20230330Application.pdf

1407 W. North Temple, Suite 330
Salt Lake City, UT 84116
March 30, 2023
VIA ELECTRONIC FILING Jan Noriyuki
Commission Secretary
Idaho Public Utilities Commission 11331 W Chinden Blvd. Building 8 Suite 201A Boise, ID 83714

Re: CASE NO. PAC-E-23-09
IN THE MATTER OF THE APPLICATION OF ROCKY MOUNTAIN POWER
REQUESTING APPROVAL OF $32.5 MILLON ECAM DEFERRAL

Dear Ms. Noriyuki:
Please find Rocky Mountain Power’s Application in the above referenced matter, along with the
direct testimony and exhibits of Company witnesses Jack Painter and Robert M. Meredith. The witnesses’ work papers are confidential and will be provided through an encrypted file. You will receive a separate email with the password 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 of Regulation and Customer Solutions Enclosures

CC: Ron Williams Eric Olsen TJ Budge
RECEIVED
2023 March, 30 4:18PM
IDAHO PUBLIC
UTILITIES COMMISSION

Page 1
Joe Dallas (ISB# 10330)
825 NE Multnomah St., 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 $32.5
MILLON ECAM DEFERRAL
) CASE NO. PAC-E-23-09
)
) 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 $32.5 million of deferred costs from the deferral
period beginning January 1, 2022, through December 31, 2022, (“Deferral Period”) with a 2.3
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
89,365 customers in the state.

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.

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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 In 2022 the inflation-adjusted PTC rate for electricity generated from qualifying wind

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).

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facilities was 2.6 cents per kilowatt hour.13 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.
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 2022 ECAM deferral balances through
Electric Service Schedule No. 94 -Energy Cost Adjustment, (“Schedule 94”).

13 Credit for Renewable Electricity Production, Refined Coal Production, and Indian Coal Production, and
Publication of Inflation Adjustment Factors and Reference Prices for Calendar Year 2021, 86 Fed. Reg. 22300
(April 27, 2021).

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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. For the Deferral Period the NPC differential was approximately
$35.3 million before the 90/10 percent sharing band.
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 decreased the deferral balance by approximately $1.6 million before
applying the sharing band due to higher usage during the Deferral Period.
12. The difference between including coal stripping costs recorded on the Company’s
books under the guidance of the accounting pronouncement EITF 04-6, and expensing coal
stripping costs when the coal was excavated increased the ECAM deferral by $190,656 before
applying the sharing band.
13. The total NPC deferral adjusted for LCAR and EITF 04-6 was approximately $33.9
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
$30.5 million.
14. During the Deferral Period the PTC differential, as described in paragraph 7,
increased the deferral approximately $1.4 million.
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

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revenue true-up included in the ECAM is symmetrical, but no sharing band is applied. During the
Deferral Period actual REC revenue was $130,679 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 $295,039.
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 1.0 percent. Interest of
$327 thousand was added to the ECAM balance.
18. The ECAM balance at the end of the Deferral Period was $41.9 million, including
$32.5 million from the 2022 ECAM deferral (inclusive of interest), plus $9.5 million remaining
balance from prior ECAM filing. The Company estimates the ECAM balance will be reduced by
$9.9 million from Schedule 94 revenue collections accrued from January 1 through May 31, 2023,
resulting in an estimated ECAM balance of $32.2 million to be collected.
19. Mr. Meredith’s testimony describes how Schedule 94 rates were designed to
recover the May 31, 2023, estimated ECAM balance of $32.2 million. Based on this rate design,
the Company proposes Schedule 94 rates of 0.934, 0.917, 0.886 and 0.892 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]

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Joe Dallas (ISB# 10330)
Senior Attorney
Rocky Mountain Power
825 NE Multnomah St., 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 NE Multnomah St., Suite 2000
Portland, Oregon 97232

Informal questions may be directed to Mark Alder, Idaho Regulatory Affairs Manager at
[phone].
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 $32.5 million ECAM deferral; and (3) approving a 2.3 percent increase to Electric
Service Schedule No. 94, Energy Cost Adjustment effective June 1, 2023.

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DATED this 30th day of March 2023.
Respectfully submitted,

ROCKY MOUNTAIN POWER

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

Attorney for Rocky Mountain Power

CUSTOMER NOTICES
On March 30, 2023, Rocky Mountain
Power asked the Idaho Public
Utilities Commission to approve the
incremental energy related costs for
2022 of $32.2 million, a net increase of
$6.9 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,
2023. 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 2022 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. Multiple heat waves across
Rocky Mountain Power’s service area in
July, August, and September significantly
increased market prices. Increases in
wholesale power prices during those
months account for nearly half of the
total cost adjustment requested. The
proposed adjustment will allow Rocky
Mountain Power to continue to deliver
safe, reliable, affordable power now and
for years to come.
A typical residential customer using
783 kilowatt-hours per month would
see an increase of approximately
$1.57 a month on their electricity bill.
The following is a summary of the
percentage impacts by customer class:
• Residential Schedule 1 –
1.6% increase
• Residential Schedule 36 –
1.9% increase
• General Service Schedule 6 –
2.3% increase
• General Service Schedule 9 –
2.9% increase
Annual energy cost adjustment
Rocky Mountain Power requests recovery of power costs
PROPOSED NET PRICE INCREASE
(continued)
• Irrigation Service Schedule 10 –
2.1% increase
• General Service Schedule 23 –
2.0% increase
• General Service Schedule 35 –
2.2% increase
• Public Street Lighting – 1.1% increase
• Tariff Contract 400 – 3.0% increase
We understand the impact that price
increases have on our customers and
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-23-09.
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 customersto 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 information, contact: News Media Hotline 801‐220‐5018 

Annual energy cost adjustment 
Higher market costs in 2022 prompt price increase request 
for Idaho customers of Rocky Mountain Power 

BOISE, Idaho (March 30, 2023) — Rocky Mountain Power’s costs for fuel and wholesale electricity 
increased in 2022 because of higher energy market prices, which made purchased power to serve its 
customers more expensive. As part of an annual review of these costs, the company requested an 
average 1.7 percent price increase for Idaho residential customers. A typical residential customer using 
783 kilowatt‐hours per month would see a 1.6 percent increase of about $1.57 per month on their 
electricity bill. 

