,157,387
ECAM Revenue Collection - Schedule 94 (28,953,155)
December 31, 2023 Balance For Collection 75,419,507$
Schedule 94 Collection - Jan - May 2024 (11,971,685)$
Interest 1,459,118
Expected Balance as of June 1, 2024 64,906,940$

Painter, Di-6
Rocky Mountain Power
Q. How are the Base NPC and Actual NPC calculated? 1
A. Exhibit No. 1 provides details of the ECAM calculation. The monthly Base NPC 2
collected in rates, as set forth in Exhibit No. 1 line 6, is calculated by taking the dollar-3
per-megawatt-hour Base NPC rate multiplied by the actual Idaho retail sales. The 4
Actual Idaho NPC, as set forth in Exhibit No. 1 line 11, is calculated by dividing the 5
monthly total Company Actual NPC in the Deferral Period by the actual monthly 6
system megawatt-hours (“MWh”) in the Deferral Period. To calculate Actual Idaho 7
NPC, the total Company Actual NPC dollar-per-megawatt-hour basis is then multiplied 8
by Idaho actual monthly MWh. 9
Q. Please describe how the NPC deferral is calculated. 10
A. The deferral is calculated monthly by subtracting the Base NPC collected in rates from 11
the Actual Idaho NPC. For the Deferral Period, the NPC differential was $65.9 million 12
before applying the 90/10 percent sharing band. 13
Q. What costs are included in the NPC differential for deferral? 14
A. The NPC differential for deferral captures all components of NPC as defined in the 15
Company’s general rate case proceedings and modeled by the Company’s production 16
dispatch model, the Generation and Regulation Initiative Decision Tool (“GRID”). 17
Specifically, Base NPC and Actual NPC include amounts booked to the following 18
Federal Energy Regulatory Commission (“FERC”) accounts: 19
Account 447 – Sales for resale; excluding on-system wholesale sales and other 20
revenues that are not modeled in GRID 21
Account 501 – Fuel, steam generation; excluding fuel handling, start-up fuel 22
(gas and diesel fuel, residual disposal), and other costs that are 23

Painter, Di-7
Rocky Mountain Power
not modeled in GRID 1
Account 503 – Steam from other sources 2
Account 547 – Fuel, other generation 3
Account 555 – Purchased power; excluding the Bonneville Power 4
Administration (“BPA”) residential exchange credit pass-5
through if applicable 6
Account 565 – Transmission of electricity by others 7
Q. Are adjustments made to the Actual NPC before comparing them to Base NPC? 8
A. Yes. The Company adjusts Actual NPC to reflect the ratemaking treatment of several 9
items, including: 10
• out of period accounting entries booked in the Deferral Period that relate to 11
operations before implementation of the ECAM on July 1, 2009; 12
• buy-through of economic curtailment by interruptible industrial customers; 13
• revenue from a contract related to the Leaning Juniper wind resource; 14
• costs for situs-assigned resources/programs in Oregon and Utah; 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
• wind availability liquidated damages; and 18
• reasonable energy price adjustments to QFs. 19
Q. Why is the July 1, 2009, cutoff used to determine out of period entries? 20
A. Since the ECAM took effect, customers’ rates have been adjusted to recover essentially 21
all of the Company’s actual net power costs, excluding any differences due to the 90/10 22
percent sharing band. Consequently, any accounting entries made during the current 23

Painter, Di-8
Rocky Mountain Power
Deferral Period that relate to any operating period since the ECAM took effect should 1
be reflected in customer rates, whether they increase or decrease Actual NPC. However, 2
accounting entries related to operating periods before the inception of the ECAM 3
should not impact the ECAM deferral. 4
Q. In addition to comparing Actual NPC to Base NPC, what other components are 5
included in the ECAM? 6
A. The ECAM calculation includes six additional components: (i) an adjustment for 7
deferred costs associated with coal mine stripping activities recorded under the 8
Financial Accounting Standards Board (“FASB”) EITF 04-6; (ii) the LCAR 9
adjustment; (iii) a true-up of PTCs; (iv) Idaho allocated REP QF costs; (v) wind 10
availability liquidated damages; and (vi) a true-up of REC revenues as authorized in 11
Order No. 32196. 12
Q. How is the adjustment for accounting pronouncement EITF 04-6 included in the 13
ECAM? 14
A. Line 13 of Exhibit No. 1 calculates coal stripping costs, reflecting Idaho’s allocated 15
differences between the coal stripping costs incurred by the Company during 16
excavation, as recorded on the Company’s books pursuant to the guidance of the 17
accounting pronouncement EITF 04-6, and the amortization of the coal stripping costs 18
as approved by the Commission in Case No. PAC-E-09-08, Order No. 30987. During 19
the Deferral Period, the total EITF 04-6 coal stripping deferral adjustment results in a 20
$61 thousand increase to the ECAM deferral balance, before the application of the 21
90/10 percent sharing band. 22

Painter, Di-9
Rocky Mountain Power
Q. Please describe the LCAR adjustment. 1
A. The calculation of the LCAR adjustment is a symmetrical adjustment for over- or 2
under-collection of the energy-related portion of the Company’s embedded revenue 3
requirement for production facilities, as specified in Case No. GNR-E-10-03, Order 4
No. 32206. This adjustment accounts for variances in Idaho load that cause the 5
Company to collect more or less of these production-related costs. The LCAR rate of 6
$8.74 per MWh is used for the Deferral Period. 7
Q. How is the LCAR adjustment calculated and what impact does it have on the 8
Deferral Period? 9
A. The LCAR adjustment assumes that the actual production-related costs of the LCAR 10
are equivalent to the base amount on Exhibit No. 1 line 14. The actual production-11
related costs are then compared to the LCAR revenue collection in rates, calculated by 12
multiplying the LCAR rate by the actual Idaho retail sales on Exhibit No. 1 line 17. 13
The LCAR adjustment, which is shown on line 18 of Exhibit No. 1, is the difference 14
between the actual production-related costs and the LCAR revenue. This adjustment 15
results in a $300 thousand increase to the ECAM deferral balance before application of 16
the 90/10 percent sharing band. 17
Q. Please explain the sharing band ratio between the Company and customers in the 18
ECAM. 19
A. The ECAM includes a sharing band with a symmetrical sharing ratio in which 20
customers either pay or receive 90 percent of the ECAM deferral balance, and the 21
Company is responsible for the remaining 10 percent. Line 20 of Exhibit No. 1 22
represents the customers’ 90 percent share of the monthly deferral shown on line 19. 23

