20210331Application.pdf

March 31 , 2021
VL4 ELECTRONIC DELIVERY
Jan Noriyuki
Commission Secretary
Idaho Public Utilities Commission
11331 W Chinden Blvd.
Building 8 Suite 201A
Boise, ID 83 714
Re: CASE NO. PAC-E-21-09
: ~. : . :'. ~-·. l E:,~.!~~~
• ~:
1 ~ ! .. 1., ~s C():·/~~r,~s10,
1407 West North Temple, Suite 330
Salt Lake City, Utah 84116
IN THE MATTER OF THE APPLICATION OF ROCKY MOUNTAIN POWER
REQUESTING APPROVAL OF $16.1 MILLON NET POWER COST
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 Messers. Jack E. Painter, Robert M. Meredith,
and Steven R. McDougal.
Informal inquiries may be directed to Ted Weston, Idaho Regulatory Manager at (801) 220-
2963.
~u~w)
Joelle Steward
Vice President, Regulation
Enclosures
CC: Ron Williams
Eric Olsen
Randall C. Budge
Adam Lowney (ISB# 10456)
McDowell Rackner Gibson PC
419 SW 11 th Avenue, Suite 400
Portland, OR 97205
Telephone: [phone]
Fax: [phone]
Email: [e-mail]
Emily Wegener (Idaho Bar application pending)
1407 West North Temple, Suite 320
Salt Lake City, Utah 84116
Telephone No. [phone]
Mobile No. [phone]
Email: [e-mail]
Attorneys for Rocky Mountain Power
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF ROCKY MOUNTAIN POWER
REQUESTING APPROVAL OF $16.1
MILLON NET POWER COST DEFERRAL
) CASE NO. PAC-E-21-09
)
) 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 $16.1 million of deferred costs from the deferral
period beginning January 1, 2020 through December 31, 2020 ("Deferral Period") with a
0.9 percent decrease to Electric Service Schedule No. 94, Energy Cost Adjustment ("Schedule 94")
for standard tariff customers. Tariff Contract 400 and 401 customers will see a 1.3 percent decrease.
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
Page 1
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
84,000 customers in the state.
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 net power costs ("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 include 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 54 7 (fuel, other generation),
• Account 555 (purchased power, excluding BPA residential exchange credit pass­
through if applicable), and
• Account 565 (transmission of electricity by others).
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 l d. at 2-3.
Page 2
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
5. In addition to the difference between Actual NPC and Base NPC, the ECAM
includes six additional components: the Load Change Adjustment Revenues ("LCAR"),4 an
adjustment for the treatment of coal stripping costs under Emerging Issues Task Force ("EITF")
04-6, a true-up of 100 percent of the incremental Renewable Energy Credit ("REC") revenues,
Production Tax Credits ("PTC"), 5 the Lake Side 2 generation resource adder, 6 and a resource
tracking mechanism ("RTM"). 7 These components are described in more detail below.
6. This year, pursuant to Order No. 34384, the ECAM does not include additional
components related to tax benefits arising from the Tax Cut and Jobs Act of 2017 ("TCJA").
7. 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.
8. The ECAM deferral also includes a resource adder for the Lake Side 2 generation
facility that is not subject to the sharing band. 8 This resource adder is to be recovered through the
ECAM for the period that the investment in the facility is not reflected in rates as a component of
3 ld.at3.
4 Id. at 4.
5 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).
6 In the Matter of the Application of PacifiCorp DBA Rocky Mountain Power to Initiate Discussions with Interested
Parties on Alternative Rate Plan Proposals, Case No. PAC-E-13-04, Order 32910, at 2 (October 24, 2013) ("2013
Order").
1 In the Matter of the Application of Rocky Mountain Power for Binding Rate making Treatment for Wind
Repowering, Case No. PAC-E-17-06, Order No. 33954 (December 28, 2018).
8 2013 Order, at 2.
Page 3
rate base. Inclusion of the Lake Side 2 resource adder in the ECAM began January 1, 2015. It is
calculated by multiplying the actual megawatt-hours of generation from the Lake Side 2 generation
facility by $1.99 per megawatt-hour and is capped at $5.4 million dollars or 2,729,500 megawatt­
hours for the calendar year. 9
9. 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 IO years beginning on the date the facility is placed in-service for income tax
purposes. 12 In 2020, the inflation-adjusted PTC rate for electricity generated from qualifying wind
facilities was 2.5 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
amount of PTCs 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
9 Id.
10 2015 ECAM Order at 5.
11 IRC section 45(a).
12 IRC section 45(a).
13 Credit for Renewable Electricity Production, Refined Coal Production, and Indian Coal Production, and
Publication oflnflation Adjustment Factors and Reference Prices for Calendar Year 2020, 85 Fed. Reg. 28698 (May
13, 2020).
Page4
eligible for PTCs, the repowering program undertaken by the Company has extended this benefit
for an additional ten years.
10. Calendar year 2020 is the last year that recovery of the 2013 incremental
depreciation expense, that was authorized for deferral, 14 will be recovered through the ECAM.