“We recognize that in difficult economic conditions, a price increase is not good news,” said Tim 
Solomon, regional business manager for Rocky Mountain Power in Rexburg. “Despite these difficulties, 
we remain committed to bringing the best value to our customers for their hard‐earned dollars. We’ve 
worked diligently to keep our expenses low. We are strict with our budgets and continue our work to 
steadily improve our system to enhance reliability for our 89,365 customers in southeastern Idaho. We 
know how important reliable service is for business and homes alike. 

“The energy costs in the annual adjustment are generally beyond the company’s direct control,” 
Solomon added. “This annual adjustment makes sure Rocky Mountain Power customers always pay a 
fair price for the energy they need.” 

Extreme weather conditions in 2022 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. Multiple heat 
waves across Rocky Mountain Power’s service area in July, August, and September significantly 
increased market prices. Increases in wholesale power prices during those months accounts for nearly 
half of total cost adjustment requested. 

“The continuing drought in the West that began in the summer of 2020 has continued to impact the 
company’s power costs because it reduces the availability of our hydroelectric resources,” said Jack 
Painter, net power cost specialist for the utility. “Additionally, December 2022 saw a historic winter 
cyclone event across most of the United States, increasing both wholesale power prices and natural gas 
prices along due to increased demand. Natural gas prices across the region drastically rose—more that 
400 percent at major delivery points last December, compared with 2021.” 

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. During the past year, the company’s 
energy‐related expenses have increased by $32.2 million. Pending commission approval, the changes 
would take effect June 1, 2023, with the following impact on each rate schedule: 

Residential Schedule 1 – 1.6% increase 
Residential Schedule 36 – 1.9% increase 
General Service Schedule 6 – 2.3% increase 
General Service Schedule 9 – 2.9% increase 
Irrigation Service Schedule 10 – 2.1% increase 
General Service Schedule 23 – 2.0% increase 
General Service Schedule 35 – 2.2% increase 
Public Street Lighting – 1.1% increase 
Tariff Contract 400 – 3.0% 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‐23‐09. 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 two 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 $32.5
MILLON ECAM DEFERRAL
) CASE NO. PAC-E-23-09
)
) DIRECT TESTIMONY OF
) JACK PAINTER

ROCKY MOUNTAIN POWER

CASE NO. PAC-E-23-09

March 2023

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, 2022 through December 31, 2022 (“Deferral Period”). More specifically, I 19
provide the following: 20
• A summary of the ECAM calculation, including changes made to comply with 21
Commission orders; 22
• Details supporting the addition of approximately $32.5 million to the deferral 23

Painter, Di-2
Rocky Mountain Power
balance, including $30.5 million customers’ share of ECAM costs, a $1.4 1
million decrease in renewable energy production tax credits (“PTCs”), $634 2
thousand in reasonable energy price (“REP”) qualified facility (“QF”) costs, a 3
credit of $295 thousand for wind availability liquidated damages, a $131 4
thousand renewable energy credit (“REC”) revenue differential, and $327 5
thousand 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. Yes. The rates for Base NPC, PTCs, RECs, and the Load Change Adjustment Revenue 13
(“LCAR”) have been updated to reflect rates established in the Company’s last general 14
rate case (“GRC”) Case No. PAC-E-21-07, which became effective January 1, 2022.3 15
The wind integration costs for third party wind have been removed because 16
PacifiCorp’s Open Access Transmission Tariff (“OATT”) Schedule 3 and 3A rates 17
include intra-hour wind integration costs and offset Base rates in FERC Account 456. 18
Liquidated damages for wind availability have been included and are passed to 19
customers outside of the sharing band. Finally, the Resource Tracking Mechanism 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
(“RTM”) and the Lake Side 2 Resource Adder have been eliminated as part of the 1
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 – 2022 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 2022 ECAM Deferral
NPC Differential 35,322,826$
EITF 04-6 Adjustment 190,656
LCAR (1,578,588)
Total Deferral Before Sharing 33,934,894$
Sharing Band 90%
Customer Reponsibility 30,541,405$
Production Tax Credits 1,388,020$
REP QF Adjustment 634,305
Wind Liquidated Damages (295,039)
REC Deferral (130,679)
Interest on Deferral 326,544
Annual Deferral (Jan - Dec 2022)32,464,556$

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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, 2023? 4
A. Table 2 provides a summary of the ECAM balancing account activity starting with the 5
December 31, 2021, ECAM deferral balance of $29.9 million approved in Case 6
No. PAC-E-22-05. By June 1, 2023, the projected balance in the ECAM deferral 7
account will be approximately $32.2 million. During the Deferral Period, 8
approximately $32.5 million is added to the balance from the annual deferral and 9
interest, which is offset by $20.5 million of ECAM revenue collections through the 10
Deferral Period, and an estimated collection of $9.7 million of Schedule 94 revenues, 11
net of interest, between January and May of 2023. 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, 2021 29,925,543$
Annual Deferral (Jan - Dec 2022) 32,138,012
Interest 326,544
ECAM Revenue Collection - Schedule 94 (20,448,621)
December 31, 2022 Balance For Collection 41,941,478$
Schedule 94 Collection - Jan - May 2023 (9,853,367)$
Interest 154,045
Expected Balance as of June 1, 2023 32,242,155$

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 $35.3 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

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Rocky Mountain Power
Account 501 – Fuel, steam generation; excluding fuel handling, start-up fuel 1
(gas and diesel fuel, residual disposal), and other costs that are 2
not modeled in GRID 3
Account 503 – Steam from other sources 4
Account 547 – Fuel, other generation 5
Account 555 – Purchased power; excluding the Bonneville Power 6
Administration (“BPA”) residential exchange credit pass-7
through if applicable 8
Account 565 – Transmission of electricity by others 9
Q. Are adjustments made to the Actual NPC before comparing them to Base NPC? 10
A. Yes. The Company adjusts Actual NPC to reflect the ratemaking treatment of several 11
items, including: 12
• out of period accounting entries booked in the Deferral Period that relate to 13
operations before implementation of the ECAM on July 1, 2009; 14
• buy-through of economic curtailment by interruptible industrial customers; 15
• revenue from a contract related to the Leaning Juniper wind resource; 16
• costs for situs-assigned resources/programs in Oregon and Utah; 17
• coal inventory adjustments to reflect coal costs in the correct period; 18
• legal fees related to fines and citations included in the cost of coal; 19
• liquidated damages that occurred outside the Deferral Period (all liquidated 20
damage fees per a coal supply agreement are booked in accordance with 21
generally accepted accounting principles); 22
• wind availability liquidated damages; and 23