Painter, Di-10
Rocky Mountain Power
For the Deferral Period, the customers’ share of the deferred balance is $59.6 million. 1
The remaining balance of $6.6 million associated with the Company’s 10 percent share 2
is not included in the deferral balance as it is not recoverable from customers. 3
Q. What is the amount of the PTC true-up in the current filing? 4
A. The PTC Deferral, on line 25 of Exhibit No. 1, is calculated by comparing the actual 5
Idaho-allocated PTC to the PTC credit customers receive through base rates. The PTC 6
credit in base rates is calculated by multiplying the approved PTC rate of $4.16/MWh 7
by Idaho retail sales. The difference results in a $900 thousand increase to the ECAM 8
deferral. 9
Q. Please explain the REP QF Adjustment. 10
A. As set forth in the 2020 Inter-Jurisdictional Allocation Protocol (“2020 Protocol”): “For 11
the Interim Period, the energy output of New QF PPAs will be dynamically allocated 12
per this agreement using the SG Factor, priced at a forecasted reasonable energy price 13
defined below, and any cost of a New QF PPA above the forecasted reasonable energy 14
price will be situs assigned to and allocated to the State of Origin.” 4 The Idaho situs-15
assigned cost, on line 26 of Exhibit No. 1, is $1.5 million. 16
Q. Please explain the wind availability liquidated damages credit? 17
A. Order No. 33954 in Case No. PAC-E-17-06 provides that “the Stipulation requires the 18
Company to pass on to ratepayers all liquidated damages it receives from equipment 19
suppliers in case the repowered equipment does not meet specified availability, 20
performance, or installation schedule requirements.” The Company first removes the 21
wind availability liquidated damages from total-Company NPC and then allocates them 22

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-11
Rocky Mountain Power
to customers using the System Generation (“SG”) allocation factor outside of the 90/10 1
percent sharing band. The wind availability liquidated damages credited to customers 2
in the ECAM is $310 thousand, as shown on line 27 of Exhibit No. 1. 3
Q. What is the amount of REC revenue adjustment in the current filing? 4
A. The REC revenue adjustment shown on line 32 of Exhibit No. 1 is calculated by 5
comparing the actual Idaho-allocated REC revenue with the REC revenue credit 6
customers receive through base rates. The REC revenue credit in base rates is calculated 7
by multiplying the approved REC revenue rate of $0.07/MWh by Idaho retail sales. 8
The resulting difference is a $357 thousand decrease to the ECAM deferral. 9
Q. What is the total ECAM deferred balance calculated in Exhibit No. 1? 10
A. The total ECAM deferred balance as of December 31, 2023, is $61.3 million, shown 11
on line 33 of Exhibit No. 1, plus $1.2 million of interest on line 42, for a total deferral 12
of $62.4 million. 13
Q. Does the calculation of the ECAM deferral in this application comply with the 14
parameters of the Idaho ECAM as approved by the Commission? 15
A. Yes, therefore the Company recommends that the Commission approve the ECAM 16
application for recovery of the $62.4 million in prudently incurred ECAM costs. 17
DIFFERENCES IN NPC 18
Q. Please describe the Base NPC the Company used to calculate the NPC component 19
of the ECAM deferral. 20
A. The total-Company Base NPC of $1.368 billion were set in Case No. PAC-E-21-07 21
(“2021 Rate Case”) using a 12-month test period of January 2021 through 22
December 2021 and became effective January 1, 2022. Based upon a normalized 23

Painter, Di-13
Rocky Mountain Power
Q. On a total-Company basis, what was the difference between Actual NPC and Base 1
NPC for the Deferral Period? 2
A. On a total-Company basis, Actual NPC for the Deferral Period amounted to $2.534 3
billion, exceeding Base NPC for the Deferral Period by $1.166 billion. Table 3 provides 4
a high-level summary of the difference between Base NPC and Actual NPC by category 5
on a total-Company basis. 6
Table 3 - Net Power Cost Reconciliation ($ millions) 7

Q. Please describe the primary differences between Actual NPC and Base NPC. 8
A. From an accounting perspective, and as shown in Table 3, Actual NPC were higher than 9
Base NPC, established in the 2021 Rate Case, due to a $290 million reduction in 10
wholesale sales, a $577 million increase in purchased power expense, a $328 million 11
increase in natural gas expense, and a $14 million increase in wheeling and other 12
expenses. These items were partially offset by a $43 million reduction in coal fuel 13
expense. 14
Q. What are the main drivers of increased NPC in 2023? 15
A. For 2023, two main drivers increased NPC, coal fuel supply constraints and increased 16
TOTAL
Base NPC 1,368$
Increase/(Decrease) to NPC:
Wholesale Sales Revenue 290
Purchased Power Expense 577
Coal Fuel Expense (43)
Natural Gas Expense 328
Wheeling and Other Expense 14
Total Increase/(Decrease)1,166$
Adjusted Actual NPC 2,534$

Painter, Di-14
Rocky Mountain Power
market power and natural gas prices, both of which are discussed with further detail in 1
my testimony below. Coal supply constraints which began at the end of calendar year 2
2022, continued through 2023 and still impact the Company today. Market power 3
prices and natural gas prices have risen sharply since 2021. These drivers have an 4
overarching influence on all components of the Company’s actual system operations 5
through its least cost economic dispatch model. Some of the more significant changes 6
identified in 2023 are reduced wholesale sales volumes, reduced coal generation 7
volumes, and increased gas generation volumes. 8
Q. Please explain the changes in wholesale sales revenue and volumes. 9
A. Wholesale sales volumes declined relative to Base NPC due to an increase in total 10
Company load combined with coal supply constraints and decreases in renewable 11
resource output and hydro generation. When actual market conditions differ from 12
normalized forecast conditions in the power cost production model, the opportunities 13
for the Company to sell excess generation to the market are limited. Additionally, as 14
market power prices and loads increase simultaneously, wholesale sales volumes 15
decrease as the Company serves its load through its own generation. Overall, the above 16
market and system dynamics, decreased wholesale sales revenue by $290 million 17
compared to Base NPC. While the average price of actual market sales transactions 18
was $67.43/MWh, or 56 percent higher than the average price in Base NPC, actual 19
wholesale market volumes were 8,178 gigawatt-hours (“GWh”), or 76 percent, lower 20
than Base NPC. In order to achieve a more accurate level of wholesale sales volumes, 21
the Company will be proposing enhancements to its power cost modeling in the 22
upcoming general rate case. 23

Painter, Di-15
Rocky Mountain Power
Q. Please explain the changes in purchased power expense. 1
A. Overall, actual purchased power expense increased $577 million over Base NPC 2
because the actual average price from market purchase transactions, represented in the 3
power cost production model as short-term firm and system balancing purchases, 4
significantly increased. On a dollar per megawatt-hour basis, actual market purchase 5
transactions increased from $35.77/MWh in Base NPC to $116.40/MWh, or 225 6
percent, but were slightly offset by the lower actual market purchase volume of 146 7
GWh which was two percent lower than Base NPC. 8
The average monthly price of market transactions at the Mid-Columbia and 9
Four Corners market hubs has risen significantly since 2021. Between 2016 and 2020, 10
the average monthly Heavy Load Hour (“HLH”) market price at the Mid-Columbia 11
market hub was $29.27/MWh and $35.11/MWh at the Four Corners market hub while 12
the average monthly HLH market price in 2023 was $85.51/MWh and $81.12/MWh 13
respectively. Table 4 and Figure 2 illustrate these significant market price increases 14
impacting 2023 NPC. 15
Table 4 – Average HLH Mid-Columbia & Four Corners Market Price 16