11. While previous ECAM deferrals have netted tax savings from the Tax Cuts and
Jobs Act, they were not netted against the 2020 ECAM deferral pursuant to the Commission's
order in Case No. PAC-E-20-03. In that order, the Commission approved a settlement allowing the
Company to retain TCJA savings to buy down or offset the net plant balance and closure costs of
Cholla Unit No. 4 and to offset the January 1, 2022 rate increase.15
PROPOSED ECAM RATE
12. In support of this Application, Rocky Mountain Power has filed the testimony and
exhibits of Company witnesses Messers. Jack Painter, Robert M. Meredith, and
Steven R. McDougal. 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 to recover the
2020 ECAM deferral balances through Electric Service Schedule No. 94-Energy Cost Adjustment
("Schedule 94") were developed. Mr. McDougal's testimony describes the recovery of expenses
relating to wind repowering through the RTM and explains modification to the accounting
treatment of excess deferred income tax.
14 In the Matter of the Application of PacifiCorp dba Rocky Mountain Power to Initiate Discussions with Interested
Parties on Alternative Rate Plan Proposals, Case No. PAC-E-13-04, Order No. 32910 at 3 (October 23, 2013)
(permitting deferral of 201 3 incremental depreciation expense).
15 In the Matter of Rocky Mountain Power 's Application to Increase Its Rates and Charges in Idaho and for
Approval of Proposed Electric Service Schedules and Regulations, Case No. PAC-E-20-03, Order No. 34884 at 2
(December 31, 2020).
Page 5
13. Exhibit No. 1 to Mr. Painter's testimony ("Exhibit 1") illustrates the detailed
calculation of the ECAM deferral. The deferral is calculated on a monthly basis by comparing
Idaho-allocated Actual NPC to the NPC collected in rates. For the Deferral Period, the NPC
differential was approximately $5. 7 million before the 90/10 percent sharing band.
14. 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, and the
Lake Side 2 generation resource adder.
15. 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 $1.1 million before
applying the sharing band due to higher usage during the Deferral Period.
16. The difference between including coal stripping costs recorded on the Company 's
books under the guidance of the accounting pronouncement EITF 04-6, and expensing coal
stripping costs when the coal was excavated decreased the ECAM deferral by $127,464 before
applying the sharing band.
17. The total NPC deferral adjusted for LCAR and EITF 04-6 was approximately
$4.5 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
$4 million.
18. The total Lake Side 2 resource adder, described in paragraph 8 above and included
on line 27 of Exhibit No. 1 for the Deferral Period, was $5.4 million based on 3,171 ,917 megawatt­
hours ("MWh") of generation, but limited to 2,729,500 MWh due to the cap.
Page 6
19. During the Deferral Period the PTC differential, as described in paragraph 9,
decreased the deferral approximately $0.1 million.
20. The ECAM calculation also includes the RTM described in Mr. McDougal's
testimony. For the Deferral Period the RTM increased the deferral by approximately $4.4 million
on an Idaho basis, without application of the sharing band.
21. 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 approximately $8,557 higher than the amount credited to
customers in base rates on an Idaho-allocated basis.
22. 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 percent. Interest of
$562 thousand was added to the ECAM balance.
23. As described in paragraph 10, the ECAM includes 2013 incremental depreciation
expenses. During the Deferral Period approximately $2.0 million was deferred associated with the
2013 incremental depreciation. The depreciation balancing account had a credit balance of
$150,512 as of the end of the Deferral Period as summarized in Exhibit No. 1 to Mr. Painter's
testimony.
24. The ECAM balance at the end of the Deferral Period was $23.2 million, including
$13.8 million from the 2020 ECAM deferral, plus $8.9 million remaining balance from prior
ECAM filings, and $0.6 million interest. This amount is reduced by $0.1 million credit balance in
the depreciation deferred balance. The Company estimates the ECAM balance will be reduced
approximately $7.0 million from Schedule 94 revenue collections less interest accrued from
Page 7
January 1 through May 31 , 2021 resulting with an expected ECAM balance of $16.1 million to be
collected.
25. Mr. Meredith's testimony describes how Schedule 94 rates were designed to
recover the May 31 , 2021 estimated ECAM balance of $16.1 million. As a result, the Company
proposes Schedule 94 rates of 0.477, 0.461 and 0.449 cents per kilowatt-hour for secondary,
primary and transmission delivery service voltages, respectively, for all customers.
COMMUNICATIONS
Communications regarding this filing should be addressed to:
Ted Weston
Idaho Regulatory Affairs Manager
Rocky Mountain Power
1407 West North Temple, Suite 330
Salt Lake City, Utah 84116
Telephone: [phone]
Email: [e-mail]
Emily L. Wegener
Senior Attorney
Rocky Mountain Power
1407 West North Temple, Suite 320
Salt Lake City, Utah 84116
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
Page 8
Informal questions may be directed to Ted Weston, 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 it has
accurately calculated the ECAM deferral with all the other 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 $14.3 million ECAM deferral; and (3) approving a 1.3 percent decrease to Electric
Service Schedule No. 94, Energy Cost Adjustment effective June 1, 2021.