Painter, Di-8
Rocky Mountain Power
• reasonable energy price adjustments to QFs. 1
Q. Why is the July 1, 2009, cutoff used to determine out of period entries? 2
A. Since the ECAM took effect, customers’ rates have been adjusted to recover essentially 3
all of the Company’s actual net power costs, excluding any differences due to the 90 / 4
10 percent sharing band. Consequently, any accounting entries made during the current 5
Deferral Period that relate to any operating period since the ECAM took effect should 6
be reflected in customer rates, whether they increase or decrease Actual NPC. However, 7
accounting entries related to operating periods before the inception of the ECAM 8
should not impact the ECAM deferral. 9
Q. In addition to comparing Actual NPC to Base NPC, what other components are 10
included in the ECAM? 11
A. The ECAM calculation includes six additional components: (i) an adjustment for 12
deferred costs associated with coal mine stripping activities recorded under the 13
Financial Accounting Standards Board (“FASB”) EITF 04-6; (ii) the LCAR 14
adjustment; (iii) a true-up of PTCs; (iv) Idaho allocated REP QF costs; (v) wind 15
availability liquidated damages; and (vi) a true-up of REC revenues as authorized in 16
Order No. 32196. 17
Q. How is the adjustment for accounting pronouncement EITF 04-6 included in the 18
ECAM? 19
A. Line 13 of Exhibit No. 1 calculates coal stripping costs, reflecting Idaho’s allocated 20
differences between the coal stripping costs incurred by the Company during 21
excavation, as recorded on the Company’s books pursuant to the guidance of the 22
accounting pronouncement EITF 04-6, and the amortization of the coal stripping costs 23

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Rocky Mountain Power
as approved by the Commission in Case No. PAC-E-09-08, Order No. 30987. During 1
the Deferral Period, the total EITF 04-6 coal stripping deferral adjustment results in a 2
$191 thousand increase to the ECAM deferral balance, before the application of the 3
90 / 10 percent sharing band. 4
Q. Please describe the LCAR adjustment. 5
A. The calculation of the LCAR adjustment is a symmetrical adjustment for over- or 6
under-collection of the energy-related portion of the Company’s embedded revenue 7
requirement for production facilities, as specified in Case No. GNR-E-10-03, Order 8
No. 32206. This adjustment accounts for variances in Idaho load that cause the 9
Company to collect more or less of these production-related costs. The LCAR rate of 10
$8.74 per MWh is used for the Deferral Period. 11
Q. How is the LCAR adjustment calculated and what impact does it have on the 12
Deferral Period? 13
A. The LCAR adjustment assumes that the actual production-related costs of the LCAR 14
are equivalent to the base amount on Exhibit No. 1 line 14. The actual production-15
related costs are then compared to the LCAR revenue collection in rates, calculated by 16
multiplying the LCAR rate by the actual Idaho retail sales on Exhibit No. 1 line 17. 17
The LCAR adjustment, which is shown on line 18 of Exhibit No. 1, is the difference 18
between the actual production-related costs and the LCAR revenue. This adjustment 19
results in a $1.6 million decrease to the ECAM deferral balance before application of 20
the 90 / 10 percent sharing band. 21

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Rocky Mountain Power
Q. Please explain the sharing band ratio between the Company and customers in the 1
ECAM. 2
A. The ECAM includes a sharing band with a symmetrical sharing ratio in which 3
customers either pay or receive 90 percent of the ECAM deferral balance, and the 4
Company is responsible for the remaining 10 percent. Line 20 of Exhibit No. 1 5
represents the customers’ 90 percent share of the monthly deferral shown on line 19. 6
For the Deferral Period, the customers’ share of the deferred balance is $30.5 million. 7
The remaining balance of $3.4 million associated with the Company’s ten percent share 8
is not included in the deferral balance as it is not recoverable from customers. 9
Q. What is the amount of the PTC true-up in the current filing? 10
A. The PTC Deferral, on line 25 of Exhibit No. 1, is calculated by comparing the actual 11
Idaho-allocated PTC to the PTC credit customers receive through base rates. The PTC 12
credit in base rates is calculated by multiplying the approved PTC rate of $4.16/MWh 13
by Idaho retail sales. The difference results in a $1.4 million increase to the ECAM 14
deferral. 15
Q. Please explain the REP QF Adjustment. 16
A. As set forth in the 2020 Inter-Jurisdictional Allocation Protocol (“2020 Protocol”): “For 17
the Interim Period, the energy output of New QF PPAs will be dynamically allocated 18
per this agreement using the SG Factor, priced at a forecasted reasonable energy price 19
defined below, and any cost of a New QF PPA above the forecasted reasonable energy 20
price will be situs assigned to and allocated to the State of Origin.”4 The Idaho situs-21
assigned cost, on line 26 of Exhibit No. 1, is $634 thousand. 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).

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Rocky Mountain Power
Q. Please explain the wind availability liquidated damages credit. 1
A. Order No. 33954 in Case No. PAC-E-17-06 provides that “the Stipulation requires the 2
Company to pass on to ratepayers all liquidated damages it receives from equipment 3
suppliers in case the repowered equipment does not meet specified availability, 4
performance, or installation schedule requirements.” The Company first removes the 5
wind availability liquidated damages from total-Company NPC and then allocates them 6
to customers using the System Generation (“SG”) allocation factor outside of the 90 /10 7
percent sharing band. The wind availability liquidated damages credited to customers 8
in the ECAM is $295 thousand, as shown on line 27 of Exhibit No. 1. 9
Q. What is the amount of REC revenue adjustment in the current filing? 10
A. The REC revenue adjustment shown on line 32 of Exhibit No. 1 is calculated by 11
comparing the actual Idaho-allocated REC revenue with the REC revenue credit 12
customers receive through base rates. The REC revenue credit in base rates is calculated 13
by multiplying the approved REC revenue rate of $0.07/MWh by Idaho retail sales. 14
The resulting difference is a $131 thousand decrease to the ECAM deferral. 15
Q. What is the total ECAM deferred balance calculated in Exhibit No. 1? 16
A. The total ECAM deferred balance as of December 31, 2022, is $32.1 million, shown 17
on line 33 of Exhibit No. 1, plus $327 thousand of interest on line 42, for a total deferral 18
of $32.5 million. 19
Q. Does the calculation of the ECAM deferral in this application comply with the 20
parameters of the Idaho ECAM as approved by the Commission? 21
A. Yes, therefore the Company recommends that the Commission approve the ECAM 22
application for recovery of the $32.5 million in prudently incurred ECAM costs. 23