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

Painter, Di-17
Rocky Mountain Power
generation volume results in a decrease of $43 million in coal fuel expense, but the coal 1
supply limitations impacted all other aspects of the Company’s system operations and 2
net power costs in 2023 as previously explained. 3
Q. Please explain the changes in natural gas fuel expense. 4
A. With a reduction in coal generating resource output in 2023, the Company increased 5
output at its natural gas generating resources. While natural gas prices and the average 6
cost of natural gas generation are higher than Base NPC, the price for operating the 7
Company’s natural gas generating resources was more economic than market power 8
purchases on average. Overall, the total natural gas fuel expense in Actual NPC 9
increased by $328 million compared to Base NPC. This was due to both an increase in 10
the average cost of natural gas generation from $26.95/MWh in Base NPC to 11
$39.61/MWh in the Deferral period and an increase in gas generation volumes of 5,562 12
GWh (66 percent) as shown in Table 6 below. 13
Table 6 – Natural Gas Generation 14

Like the significant increase in the average price of market power purchases discussed 15
above, average natural gas prices have also seen a significant increase during the same 16
timeframe. Table 7 and Figure 3 below illustrate these increases impacting 2023 NPC. 17
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%

Painter, Di-19
Rocky Mountain Power
The estimated impact on total-Company NPC in 2023 due to decreased hydro MWhs 1
caused by drought is $123 million. 2
In the four years preceding the drought (2016-2019), average west hydro 3
resource generation was 3.3 million MWhs while the average west hydro resource 4
generation during the drought (2020-2023) was 2.7 million MWhs, a difference of 600 5
thousand MWhs, on average. Figure 4 below shows the decline over time. 6
Figure 4 – Annual West Hydro Generation (MWHs) 7

Additionally, in December 2022, a historic winter cyclone event occurred 8
across the majority of the United States, which impacted both market prices and natural 9
gas prices, along with an increase in demand. The impacts of this event on both natural 10
gas prices across the Company’s delivery points and market power purchase prices 11
were not only significant and elevated, but also carried over into January 2023. Table 12
9 and Table 10 below show the large variance between average January prices and the 13
remaining average for the year prices between February and December at the Opal and 14
Sumas natural gas hubs and Mid-Columbia and Four Corners market purchase power 15
hubs. 16

 1,500,000
 2,000,000
 2,500,000
 3,000,000
 3,500,000
 4,000,000
 4,500,000
2016 2017 2018 2019 2020 2021 2022 2023

Painter, Di-20
Rocky Mountain Power
Table 9 – Opal and Sumas Average Monthly Price ($/MMBtu) 1

Table 10 – Mid-Columbia and Four Corners Average Monthly Price ($/MWh) 2

COAL SUPPLY CONSTRAINTS 3
Q. Please describe the many challenges the Company faced fueling its coal generating 4
resources in 2023. 5
A. All of Utah’s operating mines and some Wyoming mines experienced significant 6
production difficulties and challenges in 2023 due to geological, logistical, and 7
financial challenges. The most significant challenge was the mine fire that occurred at 8
American Consolidated Natural Resources’ (“ACNR”) Lila Canyon mine. The mine 9
had produced more than 25 percent of Utah’s coal production in recent years and 10
stopped production in September 2022. ACNR announced the permanent closure of the 11
Lila Canyon mine in November 2023 after determining that it was not possible to safely 12
remediate and operate the mine. 13
In 2023, all of PacifiCorp’s Utah coal suppliers and a major Wyoming coal 14
supplier operated under force majeure declarations that resulted in significant delivery 15
shortfalls of PacifiCorp’s contracted coal supply. Consequently, the Utah coal mines 16
experienced a 35 percent decrease in coal production from 10.7 million tons in 2022 to 17
6.9 million tons. Table 11 below highlights recent Utah coal market production data. 18
Month Opal Sumas
Jan $15.85 $13.58
Feb - Dec $3.68 $3.37
Month Mid-C HLH Four-C HLH
Jan $146.06 $152.35
Feb - Dec $80.01 $74.64

Painter, Di-21
Rocky Mountain Power
Table 11 1

Additionally, challenges in the U.S. coal market in 2022 due to historically low 2
coal inventories and soaring natural gas prices led many utilities to increase coal 3
purchases for generation and to restock depleted coal inventories. In many coal basins, 4
coal pricing more than doubled in 2022 and remained high into 2023. This effect on 5
coal pricing was exacerbated by the war in Ukraine, when many U.S. mines, including 6
mines in Utah and Colorado, rushed to take advantage of high coal prices by exporting 7
coal to Europe. 8
Q. What did the Company do to acquire additional coal supply in 2023? 9
A. The Company explored economic coal from possible sources. PacifiCorp contracted 10
with a new supplier in 2023, Gentry Mountain Mining (“Gentry”), for additional coal 11
supply for the Hunter plant. The Gentry coal supply agreements were designed to 12
purchase all known economically-available Utah coal for use at the Utah plants. 13
PacifiCorp continued to cooperate with the Hunter plant’s co-owners to deliver coal 14
from one of the plant co-owner’s mine in Colorado. PacifiCorp even excavated a small 15
amount of coal from the buried coal pile at the Gadsby plant, a converted natural gas 16
plant in Salt Lake City, and delivered the coal to the Hunter plant. PacifiCorp also 17
continued to transport coal from the Rock Garden safety pile to the Huntington plant. 18
Change
2021 2022 2023 2022 v. 2023 %
Bronco Utah Operations, LLC 1,170,988 1,062,707 798,023 (264,684) -25%
Wolverine Fuels, LLC 6,845,083 6,425,241 5,477,050 (948,191) -15%
ACNR Holdings, Inc. 3,470,644 2,281,289 159,240 (2,122,049) -93%
Gentry Mountain Mining, LLC 512,951 599,770 419,592 (180,178) -30%
Alton Coal Development, LLC 434,165 354,265 66,659 (287,606) -81%
12,433,831 10,723,272 6,920,564 (3,802,708) -35%
TONS
Utah Coal Production by Supplier (source MSHA)

Painter, Di-22
Rocky Mountain Power
This activity continued through September 2023 when the Rock Garden inventory was 1
completely depleted. 2
PacifiCorp also procured coal from the North Antelope Rochelle Mine 3
(“NARM”) in Wyoming’s Powder River Basin for the first time for the Jim Bridger 4
plant. Historically, Jim Bridger’s coal has been supplied by the captive Bridger Coal 5
Company mine and Lighthouse Resources’ local Black Butte mine (“Black Butte”). 6
PacifiCorp’s deliveries from Black Butte were 0.88 million tons or less than 7
contracted in 2023. The shortfall occurred due to Black Butte’s 8
Black Butte mine 9
declared force majeure in October 2023 . Early in 2023, once 10
the Black Butte delivery shortfall became apparent, PacifiCorp took steps to mitigate 11
the shortfall. First, dispatch of the Jim Bridger plant was adjusted to account for the 12
shortfall. Second, PacifiCorp contracted for the delivery of NARM coal which also 13
required PacifiCorp to lease railcars. PacifiCorp received 0.33 million tons from 14
NARM in 2023 to partially offset the reduction in Black Butte mine deliveries. 15
Q. How did the Company ensure existing coal suppliers in Utah did not suspend 16
operations during 2023? 17
A. Bronco Utah Operations, LLC (“Bronco”) operates the Emery mine in Utah. PacifiCorp 18
signed a coal supply agreement with Bronco in 2020 which allowed the Company to 19
purchase tons per year for calendar years 2021-20
2024 for coal to the Hunter Plant. Bronco notified PacifiCorp in late 2022 that it was 21
unable to supply coal to the Hunter Plant at the current contract price and needed a 22
commitment longer than the remaining two years of the contract for it to make the 23
REDACTED

Painter, Di-23
Rocky Mountain Power
necessary capital investment for a reliable supply of coal to the Hunter plant. 1
PacifiCorp evaluated the economic effects of this request and determined to adjust the 2
Bronco contract terms to allow Bronco to obtain the necessary financing. 3
To avoid the unfavorable cost impacts to PacifiCorp’s customers resulting from 4
the unexpected loss of Bronco’s coal supply, PacifiCorp amended its contract with 5
Bronco in March 2023 to maintain Bronco as a coal supplier to serve Hunter through 6
December 31, 2025. The contract amendment reduced Bronco’s deliveries to the 7
Hunter Plant as follows: (2023) tons, (2024) tons, and (2025) 8
tons. Despite PacifiCorp’s best efforts to maintain the Emery mine as a 9
reliable coal supplier, Bronco continued to struggle with production and ultimately 10
delivered only 0.51 million tons in 2023, a shortfall of tons from the 11
contractual tons. 12
Q. How have the coal supply limitations impacted the Company’s dispatch of its coal 13
generating resources? 14
A. As a result of the force majeure declarations and resulting coal delivery shortfalls in 15
Utah, the dispatch price of the Hunter and Huntington plants was adjusted to match the 16
coal deliveries and assure system reliability throughout 2023. In other words, the 17
dispatch of these coal resources was adjusted to ensure the Company had sufficient coal 18
to serve load during high-demand periods. Additionally, the dispatch price of the Jim 19
Bridger plant was adjusted for three months in early 2023 due to delivery shortfalls at 20
the Black Butte mine which eventually resulted in a force majeure declaration. 21
Ultimately due to these issues, the Company had to reduce its overall coal generating 22
resource output in 2023 as illustrated in Table 5 above. 23
REDACTED
Painter, Di-24
Rocky Mountain Power
Q.How has the Company amended its coal contracts for future supply? 1
A.In February 2024, PacifiCorp amended the Hunter and Huntington coal supply 2
agreements with Wolverine. The amended coal supply agreement with Wolverine for 3
the Hunter plant’s fuel supply 4
for the Hunter plant. Beginning in , the amendment 5
facilitates additional coal production through renewed operations at the Fossil Rock 6
mine in Emery County, Utah. Deliveries from the Fossil Rock mine will begin in . 7
When fully operational, the Fossil Rock mine will provide tons per year to 8
the Hunter plant. The contract amendment allows the Company to direct this coal to 9
the Huntington plant as needed. 10
COMPLIANCE COSTS 11
Q.Has there been any additional purchase requirements for NPC in 2023 for the 12
Company to operate its system and resources? 13
A. Yes. The Company had to acquire allowances for the Washington Climate Commitment 14
Act (“CCA”), which caps and reduces greenhouse gas emissions in Washington. 15
Additionally, the Ozone Transport Rule (“OTR”), which is the federal plan for 16
interstate transport of the 2015 ozone National Ambient Air Quality Standards was 17
planned to become effective on August 4, 2023. 18
Q.Does the Company have to comply with the Washington CCA to operate its 19
Chehalis natural gas generating plant? 20
A. Yes. The Washington CCA requires the Company to purchase allowances for output at 21
its Chehalis natural gas generating facility. In 2023, the Company made $42 million in 22
purchases, on a total-company basis, to comply with the Washington CCA. These costs 23
REDACTED

Painter, Di-25
Rocky Mountain Power
were necessary to comply with applicable law for the continued operation of Chehalis, 1
for the benefit of Idaho customers, and were prudently incurred by the Company. 2
Q. Do these prudently incurred costs benefit Idaho customers? 3
A. Yes. Idaho customers received the benefit of the generation from the Chehalis natural 4
gas facility which reduced NPC. NPC would have increased by $23.6 million on a total-5
Company basis if the generation from Chehalis were removed. Accordingly, as with 6
other taxes and compliance costs imposed on the Company by state and federal 7
governments, customer rates should reflect the full costs for this generation including 8
the costs to comply with Washington CCA. 9
Q. Please generally describe the Ozone Transport Rule (“OTR”). 10
A. The OTR is the Environmental Protection Agency’s (“EPA”) finalized federal plan for 11
interstate transport of the 2015 ozone National Ambient Air Quality Standards, and had 12
an effective date of August 4, 2023. The plan applied to 23 states, including Utah, and 13
includes requirements to eliminate significant contributions of ozone or ozone 14
precursors (specifically, nitrogen oxides (“NOx”)) to nonattainment or maintenance 15
areas in neighboring states. With respect to fossil fuel-fired electric generating units, 16
the final rule sought to implement an allowance-based trading program where each unit 17
was allocated a portion of the state’s NOx budget during the ozone season (identified 18
in the rule as May 1 – September 30). 19
Q. What is the current status of the OTR? 20
A. On July 27, 2023, the U.S. Tenth Circuit Court of Appeals granted petitioners’, 21
including PacifiCorp, motion to stay the EPA’s final disapproval of Utah’s OTR state 22
implementation plan (“SIP”) on July 27, 2023; and (2) EPA proposed approval of 23