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Rocky Mountain Power
DIFFERENCES IN NPC 1
Q. On a total-Company basis, what was the difference between Actual NPC and Base 2
NPC for the Deferral Period? 3
A. On a total-Company basis, Actual NPC for the Deferral Period amounted to $2.018 4
billion, exceeding Base NPC for the Deferral Period by $650 million. Table 3 provides 5
a high-level summary of the difference between Base NPC and Actual NPC by category 6
on a total-Company basis. 7
Table 3 - Net Power Cost Reconciliation ($ millions) 8

Q. Please describe the Base NPC the Company used to calculate the NPC component 9
of the ECAM deferral. 10
A. The Base NPC were set in Case No. PAC-E-21-07 and became effective 11
January 1, 2022. Base NPC used the 12-month test period of January 2021 through 12
December 2021 and set total-Company Base NPC at $1.368 billion. 13
Q. Please describe some of the weather events that impacted NPC. 14
A. Similar to 2021, the year 2022 was also marked by several extreme and unforeseeable 15
weather events that has a collective impact on Actual NPC during the year. Multiple 16
TOTAL
Base NPC 1,368$
Increase/(Decrease) to NPC:
Wholesale Sales Revenue 178
Purchased Power Expense 98
Coal Fuel Expense (19)
Natural Gas Expense 382
Wheeling and Other Expense 11
Total Increase/(Decrease)650$
Adjusted Actual NPC 2,018$

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Rocky Mountain Power
heat waves across the Company’s service territories throughout July, August, and 1
September had a significant effect on market prices, ultimately leading to an increase 2
in NPC. Cumulatively, the NPC differential for those months amounted to $16.5 3
million, which is almost half of the entire $35.3 million variance on an Idaho-allocated 4
basis. 5
Additionally, ongoing drought in the West, which began in the summer of 2020, 6
continued to impact Actual NPC because it reduced the availability of the Company’s 7
hydro resources. In 2022, actual generation from hydro resources were 1,505,231 8
MWhs, which was 34 percent lower than forecasted generation and needed to be 9
replaced to meet customer demand either through system dispatch of other resources, 10
reducing market sales, increasing market purchases, or any combination of these 11
options. The estimated impact on total-Company NPC in 2022 due to decreased hydro 12
MWhs due to drought is $151 million. 13
Finally, in December 2022 a historic winter cyclone event occurred across the 14
majority of the United States, which impacted both market prices and natural gas prices, 15
along with an increase in demand. Natural gas prices across the Company’s delivery 16
points drastically increased. At the Opal natural gas trading hub, the average market 17
prices were 424 percent higher in December 2022 as compared to December 2021, 18
while market prices at the Mid-Columbia and Four-Corners trading hubs were, on 19
average, 406 percent higher across all load hours. The NPC differential in December 20
alone is $6.7 million, or 19 percent, of the total Idaho-allocated NPC variance. 21
Q. How has the conflict in Ukraine impacted regional natural gas fuel prices? 22
A. The ongoing conflict in Ukraine has resulted in decreased availability of natural gas in 23

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Rocky Mountain Power
Europe, which was previously sourced from Russian imports. With decreased European 1
supply, the associated European demand has turned to U.S. domestic supply to fill the 2
gap. This has resulted in increased competition over domestic supply, which has driven 3
regional natural gas fuel prices upwards due to domestic production being unable to 4
keep pace with the increased demand. This increase in natural gas fuel prices 5
correspondingly increases regional natural gas market prices and regional power 6
market prices, in that order. It is difficult to predict (or forecast) how long, and in what 7
direction, these factors will continue to impact regional prices. 8
Q. Please describe the primary differences between Actual NPC and Base NPC. 9
A. From an accounting perspective, and as shown in Table 3, Actual NPC were higher than 10
Base NPC due to a $178 million reduction in wholesale sales, a $98 million increase in 11
purchased power expense, a $382 million increase in natural gas expense, and a $11 12
million increase in wheeling and other expenses. These items were partially offset by a 13
$19 million reduction in coal fuel expense. 14
Q. Please explain the changes in wholesale sales revenue. 15
A. Wholesale sales revenue declined relative to Base NPC due to higher market prices and 16
a reduction in the wholesale sales volume of market transactions (represented in GRID 17
as short-term firm and system balancing sales). Of the $178 million decrease to 18
wholesale sales, revenue from market transactions represents the largest change to Base 19
NPC. Market transactions are $209 million lower than Base NPC, specifically due to 20
the higher market prices and lower volume of market sales transactions mentioned 21
above. The average price of actual market sales transactions was $22.65/MWh, which 22

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is 52 percent higher than the average price in Base NPC. Actual wholesale market 1
volumes were 6,722 gigawatt-hours (“GWh”), or 64 percent, lower than the Base NPC. 2
Q. Please explain the changes in purchased power expense. 3
A. The expenses from market transactions (represented in GRID as short-term firm and 4
system balancing purchases) increased by $412 million compared to Base NPC, 5
making it the most significant driver. Actual market purchases were 1,039 GWh (13 6
percent) lower than Base NPC, but the average price of actual market purchases 7
transactions was $65.03/MWh (182 percent) higher than Base NPC. The biggest impact 8
to market transaction prices was tied to several heat waves throughout July, August, 9
and September, further compounded by ongoing drought dating back to the summer of 10
2020. 11
During the summer 2022 heat waves, the Mid-Columbia market hub saw an 12
average increase in heavy load hour market prices of 103 percent in August and 13
September as compared to the same timeframe in 2021. This is significant considering 14
2021 also experienced an extreme heat dome and drought. The Four Corners market 15
hub saw an average increase in heavy load hour market prices of 151 percent for the 16
same period. 17
Q. Please explain the changes in wheeling expenses. 18
A. The increase in wheeling expenses relative to Base NPC was primarily due to an 19
increase in short-term firm wheeling expense of $13.5 million. 20
Q. Please explain the changes in coal fuel expense. 21
A. Coal fuel expense decreased because coal generation volume decreased 1,484 GWh (5 22
percent) compared to Base NPC. Although the average cost of coal generation 23