Painter, Di-26
Rocky Mountain Power
Wyoming’s OTR SIP on August 14, 2023. While timelines cannot be predicted 1
precisely, the OTR stay for the state of Utah is still under litigation with the U.S. Tenth 2
Circuit Court of Appeals and is expected to remain in place at least through the 2024 3
ozone season. For Wyoming, the EPA published its final approval of Wyoming’s 4
interstate ozone transport plan in the Federal Register on December 19, 2023. The final 5
approval of Wyoming’s plan removes cross-state ozone transport requirements from 6
electric generating units in the state, including PacifiCorp’s generating units. As a 7
result, Wyoming is not subject to the OTR federal implementation plan. 8
Q. Did the OTR impact NPC in 2023? 9
A. The stay was not granted until a week before the OTR was set to become effective, and 10
the Company had to plan as if the OTR was going to be implemented for the Utah 11
thermal generating units. Therefore the Company needed to alter its dispatch through 12
market power purchases and its thermal generating resources as necessary to ensure 13
there were sufficient NOx allowances to cover the generation. In 2023, the Company 14
incurred $17 million in additional net power costs to comply with the prospective OTR 15
requirements. 16
Q. Are other environmental compliance costs included in Idaho customer rates? 17
A. Yes. All the Company’s generation resources incur various types of environmental 18
compliance costs and generation taxes, many of which are imposed by the state where 19
the resource is located. These include costs like the Wyoming wind tax, and upgrades 20
at generation facilities that are necessary to comply with environmental requirements 21
like fish passage at hydroelectric plants or avian curtailments at wind facilities. These 22
direct impacts to generation are consistently system allocated. Idaho customers pay 23

Painter, Di-27
Rocky Mountain Power
these environmental compliance and generation tax costs incurred by resources that are 1
used to serve Idaho customers. 2
IMPACT OF PARTICIPATING IN THE WEIM 3
Q. Are the actual benefits from participating in the WEIM with CAISO included in 4
the ECAM deferral? 5
A. Yes. Participation in the WEIM provides benefits to customers in the form of reduced 6
Actual NPC. The WEIM benefits are embedded in Actual NPC through lower fuel and 7
purchased power costs. According to CAISO’s WEIM benefits report, PacifiCorp has 8
received $154 million in benefits in 2023 and $746 million since the inception of the 9
WEIM. 10
CONCLUSION 11
Q. Please summarize your testimony. 12
A. The ECAM deferral of $62.4 million, including interest, for the Deferral Period, was 13
accurately calculated in compliance with previous Commission orders. Therefore, I 14
respectfully request that the Commission approve this application as filed with rates 15
effective June 1, 2024. 16
Q. Does this conclude your direct testimony? 17
A. Yes. 18