Painter, Di-16
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increased from $20.08/MWh in Base NPC to $20.47/MWh in the Deferral Period, the 1
lower generation volume results in an overall decrease of $19 million in coal fuel 2
expense. 3
Q. Please explain the changes in natural gas fuel expense. 4
A. The total natural gas fuel expense in Actual NPC increased by $382 million compared 5
to Base NPC. This was mainly due to an increase in average cost of natural gas 6
generation from $26.95/MWh in Base NPC to $44.61/MWh in the Deferral Period 7
caused by conflict in Ukraine and a historic winter weather event as discussed above. 8
In addition, there was an increase in gas generation volumes of 5,198 GWh (61 9
percent). 10
IMPACT OF PARTICIPATING IN THE WEIM 11
Q. Are the actual benefits from participating in the WEIM with CAISO included in 12
the ECAM deferral? 13
A. Yes. Participation in the WEIM provides benefits to customers in the form of reduced 14
Actual NPC. The WEIM benefits are embedded in Actual NPC through lower fuel and 15
purchased power costs. According to CAISO’s WEIM benefits report, PacifiCorp has 16
received $200 million in benefits in 2022 and $591.4 million since the inception of the 17
WEIM. 18
Q. Please summarize your testimony. 19
A. The ECAM deferral of $32.5 million, including interest, for the Deferral Period, was 20
accurately calculated in compliance with previous Commission orders. Therefore, I 21
respectfully request that the Commission approve this application as filed with rates 22
effective June 1, 2023. 23

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

Case No. PAC-E-23-09
Exhibit No. 1
Witness: Jack Painter

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

ROCKY MOUNTAIN POWER

____________________________________________

Exhibit Accompanying Direct Testimony of Jack Painter

March 2023

Idaho Energy Cost Adjustment Mechanism Deferr
January 1, 2022 - December 31, 202
LinNo.
CY 20211 ID Base NPC Embedded in Rates ($PAC-E-21-07 86,534,56$
2 nnual Idaho Base Load @ meter (MWh PAC-E-21-07 3,526,353 NPC Rate Embedded in Base Rates ($/MWh Line 1 / Line 24.54$
Jan-22 Feb-22 Mar-22 Apr-22 May-22 Jun-22 Jul-22 Aug-22 Sep-22 Oct-22 Nov-224 NPC Rate Embedded in Base Rates ($/MWh Line 24.54$ 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 298,043 243,523 271,234 259,804 311,132 391,286 494,237 350,269 297,140 251,618 238,833
6 ID NPC Collected in Rates ($Line 4 x Line 7,313,771$ 5,975,88$ 6,655,89$ 6,375,41$ 7,634,96$ 9,601,91$ 12,128,26$ 8,595,38$ 7,291,62$ 6,174,53$ 5,860,811$
7 Total Company Adjusted Actual NPC ($djusted Actual NP 148,270,35$ 126,512,75$ 121,891,77$ 131,742,131$ 138,364,69$ 133,568,84$ 227,031,38$ 216,086,211$ 192,844,56$ 138,951,54$ 175,269,84$
8 Total Company Load @ Input (MWh 5,391,99 4,739,80 4,840,50 4,575,97 4,647,51 4,993,20 6,116,032 5,796,65 4,935,652 4,610,941 5,039,73 9 ctual NPC ($/MWh Line 7 / Line 27.50$ 26.69$ 25.18$ 28.79$ 29.77$ 26.75$ 37.12$ 37.28$ 39.07$ 30.14$ 34.78$
10 ID Actual Load @ Input (MWh 309,600 255,102 273,360 267,595 342,454 415,263 521,018 352,422 307,012 270,190 242,32911ctual ID NP Line 9 x Line 1 8,513,452$ 6,809,07$ 6,883,63$ 7,704,05$ 10,195,46$ 11,108,32$ 19,340,56$ 13,137,52$ 11,995,48$ 8,142,22$ 8,427,60$
12 NPC Differential Line 11 - Line 1,199,681$ 833,190$ 227,741$ 1,328,642$ 2,560,49$ 1,506,41$ 7,212,291$ 4,542,140$ 4,703,85$ 1,967,68$ 2,566,78$
EITF 04-6 Adjustmen
13 Idaho Allocated EITF 04-6 Deferral Adjustment ($(35,206)$ 124$ 23,090$ 43,918$ (65,172)$ (89,614)$ 79,342$ 124,80$ 7,959$ 87,13$ 21,54$
LCA
14 ctual Idaho Jurisdictional ECPC minus NPC (Assume Actual = PAC-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$
15 LCAR Rate @ Meter ($/MWh PAC-E-21-07 8.74$ 8.74$ 8.74$ 8.74$ 8.74$ 8.74$ 8.74$ 8.74$ 8.74$ 8.74$ 8.74$ 16 ID Actual Sales @ Meter (MWh Line 298,043 243,523 271,234 259,804 311,132 391,286 494,237 350,269 297,140 251,618 238,833 17 LCAR Revenue Collected through Base Rates (Line 15 x Line 1 2,604,76$ 2,128,28$ 2,370,46$ 2,270,57$ 2,719,16$ 3,419,681$ 4,319,43$ 3,061,20$ 2,596,88$ 2,199,03$ 2,087,302$
18 LCAR Adjustmen Line 14 - Line 1 (36,525)$ 439,957$ 197,77$ 297,66$ (150,918$ (851,438$ (1,751,188$ (492,966$ (28,638)$ 369,208$ 480,940$
ECAM Deferral19 Total ECAM Deferral (NPC Deferral, EITF 04-6 Adjustment, LCASum of Lines: 12, 13, 1 1,127,95 1,273,271 448,605 1,670,22 2,344,40 565,360 5,540,44 4,173,97 4,683,17 2,424,031 3,069,27 20 Total ECAM Deferral after 90% Sharin Line 19 x 90 1,015,15$ 1,145,94$ 403,74$ 1,503,20$ 2,109,96$ 508,82$ 4,986,401$ 3,756,581$ 4,214,85$ 2,181,62$ 2,762,34$
Production Tax Credits (PTCs21 ID Allocated PTCs in Rates ($/MWh PAC-E-21-07 (4.16$ (4.16$ (4.16$ (4.16$ (4.16$ (4.16$ (4.16$ (4.16$ (4.16$ (4.16$ (4.16$
22 ID Actual Sales @ Meter (MWh Line 298,043 243,523 271,234 259,804 311,132 391,286 494,237 350,269 297,140 251,618 238,833 23 ID PTCs in Rates ($Line 21 x Line 2 (1,241,025$ (1,014,008$ (1,129,395$ (1,081,802$ (1,295,527$ (1,629,285$ (2,057,965$ (1,458,494$ (1,237,267$ (1,047,716$ (994,482$
24 ID Allocated Actual PTCs ($(1,643,681 (1,590,954 (1,394,353 (1,439,211 (1,211,430 (876,345 (690,035 (628,766 (724,878 (921,948 (1,220,451 25 ID PTCs Deferral ($Line 24 - Line 2 (402,656$ (576,945$ (264,958$ (357,409$ 84,096$ 752,941$ 1,367,930$ 829,728$ 512,390$ 125,769$ (225,969$
Situs Assigned REP QF Adjustmen26 ID REP QF Adjustment ($3,642$ 6,52$ 5,277$ 42,967$ 78,488$ 127,253$ 68,56$ 56,281$ 37,079$ 78,72$ 44,193$
Wind Liquidated Damage27 ID Allocated Wind Liquidated Damages ($(52,304)$ $ $ $ $ $ $ $ $ $ (239,912$
Renewable Energy Credits (REC) Revenu28 ID REC Revenue in Rates ($/MWh PAC-E-21-07 (0.07$ (0.07$ (0.07$ (0.07$ (0.07$ (0.07$ (0.07$ (0.07$ (0.07$ (0.07$ (0.07$ 29 ID Actual Sales @ Meter (MWh Line 298,043 243,523 271,234 259,804 311,132 391,286 494,237 350,269 297,140 251,618 238,833 30 ID REC Revenue in Rates ($Line 28 x Line 2 (20,401$ (16,669$ (18,566$ (17,784$ (21,297$ (26,784$ (33,831$ (23,976$ (20,339$ (17,223$ (16,348$
31 ID Allocated Actual REC Revenue ($(33,363 (15,420 (103,577 (98,901 (16,738 (29,836 (21,885 (3,551 16,899 (2,231 (2,696 32 REC Revenue Adjustment ($Line 31 - Line 3 (12,962)$ 1,249$ (85,011)$ (81,117)$ 4,560$ (3,053)$ 11,946$ 20,42$ 37,239$ 14,992$ 13,653$
33 Total Deferral Sum of Lines 20, 25, 26, 27, 3 550,87$ 576,772$ 59,053$ 1,107,64$ 2,277,10$ 1,385,96$ 6,434,841$ 4,663,01$ 4,801,56$ 2,401,11$ 2,354,312$
34 Interest Rat Order No. 3486 1.00%1.00%1.00%1.00%1.00%1.00%1.00%1.00%1.00%1.00%1.00%
ECAM Balancing Account ($35 Beginning Balanc 29,925,54$ 29,605,861$ 28,862,30$ 28,422,82$ 28,674,96$ 30,048,80$ 29,912,72$ 32,244,61$ 34,870,97$ 37,291,82$ 37,836,661$
36 ECAM Deferral After Sharin Line 2 1,015,15 1,145,94 403,744 1,503,20 2,109,96 508,824 4,986,401 3,756,581 4,214,85 2,181,62 2,762,34 37 PTCs Deferral Line 2 (402,656 (576,945 (264,958 (357,409 84,096 752,941 1,367,93 829,728 512,390 125,769 (225,969
38 REP Situs Adjustmen Line 2 3,642 6,524 5,277 42,967 78,488 127,253 68,564 56,281 37,079 78,724 44,193 39 Wind Liquidated Damage Line 2 (52,304 - - - - - - - - - (239,912 40 REC Revenue Adjustmen Line 3 (12,962 1,249 (85,011 (81,117 4,560 (3,053 11,946 20,425 37,239 14,992 13,653
41 Less: Monthly ECAM Rider Revenues allocated to ECA (895,351 (1,344,678 (522,392 (879,287 (927,727 (1,547,017 (4,128,846 (2,064,606 (2,410,769 (1,887,566 (1,911,839 42 Interes 24,794 24,352 23,859 23,781 24,458 24,974 25,888 27,953 30,055 31,290 31,715
43 Total ECAM Deferral Balance ($)29,605,861$ 28,862,307$ 28,422,828$ 28,674,966$ 30,048,805$ 29,912,727$ 32,244,610$ 34,870,972$ 37,291,823$ 37,836,661$ 38,310,848$
Rocky Mountain Power
Exhibit No. 1 Page 1 of 2 Case No. PAC-E-23-09 Witness: Jack Painter
Idaho Energy Cost Adjustment Mechanism Deferr
January 1, 2022 - December 31, 202
LinNo.
1 ID Base NPC Embedded in Rates ($PAC-E-21-07
2 nnual Idaho Base Load @ meter (MWh PAC-E-21-073 NPC Rate Embedded in Base Rates ($/MWh Line 1 / Line
4 NPC Rate Embedded in Base Rates ($/MWh Line 5 ID Actual Sales @ Meter (MWh
6 ID NPC Collected in Rates ($Line 4 x Line
7 Total Company Adjusted Actual NPC ($djusted Actual NP
8 Total Company Load @ Input (MWh9ctual NPC ($/MWh Line 7 / Line
10 ID Actual Load @ Input (MWh11ctual ID NP Line 9 x Line 1
12 NPC Differential Line 11 - Line
EITF 04-6 Adjustmen
13 Idaho Allocated EITF 04-6 Deferral Adjustment ($
LCA
14 ctual Idaho Jurisdictional ECPC minus NPC (Assume Actual = PAC-E-21-07
15 LCAR Rate @ Meter ($/MWh PAC-E-21-0716 ID Actual Sales @ Meter (MWh Line 17 LCAR Revenue Collected through Base Rates (Line 15 x Line 1
18 LCAR Adjustmen Line 14 - Line 1
ECAM Deferral19 Total ECAM Deferral (NPC Deferral, EITF 04-6 Adjustment, LCASum of Lines: 12, 13, 120Total ECAM Deferral after 90% Sharin Line 19 x 90
Production Tax Credits (PTCs21 ID Allocated PTCs in Rates ($/MWh PAC-E-21-07
22 ID Actual Sales @ Meter (MWh Line 23 ID PTCs in Rates ($Line 21 x Line 2
24 ID Allocated Actual PTCs ($25 ID PTCs Deferral ($Line 24 - Line 2
Situs Assigned REP QF Adjustmen26 ID REP QF Adjustment ($
Wind Liquidated Damage27 ID Allocated Wind Liquidated Damages ($
Renewable Energy Credits (REC) Revenu28 ID REC Revenue in Rates ($/MWh PAC-E-21-0729 ID Actual Sales @ Meter (MWh Line 30 ID REC Revenue in Rates ($Line 28 x Line 2
31 ID Allocated Actual REC Revenue ($32 REC Revenue Adjustment ($Line 31 - Line 3
33 Total Deferral Sum of Lines 20, 25, 26, 27, 3
34 Interest Rat Order No. 3486
ECAM Balancing Account ($35 Beginning Balanc
36 ECAM Deferral After Sharin Line 237 PTCs Deferral Line 2
38 REP Situs Adjustmen Line 239 Wind Liquidated Damage Line 240 REC Revenue Adjustmen Line 3
41 Less: Monthly ECAM Rider Revenues allocated to ECA42 Interes
43 Total ECAM Deferral Balance ($)
Dec-22 Total24.54$ 299,866
7,358,512$ 90,966,98$
267,860,34$ 2,018,394,44$
5,589,47 61,277,48 47.92$ 32.94$
292,81614,032,41$ 126,289,81$
6,673,90$ 35,322,82$
(7,269)$ 190,65$
2,568,242$ 30,818,90$
8.74$ 299,866 2,620,702$ 32,397,49$
(52,460)$ (1,578,588$
6,614,17 33,934,89 5,952,75$ 30,541,40$
(4.16$
299,866 (1,248,617$
(1,705,514 (456,897$ 1,388,020$
85,311$ 634,30$
(2,824)$ (295,039$
(0.07$ 299,866 (20,526$
(73,125 (52,599)$ (130,679$
5,525,74$ 32,138,01$
1.00%
38,310,84$
5,952,75 (456,897
85,311 (2,824 (52,599
(1,928,544 33,425
41,941,478$ 41,941,478$
Rocky Mountain Power
Exhibit No. 1 Page 2 of 2 Case No. PAC-E-23-09 Witness: Jack Painter