Case No. PAC-E-24-05
Exhibit No. 1
Witness: Jack Painter

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

ROCKY MOUNTAIN POWER

____________________________________________

Exhibit Accompanying Direct Testimony of Jack Painter

April 2024

Idaho Energy Cost Adjustment Mechanism Deferral
January 1, 2023 - December 31, 2023
Line No.
CY 2021
1 ID Base NPC EmPAC-E-21-07 86,534,565$
2 Annual Idaho BasPAC-E-21-07 3,526,359
3 NPC Rate EmbedLine 1 / Line 2 24.54$
Jan-23 Feb-23 Mar-23 Apr-23 May-23 Jun-23 Jul-23 Aug-23 Sep-23 Oct-23 Nov-23 Dec-23 Total
4 NPC Rate EmbedLine 3 24.54$ 24.54$ 24.54$ 24.54$ 24.54$ 24.54$ 24.54$ 24.54$ 24.54$ 24.54$ 24.54$ 24.54$
5 ID Actual Sales @ Meter (MWh)299,332 266,756 287,605 267,422 266,927 312,992 453,764 332,398 273,090 259,513 256,625 219,155
6 ID NPC CollectedLine 4 x Line 5 7,345,407$ 6,546,028$ 7,057,643$ 6,562,371$ 6,550,208$ 7,680,628$ 11,135,084$ 8,156,825$ 6,701,462$ 6,368,292$ 6,297,415$ 5,377,911$ 85,779,273$
7 Total Company A Adjusted Actual N 197,232,836$ 215,132,289$ 214,137,197$ 162,052,729$ 160,452,428$ 178,795,711$ 297,171,442$ 302,134,695$ 233,832,184$ 176,643,130$ 199,091,621$ 197,106,207$ 2,533,782,470$
8 Total Company Load @ Input (MWh 5,470,924 4,920,330 5,135,244 4,554,467 4,596,442 4,727,056 5,971,190 5,598,864 4,669,059 4,659,078 4,854,047 5,249,636 60,406,339
9 Actual NPC ($/MWLine 7 / Line 8 36.05$ 43.72$ 41.70$ 35.58$ 34.91$ 37.82$ 49.77$ 53.96$ 50.08$ 37.91$ 41.02$ 37.55$ 41.95$
10 ID Actual Load @ Input (MWh)303,538 284,568 294,802 252,861 273,264 368,186 481,082 318,523 285,199 258,137 221,546 245,710
11 Actual ID NPC Line 9 x Line 10 10,942,879$ 12,442,212$ 12,293,097$ 8,997,068$ 9,539,095$ 13,926,241$ 23,942,267$ 17,188,614$ 14,283,130$ 9,786,957$ 9,086,860$ 9,225,583$ 151,654,001$
12 NPC Differential Line 11 - Line 6 3,597,472$ 5,896,183$ 5,235,454$ 2,434,697$ 2,988,887$ 6,245,613$ 12,807,183$ 9,031,789$ 7,581,668$ 3,418,665$ 2,789,445$ 3,847,671$ 65,874,728$
EITF 04-6 Adjustment
13 Idaho Allocated EITF 04-6 Deferral 57,959$ (40,638)$ (82,041)$ (115,519)$ (110,664)$ 65,081$ 106,954$ 36,135$ 50,297$ 85,302$ 25,322$ (17,593)$ 60,594$
LCAR
14 Actual Idaho JurisPAC-E-21-07 2,568,242$ 2,568,242$ 2,568,242$ 2,568,242$ 2,568,242$ 2,568,242$ 2,568,242$ 2,568,242$ 2,568,242$ 2,568,242$ 2,568,242$ 2,568,242$ 30,818,909$
15 LCAR Rate @ MePAC-E-21-07 8.74$ 8.74$ 8.74$ 8.74$ 8.74$ 8.74$ 8.74$ 8.74$ 8.74$ 8.74$ 8.74$ 8.74$
16 ID Actual Sales @Line 5 299,332 266,756 287,605 267,422 266,927 312,992 453,764 332,398 273,090 259,513 256,625 219,155
17 LCAR Revenue CLine 15 x Line 16 2,616,035$ 2,331,339$ 2,513,549$ 2,337,160$ 2,332,828$ 2,735,422$ 3,965,712$ 2,905,018$ 2,386,697$ 2,268,039$ 2,242,797$ 1,915,320$ 30,549,915$
18 LCAR AdjustmentLine 14 - Line 17 (47,792)$ 236,903$ 54,694$ 231,082$ 235,414$ (167,180)$ (1,397,469)$ (336,775)$ 181,546$ 300,203$ 325,446$ 652,923$ 268,994$
ECAM Deferral
19 Total ECAM Defe Sum of Lines:
12 13 18
3,607,639 6,092,448 5,208,107 2,550,260 3,113,637 6,143,514 11,516,667 8,731,149 7,813,511 3,804,170 3,140,213 4,483,002 66,204,316
20 Total ECAM DefeLine 19 x 90%3,246,875$ 5,483,203$ 4,687,296$ 2,295,234$ 2,802,273$ 5,529,163$ 10,365,000$ 7,858,034$ 7,032,160$ 3,423,753$ 2,826,192$ 4,034,701$ 59,583,884$
Production Tax Credits (PTCs)
21 ID Allocated PTCsPAC-E-21-07 (4.16)$ (4.16)$ (4.16)$ (4.16)$ (4.16)$ (4.16)$ (4.16)$ (4.16)$ (4.16)$ (4.16)$ (4.16)$ (4.16)$
22 ID Actual Sales @Line 5 299,332 266,756 287,605 267,422 266,927 312,992 453,764 332,398 273,090 259,513 256,625 219,155
23 ID PTCs in RatesLine 21 x Line 22 (1,246,393)$ (1,110,752)$ (1,197,565)$ (1,113,525)$ (1,111,461)$ (1,303,275)$ (1,889,439)$ (1,384,077)$ (1,137,127)$ (1,080,593)$ (1,068,566)$ (912,542)$
24 ID Allocated Actual PTCs ($)(1,506,351) (1,527,575) (1,349,209) (1,300,860) (898,278) (825,256) (760,968) (878,133) (855,476) (881,682) (1,455,204) (1,409,147)
25 ID PTCs Deferral Line 24 - Line 23 (259,958)$ (416,823)$ (151,644)$ (187,335)$ 213,183$ 478,018$ 1,128,470$ 505,944$ 281,651$ 198,911$ (386,637)$ (496,605)$ 907,177$
Situs Assigned REP QF Adjustment
26 ID REP QF Adjustment ($)45,334$ 50,891$ 38,540$ 102,024$ 133,317$ 198,289$ 177,707$ 130,328$ 93,656$ 168,692$ 142,411$ 168,941$ 1,450,130$
Wind Liquidated Damages
27 ID Allocated Wind Liquidated Dama -$ (14,654)$ -$ -$ -$ -$ (19,635)$ (275,795)$ -$ -$ -$ -$ (310,085)$
Renewable Energy Credits (REC) Revenue
28 ID REC Revenue PAC-E-21-07 (0.07)$ (0.07)$ (0.07)$ (0.07)$ (0.07)$ (0.07)$ (0.07)$ (0.07)$ (0.07)$ (0.07)$ (0.07)$ (0.07)$
29 ID Actual Sales @Line 5 299,332 266,756 287,605 267,422 266,927 312,992 453,764 332,398 273,090 259,513 256,625 219,155
30 ID REC Revenue Line 28 x Line 29 (20,489)$ (18,260)$ (19,687)$ (18,305)$ (18,271)$ (21,424)$ (31,060)$ (22,753)$ (18,693)$ (17,764)$ (17,566)$ (15,001)$
31 ID Allocated Actual REC Revenue ((5,402) (118,766) (228,071) (97,144) (39,468) (3,729) (30,448) 25,704 (2,060) (2,591) (20,916) (73,691)
32 REC Revenue AdLine 31 - Line 30 15,087$ (100,506)$ (208,384)$ (78,838)$ (21,197)$ 17,696$ 612$ 48,456$ 16,633$ 15,172$ (3,349)$ (58,690)$ (357,308)$
33 Total Deferral Sum of Lines 20, 3,047,338$ 5,002,111$ 4,365,808$ 2,131,085$ 3,127,577$ 6,223,166$ 11,652,155$ 8,266,967$ 7,424,100$ 3,806,528$ 2,578,616$ 3,648,347$ 61,273,798$
34 Interest Rate Order No. 35621 2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%2.00%
ECAM Balancing Account ($)
35 Beginning Balance 41,941,478$ 42,982,959$ 45,069,883$ 48,401,960$ 47,865,290$ 50,134,661$ 54,308,273$ 61,339,814$ 67,113,506$ 72,023,580$ 73,546,372$ 73,543,853$
36 ECAM Deferral AfLine 20 3,246,875 5,483,203 4,687,296 2,295,234 2,802,273 5,529,163 10,365,000 7,858,034 7,032,160 3,423,753 2,826,192 4,034,701
37 PTCs Deferral Line 25 (259,958) (416,823) (151,644) (187,335) 213,183 478,018 1,128,470 505,944 281,651 198,911 (386,637) (496,605)
38 REP Situs AdjustmLine 26 45,334 50,891 38,540 102,024 133,317 198,289 177,707 130,328 93,656 168,692 142,411 168,941
39 Wind Liquidated DLine 27 - (14,654) - -- -(19,635) (275,795) - -- -
40 REC Revenue AdLine 32 15,087 (100,506) (208,384) (78,838) (21,197) 17,696 612 48,456 16,633 15,172 (3,349) (58,690)
41 Less: Monthly ECAM Rider Revenu (2,076,569) (2,988,503) (1,111,559) (2,747,911) (939,804) (2,136,517) (4,716,907) (2,600,231) (2,629,876) (2,404,944) (2,703,608) (1,896,726)
42 Interest 70,711 73,316 77,828 80,156 81,599 86,963 96,293 106,955 115,851 121,207 122,473 124,033
43 Total ECAM Deferral Balance ($) 42,982,959$ 45,069,883$ 48,401,960$ 47,865,290$ 50,134,661$ 54,308,273$ 61,339,814$ 67,113,506$ 72,023,580$ 73,546,372$ 73,543,853$ 75,419,507$ 75,419,507$
Rocky Mountain Power
Exhibit No. 1 Page 1 of 1
Case No. PAC-E-24-05
Witness: Jack Painter

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE APPLICATION
OF ROCKY MOUNTAIN POWER
REQUESTING APPROVAL OF $62.4
MILLION ECAM DEFERRAL
) CASE NO. PAC-E-24-05
)
) DIRECT TESTIMONY OF
) ROBERT M. MEREDITH

ROCKY MOUNTAIN POWER

CASE NO. PAC-E-24-05

April 2024

Meredith, Di-1
Rocky Mountain Power
Q. Please state your name, business address and present position with PacifiCorp, 1
dba Rocky Mountain Power (“the Company”). 2
A. My name is Robert M. Meredith. My business address is 825 NE Multnomah Street, 3
Suite 2000, Portland, Oregon 97232. My present position is Director, Pricing and Tariff 4
Policy. 5
Qualifications 6
Q. Briefly describe your educational and professional background. 7
A. I graduated from Oregon State University with a Bachelor of Science degree in 8
Business Administration and a minor in Economics. In addition to my formal 9
education, I have attended various industry-related seminars. I have worked for the 10
Company for 19 years in various roles of increasing responsibility in the Customer 11
Service, Regulation, and Integrated Resource Planning departments. I have over 13 12
years of experience preparing cost of service and pricing related analyses for all of the 13
six states that PacifiCorp serves. In March 2016, I became Manager, Pricing and Cost 14
of Service. In February 2022, I assumed my current position. 15
Q. Have you testified in previous regulatory proceedings? 16
A. Yes. I have previously filed testimony on behalf of the Company in regulatory 17
proceedings in Idaho, Utah, Wyoming, Oregon, Washington, and California. 18
Q. What is the purpose of your testimony in this proceeding? 19
A. My testimony presents and supports the Company’s proposed rates to recover the 2023 20
Energy Cost Adjustment Mechanism (“ECAM”) deferral balances through Electric 21
Service Schedule No. 94, Energy Cost Adjustment (“Schedule 94”). 22