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE APPLICATION
OF ROCKY MOUNTAIN POWER
REQUESTING APPROVAL OF $32.5
MILLON ECAM DEFERRAL
) CASE NO. PAC-E-23-09
)
) DIRECT TESTIMONY OF
) ROBERT M. MEREDITH

ROCKY MOUNTAIN POWER

CASE NO. PAC-E-23-09

March 2023

Meredith, Di-1
Rocky Mountain Power
Q. Please state your name, business address and present position with PacifiCorp, 1
d/b/a 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 18 years in various roles of increasing responsibility in the Customer 11
Service, Regulation, and Integrated Resource Planning departments. I have over 12 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 2022 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 $25.3 million—$9.6 million 3
for the Electric Service Schedule No. 400 (“Schedule 400”) customer and $15.7 million 4
for standard tariff customers—based on Idaho loads from Case No. PAC-E-21-07. 5
Proposed Rate Change for Schedule 94 6
Q. Please describe the Company’s proposed rate change in this case. 7
A. The 2022 ECAM application proposes to increase Schedule 94 rates to recover 8
approximately $32.2 million from June 1, 2023 to May 31, 2024. This amount includes 9
$32.5 million for the 2022 ECAM Deferral and approximately $9.5 million remaining 10
from the 2021 ECAM balance, resulting in a total balance of $41.9 million as of 11
December 31, 2022. This is offset by $9.9 million Schedule 94 forecasted revenue 12
collection from January 1, 2023 through May 31, 2023, as shown in Table 2 of Mr. 13
Jack Painter’s testimony. Mr. Painter explains in his testimony the components of the 14
2022 ECAM deferred balance. 15
Q. What is the impact of the proposed ECAM rates? 16
A. As summarized in my Exhibit No. 2, these rate change proposals result in an increase 17
of 3.0 percent for Schedule 400. Standard tariff customers will see an average increase 18
of 2.0 percent. 19
Renewable Energy Credit (“REC”) Revenue Treatment for Schedule 400 20
Q. Did the Company make any adjustments to the Schedule 94 ECAM price for 21
Schedule 400? 22
A. Yes. Consistent with the 2021 ECAM, the Company created a different ECAM rate for 23

Meredith, Di-3
Rocky Mountain Power
Schedule 400 to exclude the REC revenues in the ECAM from Schedule 400’s rates. 1
Q. Why are REC revenues excluded from Schedule 400 rates? 2
A. On March 29, 2021, PacifiCorp filed an application to the Commission requesting 3
approval of an agreement the Company entered into with the sole Schedule 400 4
customer (“REC agreement”). Under this agreement, the Company will retire, rather 5
than sell, this customer’s allocated share of RECs generated post-2020 from system 6
resources.1 The Company discontinued sale of Idaho-allocated system RECs associated 7
with the Schedule 400 load in 2021, so that the Schedule 400 customer’s allocated share 8
of system RECs could be retired on its behalf. As a result, the REC revenue that 9
Schedule 400 would otherwise have been allocated from the sale of post-2020 system 10
RECs is removed from Schedule 400’s base rates. However, Schedule 400 will 11
continue to receive REC revenue from the sale of any RECs generated prior to 2021. 12
On August 11, 2021, Commission Order No. 35131 approved the REC 13
agreement. Based on the terms of the agreement, the Company withheld the Schedule 14
400 customer’s share of 2021 RECs from any auctions or sales. Beginning on January 15
1, 2021, the Schedule 400 customer will no longer receive a REC revenue credit for 16
RECs generated after December 31, 2020. However, if the Company was able to sell 17
RECs generated prior to 2021, Schedule 400 will receive credit for its share of those 18
REC revenues. 19
Q. How did you calculate the Schedule 400 ECAM rate? 20
A. To calculate the Schedule 400 ECAM rate, the Company removed REC revenue 21
credits in the ECAM from the transmission voltage rate. 22