Meredith, Di-2
Rocky Mountain Power
Background 1
Q. What level of revenue is Schedule 94 currently designed to collect? 2
A. Schedule 94 is currently designed to collect approximately $32.2 million—$12.2 3
million for the Electric Service Schedule No. 400 (“Schedule 400”) customer and $20.0 4
million for standard tariff customers—based on Idaho loads from Case No. 5
PAC-E-21-07. 6
Proposed Rate Change for Schedule 94 7
Q. Please describe the Company’s proposed rate change in this case. 8
A. The 2023 ECAM application proposes to increase Schedule 94 rates to recover 9
approximately $64.9 million from June 1, 2024 to May 31, 2025. The $64.9 million 10
includes $62.4 million for the 2023 ECAM Deferral, plus approximately $13.0 million 11
remaining from the 2022 ECAM balance, for a total balance of $75.4 million as of 12
December 31, 2023. This is offset by $10.5 million Schedule 94 forecasted revenue 13
collection from January 1, 2024 through May 31, 2024, as shown in Table 2 of Mr. 14
Jack Painter’s testimony. Mr. Painter explains in his testimony the components of the 15
2023 ECAM deferred balance. 16
Q. What is the impact of the proposed ECAM rates? 17
A. As summarized in Exhibit No. 2, these rate change proposals result in an increase of 18
13.5 percent for Schedule 400. Standard tariff customers will see an average increase 19
of 9.2 percent. 20

Meredith, Di-3
Rocky Mountain Power
Renewable Energy Credit (REC) Revenue Treatment for Schedule 400 1
Q. Did the Company make any adjustments to the Schedule 94 ECAM price for 2
Schedule 400? 3
A. Yes. Consistent with the 2022 ECAM, the Company created a different ECAM rate for 4
Schedule 400 to exclude the REC revenues in the ECAM from Schedule 400’s rates. 5
Q. Why are REC revenues excluded from Schedule 400 rates? 6
A. On March 29, 2021, PacifiCorp filed an application requesting Commission approval 7
of an agreement entered into with the sole Schedule 400 customer under which the 8
Company will retire, rather than sell, this customer’s allocated share of RECs generated 9
post-2020 from system resources.1 The Company discontinued sale of Idaho-allocated 10
system RECs associated with the Schedule 400 load in 2021, so that the Schedule 400 11
customer’s allocated share of system RECs could be retired on its behalf. The REC 12
revenue that Schedule 400 would otherwise have been allocated from the sale of post-13
2020 system RECs is removed from Schedule 400’s base rates. Schedule 400 will 14
continue to receive REC revenue from the sale of any RECs generated prior to 2021. 15
On August 11, 2021, Commission Order No. 35131 approved this agreement. 16
Based on the terms of the agreement, the Company withheld the Schedule 400 17
customer’s share of 2021 RECs from any auctions or sales. Beginning on January 1, 18
2021, the Schedule 400 customer will no longer receive a REC revenue credit for RECs 19
generated after December 31, 2020. If the Company was able to sell RECs generated 20
prior to 2021, Schedule 400 will receive credit for its share of those REC revenues. 21

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.

Meredith, Di-4
Rocky Mountain Power
Q. How did you calculate the Schedule 400 ECAM rate? 1
A. To calculate the Schedule 400 ECAM rate, the Company removed REC revenue credits 2
in the ECAM from the transmission voltage rate. 3
Q. Did you remove all of the REC revenue credits in Schedule 400 rates through the 4
ECAM? 5
A. No. The ECAM only tracks the incremental difference between actual REC revenues 6
received during the deferral period and the REC revenue credit in base rates. The base 7
rates were established in Case No. PAC-E-21-07 with a REC revenue credit of seven 8
cents per megawatt hour. Base REC sales were removed from Schedule 400’s base 9
rates to reflect Schedule 400’s agreement with the Company to retire its share of RECs 10
on its behalf. 11
Calculation of Proposed Rates for Schedule 94 12
Q. How were the proposed Schedule 94 rates developed for all customers? 13
A. The proposed rates for all customers were developed in five steps. First, kilowatt-hour 14
(“kWh”) consumption at the generation level was developed by multiplying their retail 15
loads at the delivery service voltage level with the corresponding line loss factors. 16
Second, an overall average rate at the generation level was developed by dividing the 17
total collection target identified above by their kWh consumption at the generation level. 18
Third, rates by delivery voltage level were developed by multiplying the above overall 19
average rate at the generation level with the corresponding line loss factors. Fourth, the 20
rate for Schedule 400 was increased by 0.01 cents per kWh to account for the $0.4 21
million adjustment to REC revenue included in the 2023 ECAM, which Contract Tariff 22
400 had elected to forego per the terms of the REC agreement. This results in a proposed 23

Meredith, Di-5
Rocky Mountain Power
$24.6 million ECAM recovery from the Schedule 400 customer. Finally, the overall 1
proposed collection of $64.9 million was reduced by the $24.6 million share for 2
Schedule 400, and rates for standard tariff customers were developed to collect the 3
remaining $40.3 million using similar logic to that described in the third step. As a result, 4
the Company proposes Schedule 94 rates for standard tariff customers of 1.878, 1.844 5
and 1.782 cents per kWh for secondary, primary, and transmission delivery service 6
voltages, respectively. The rate for Schedule 400 is 1.798 cents per kWh. 7
Q. Please describe Exhibit No. 2. 8
A. Exhibit No. 2 shows the 2020 loads used to develop rates, the line loss adjusted loads, 9
the allocation of the ECAM price change, and the percentage change by rate schedule. 10
Q. Please describe Exhibit No. 3. 11
A. Exhibit No. 3 contains clean and legislative copies of the proposed Electric Service 12
Schedule No. 94, Energy Cost Adjustment. The Company requests that the proposed 13
Schedule 94 rates become effective on June 1, 2024. 14
Q. Does this conclude your direct testimony? 15
A. Yes. 16

Case No. PAC-E-24-05
Exhibit No. 2
Witness: Robert M. Meredith

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

ROCKY MOUNTAIN POWER

____________________________________________

Exhibit Accompanying Direct Testimony of Robert M. Meredith

April 2024

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 2020
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 55,659 523,107 $60,147 523,107 570,505 $9,825 1.878 1.844 1.782 $4,886 $4,939 7.6%
2 Residential Optional TOD 36 11,711 196,337 $19,448 196,337 214,128 $3,687 1.878 1.844 1.782 $1,834 $1,854 8.7%
3 AGA Revenue $4
4 Total Residential 67,370 719,444 $79,599 719,444 0 0 784,633 $13,512 $6,720 $6,793 7.9%
5 Commercial & Industrial
6 General Service - Large Power 6 1,158 345,854 $27,087 303,007 42,847 376,344 $6,481 1.878 1.844 1.782 $3,223 $3,258 10.7%
7 General Svc. - Lg. Power (R&F)6A 207 26,805 $2,326 26,656 149 29,231 $503 1.878 1.844 1.782 $250 $253 9.8%
8 Subtotal-Schedule 6 1,365 372,659 $29,413 329,663 42,996 0 405,575 $6,984 $3,473 $3,511 10.7%
9 General Service - High Voltage 9 17 222,699 $13,225 0 0 222,699 230,500 $3,969 1.878 1.844 1.782 $1,973 $1,996 13.1%
10 Irrigation 10 5,971 615,886 $55,363 615,886 671,691 $11,567 1.878 1.844 1.782 $5,752 $5,815 9.5%
11 General Service 23 7,734 183,016 $17,375 182,662 353 0 199,592 $3,437 1.878 1.844 1.782 $1,709 $1,728 9.1%
12 General Service (R&F)23A 2,576 39,710 $3,922 38,626 1,084 43,287 $745 1.878 1.844 1.782 $371 $375 8.7%
13 Subtotal-Schedule 23 10,310 222,726 21,298 221,289 1,437 0 242,879 4,183 2,080 2,103 9.0%
14 General Service Optional TOD 35 2 278 $23 278 303 $5 1.878 1.844 1.782 $3 $3 10.3%
15 General Service Optional TOD (R&F) 35A 0 0 $0 0 0 $0 1.878 1.844 1.782 $0 $0
16 Subtotal-Schedule 35 2 278 23 278 0 0 303 5 1.878 1.844 1.782 3 3 10.3%
17 Special Contract 400 1 1,369,716 $79,465 1,369,716 1,417,697 $24,631 1.798 $12,218 $12,413 13.5%
18 AGA Revenue $602
19 Total Commercial & Industrial 17,666 2,803,964 $199,389 1,167,116 44,433 1,592,415 2,968,646 $51,339 $25,499 $25,840 11.5%
20 Public Street Lighting
21 Security Area Lighting 7 188 274 $50 274 298 $5 1.878 1.844 1.782 $3 $3 5.0%
22 Security Area Lighting (R&F)7A 132 106 $24 106 115 $2 1.878 1.844 1.782 $1 $1 4.0%
23 Street Lighting - Company 11 57 154 $61 154 168 $3 1.878 1.844 1.782 $1 $1 2.3%
24 Street Lighting - Customer 12 256 2,417 $368 2,417 2,636 $45 1.878 1.844 1.782 $23 $23 5.8%
25 AGA Revenue $0
26 Total Public Street Lighting 633 2,950 $503 2,950 0 0 3,218 $55 $28 $28 5.2%
27 Total Sales to Ultimate Customers 85,669 3,526,359 $279,491 1,889,511 44,433 1,592,415 3,756,496 $64,907 $32,246 $32,660 10.5%
28 Total Excluding Special Contract 400 85,668 2,156,643 $200,026 1,889,511 44,433 222,699 2,338,799 $40,276 $20,029 $20,248 9.2%
Rev. Rqmt Unallocated
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):$40,276 1.722 1.878 1.844 1.782 Tariff Customer Rate 1.878 1.844 1.782 0.934 0.917 0.886
31 REC Adjustment and Rate (cents/kWh):($357)-0.010 -0.010 -0.010 -0.010 Schedule 400 Rate 1.798 0.892
32 Total Idaho ECAM Rate (cents/kWh):$64,907 1.728 1.884 1.850 1.788 REC Adj -$135
Allocated Proposed Rates Current Rates
Rocky Mountain Power
Exhibit No. 2 Page 1 of 1
Case No. PAC-E-24-05
Witness: Robert M. Meredith

Case No. PAC-E-24-05
Exhibit No. 3
Witness: Robert M. Meredith

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

ROCKY MOUNTAIN POWER

____________________________________________

Exhibit Accompanying Direct Testimony of Robert M. Meredith

April 2024

Fifteenth Fourteenth Revision of Sheet No. 94.1
I.P.U.C. No. 1 Canceling FourteenthThirteenth Revision of Sheet No. 94.1
Submitted Under Case No. PAC-E-243-059
ISSUED: March 30, 2023April 1, 2024 EFFECTIVE: June 1, 20243
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 1.8780.934¢ per kWh
Schedule 6 1.8780.934¢ per kWh 1.8440.917¢ per kWh
Schedule 6A 1.8780.934¢ per kWh 1.8440.917¢ per kWh
Schedule 7 1.8780.934¢ per kWh
Schedule 7A 1.8780.934¢ per kWh
Schedule 9 1.7820.886¢ per kWh
Schedule 10 1.8780.934¢ per kWh
Schedule 11 1.8780.934¢ per kWh
Schedule 12 1.8780.934¢ per kWh
Schedule 23 1.8780.934¢ per kWh 1.8440.917¢ per kWh
Schedule 23A 1.8780.934¢ per kWh 1.8440.917¢ per kWh
Schedule 24 1.8780.934¢ per kWh 1.8440.917¢ per kWh
Schedule 35 1.8780.934¢ per kWh 1.8440.917¢ per kWh
Schedule 35A 1.8780.934¢ per kWh 1.8440.917¢ per kWh
Schedule 36 1.8780.934¢ per kWh
Schedule 400 1.7980.892¢ per kWh
Rocky Mountain Power
Exhibit No. 3 Page 1 of 2
Case No. PAC-E-24-05
Witness: Robert M. Meredith
Fifteenth Revision of Sheet No. 94.1
I.P.U.C. No. 1 Canceling Fourteenth Revision of Sheet No. 94.1
Submitted Under Case No. PAC-E-24-05
ISSUED: April 1, 2024 EFFECTIVE: June 1, 2024
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 1.878¢ per kWh
Schedule 6 1.878¢ per kWh 1.844¢ per kWh
Schedule 6A 1.878¢ per kWh 1.844¢ per kWh
Schedule 7 1.878¢ per kWh
Schedule 7A 1.878¢ per kWh
Schedule 9 1.782¢ per kWh
Schedule 10 1.878¢ per kWh
Schedule 11 1.878¢ per kWh
Schedule 12 1.878¢ per kWh
Schedule 23 1.878¢ per kWh 1.844¢ per kWh
Schedule 23A 1.878¢ per kWh 1.844¢ per kWh
Schedule 24 1.878¢ per kWh 1.844¢ per kWh
Schedule 35 1.878¢ per kWh 1.844¢ per kWh
Schedule 35A 1.878¢ per kWh 1.844¢ per kWh
Schedule 36 1.878¢ per kWh
Schedule 400 1.798¢ per kWh
Rocky Mountain Power
Exhibit No. 3 Page 2 of 2
Case No. PAC-E-24-05
Witness: Robert M. Meredith