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. Did you remove all of the REC revenue credits in Schedule 400 rates through the 1
ECAM? 2
A. No. The ECAM only tracks the incremental difference between actual REC revenues 3
received during the deferral period and the REC revenue credit in base rates. The base 4
rates were established in Case No. PAC-E-21-07 with a REC revenue credit of seven 5
cents per megawatt hour. Base REC sales were removed from Schedule 400’s base 6
rates to reflect Schedule 400’s agreement with the Company to retire its share of RECs 7
on its behalf. 8
Calculation of Proposed Rates for Schedule 94 9
Q. How were the proposed Schedule 94 rates developed for all customers? 10
A. The proposed rates for all customers were developed in five steps. First, kilowatt-hour 11
(“kWh”) consumption at the generation level was developed by multiplying their retail 12
loads at the delivery service voltage level with the corresponding line loss factors. 13
Second, an overall average rate at the generation level was developed by dividing the 14
total collection target identified above with their kWh consumption at the generation 15
level. Third, rates by delivery voltage level were developed by multiplying the above 16
overall average rate at the generation level with the corresponding line loss factors. 17
Fourth, the rate for Schedule 400 was increased by 0.004 cents per kWh to account for 18
the $0.1 million adjustment to REC revenue included in the 2022 ECAM, which 19
Contract Tariff 400 had elected to forego per the terms of the REC agreement. This 20
results in a proposed $12.2 million ECAM recovery from the Schedule 400 customer. 21
Finally, the overall proposed collection of $32.2 million was reduced by the $12.2 22
million share for Schedule 400, and rates for standard tariff customers were developed 23

Meredith, Di-5
Rocky Mountain Power
to collect the remaining $20.0 million using similar logic to that described in the third 1
step. As a result, the Company proposes Schedule 94 rates for standard tariff customers 2
of 0.934, 0.917 and 0.886 cents per kWh for secondary, primary and transmission 3
delivery service voltages, respectively. The rate for Schedule 400 is 0.892 cents per 4
kWh. 5
Q. Please describe Exhibit No. 2. 6
A. Exhibit No. 2 shows the 2020 loads used to develop rates, the line loss adjusted loads, 7
the allocation of the ECAM price change, and the percentage change by rate schedule. 8
Q. Please describe Exhibit No. 3. 9
A. Exhibit No. 3 contains clean and legislative copies of the proposed Electric Service 10
Schedule No. 94, Energy Cost Adjustment. The Company requests that the proposed 11
Schedule 94 rates become effective on June 1, 2023. 12
Q. Does this conclude your direct testimony? 13
A. Yes. 14

Case No. PAC-E-23-09
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 2023

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
(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 $4,885 0.934 0.917 0.886 $3,834 $1,050 1.6%
2 Residential Optional TOD 36 11,711 196,337 $19,448 196,337 214,128 $1,833 0.934 0.917 0.886 $1,439 $394 1.9%
3 AGA Revenue $4
4 Total Residential
5 Commercial & Industrial
6 General Service - Large Power 6 1,158 345,854 $27,087 303,007 42,847 376,344 $3,222 0.934 0.917 0.886 $2,530 $693 2.3%
7 General Svc. - Lg. Power (R&F)6A 207 26,805 $2,326 26,656 149 29,231 $250 0.934 0.917 0.886 $196 $54 2.1%
8 Subtotal-Schedule 6 1,365 372,659 $29,413 329,663 42,996 0 405,575 $3,473 $2,726 $747 2.3%
9 General Service - High Voltage 9 17 222,699 $13,225 0 0 222,699 230,500 $1,974 0.934 0.917 0.886 $1,550 $424 2.9%
10 Irrigation 10 5,971 615,886 $55,363 615,886 671,691 $5,751 0.934 0.917 0.886 $4,514 $1,237 2.1%
11 General Service 23 7,734 183,016 $17,375 182,662 353 0 199,592 $1,709 0.934 0.917 0.886 $1,341 $367 2.0%
12 General Service (R&F)23A 2,576 39,710 $3,922 38,626 1,084 43,287 $371 0.934 0.917 0.886 $291 $80 1.9%
13 Subtotal-Schedule 23 10,310 222,726 21,298 221,289 1,437 0 242,879 2,080 1,632 447 1.9%
14 General Service Optional TOD 35 2 278 $23 278 303 $3 0.934 0.917 0.886 $2 $1 2.2%
15 General Service Optional TOD (R&F) 35A 0 0 $0 0 0 $0 0.934 0.917 0.886 $0 $0
16 Subtotal-Schedule 35 2 278 23 278 0 0 303 3 0.934 0.917 0.886 2 1 2.2%
17 Special Contract 400 1 1,369,716 $79,465 1,369,716 1,417,697 $12,217 0.892 $9,588 $2,629 3.0%
18 AGA Revenue $602
19 Total Commercial & Industrial
20 Public Street Lighting
21 Security Area Lighting 7 188 274 $50 274 298 $3 0.934 0.917 0.886 $2 $1 1.1%
22 Security Area Lighting (R&F)7A 132 106 $24 106 115 $1 0.934 0.917 0.886 $1 $0 0.9%
23 Street Lighting - Company 11 57 154 $61 154 168 $1 0.934 0.917 0.886 $1 $0 0.5%
24 Street Lighting - Customer 12 256 2,417 $368 2,417 2,636 $23 0.934 0.917 0.886 $18 $5 1.3%
25 AGA Revenue $0
26 Total Public Street Lighting
Total Sales to Ultimate Customers
28 Total Excluding Special Contract 400 85,668 2,156,643 $200,026 1,889,511 44,433 222,699 2,338,799 $20,025 $15,720 $4,305 2.0%
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):$20,025 0.856 0.934 0.917 0.886 Tariff Customer Rate 0.934 0.917 0.886 0.733 0.720 0.696
31 REC Adjustment and Rate (cents/kWh):($131)-0.003 -0.004 -0.004 -0.004 Schedule 400 Rate 0.892 0.700
32 Total Idaho ECAM Rate (cents/kWh): 32,242 0.858 0.936 0.919 0.888 REC Adj -$49
Current RatesAllocatedProposed Rates
Rocky Mountain Power
Exhibit No. 2 Page 1 of 1 Case No. PAC-E-23-09 Witness: Robert M. Meredith

Case No. PAC-E-23-09
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 2023

FourteenthThirteenth Revision of Sheet No. 94.1 I.P.U.C. No. 1 Canceling ThirteenthTwelfth Revision of Sheet No. 94.1
Submitted Under Case No. PAC-E-232-095
ISSUED: March 30, 20232 EFFECTIVE: June 1, 20232
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.
Rocky Mountain Power
Exhibit No. 3 Page 1 of 2 Case No. PAC-E-23-09 Witness: Robert M. Meredith
Fourteenth Revision of Sheet No. 94.1 I.P.U.C. No. 1 Canceling Thirteenth Revision of Sheet No. 94.1
Submitted Under Case No. PAC-E-23-09
ISSUED: March 30, 2023 EFFECTIVE: June 1, 2023
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.
Rocky Mountain Power
Exhibit No. 3 Page 2 of 2 Case No. PAC-E-23-09 Witness: Robert M. Meredith