DATED this 3151 day of March 2021.
Respectfully submitted,
ROCKY MO TAIN POWER
Adam Lowney (ISB#10456)
McDowell Rackner Gibson PC
4 l 9 SW 11th Avenue, Suite 400
Portland, OR 97205
Telephone: [phone]
Fax: [phone]
Email: [e-mail]
Emily L. Wegener (Idaho Bar admission pending)
1407 West North Temple, Suite 320
Salt Lake City, Utah 84116
Telephone No. [phone]
Mobile No. [phone]
Email: [e-mail]
Attorneys for Rocky Mountain Power
Page 9
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION ) CASE NO. PAC-E-21-09
OF ROCKY MOUNTAIN POWER )
REQUESTING APPROVAL OF $16.1 ) DIRECT TESTIMONY OF
MILLON NET POWER COST DEFERRAL ) JACK PAINTER
ROCKY MOUNTAIN POWER
CASE NO. PAC-E-21-09
March 2021
1 Q.
2
3 A.
4
5
6 Q.
7 A.
8
9
10
11
12 Q.
13 A.
14
15 Q.
16 A.
17
18
19
20
21
22
23
Please state your name, business address, and present position with PacifiCorp
d/b/a Rocky Mountain Power ("Rocky Mountain Power" or the "Company").
My name is Jack Painter and my business address is 825 NE Multnomah Street, Suite
600, Portland, Oregon 97232. My title is Net Power Cost Specialist.
QUALIFICATIONS
Please describe your education and professional experience.
I received a Bachelor of Arts degree in Business Administration with a Finance major
from Washington State University in 2007. I have been employed by PacifiCorp since
2008 and have held positions in the regulation and jurisdictional loads departments. I
joined the regulatory net power costs group in 2019 and assumed my current role as a
net power cost specialist in 2020.
Have you testified in previous regulatory proceedings?
Yes. I have previously provided testimony to the Utah Public Service Commission.
PURPOSE OF TESTIMONY
What is the purpose of your testimony in this proceeding?
My testimony presents and supports the Company's calculation of the Energy Cost
Adjustment Mechanism ("ECAM") balancing account for the 12-month period of
January 1, 2020 through December 31 , 2020 ("Deferral Period"). More specifically, I
provide the following:
• A summary of the ECAM calculation, including changes made to comply with
Commission orders;
• Details supporting the addition of approximately $14.3 million to the deferral
balance, including $4.0 million customers' share of ECAM costs, $5.4 million
Painter, Di-I
Rocky Mountain Power
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
Q.
A.
Q.
A.
Lake Side 2 Resource Adder, a $0.1 million increase in renewable energy
production tax credits ("PTCs"), $4.4 million resource tracking mechanism
("RTM") deferral, $9 thousand renewable energy credit ("REC") revenue
differential, and $0.6 million interest accrued;
• Discussion of the main differences between adjusted actual net power costs
("Actual NPC") and net power costs in rates ("Base NPC"); and,
• Discussion about the Company's participation in the energy imbalance market
("EIM") with the California Independent System Operator ("CAISO") and the
benefits from EIM that are passed through to customers.
What other witnesses present testimony for the ECAM and Tariff Schedule 94 in
this case?
Mr. Robert M. Meredith, Director, Pricing and Cost of Service, provides testimony on
the proposed rates in Electric Service Schedule No. 94, Energy Cost Adjustment
("Schedule 94") and Mr. Steven R. McDougal, Director, Revenue Requirement,
provides testimony on the RTM.
SUMMARY OF THE ECAM DEFERRAL CALCULATION
Please briefly describe the Company's ECAM authorized by the Commission.
In general, the ECAM tracks deviations between Actual NPC and Base NPC and defers
90 percent of the difference for later recovery. 1 Other items, described in detail later in
my testimony, are also tracked in the ECAM to true-up the amount in base rates to
actuals. These items include a resource adder for the Lake Side 2 gas generation plant,
PTCs, RTM deferral, and revenues from the sale of RECs. 2 The balance that
1 See Order No. 30904 in Case No. PAC-E-08-08 and Order No. 33440 in Case No. PAC-E-15-09.
2 See Order No. 33440 in Case No. PAC-E-15-09 pages 5--6.
Painter, Di-2
Rocky Mountain Power
1
2
3
4
5
6
7
8 Q.
9 A.
10
11 Q.
12 A.
13
14
15
accumulates over a deferral period is then passed on to customers as a rate surcharge
or credit. Schedule 94, described in Mr. Meredith's testimony, appears as a separate
line item on customer bills, collects from or credits to customers the balance of deferred
costs. Schedule 94 is adjusted as needed in the Company's annual ECAM filings.
The Company is required to file an application with the Commission annually
by April 1st to seek approval of the deferral amount and the new Schedule 94 rate, which
becomes effective June 1st•
Are there any changes to the ECAM calculation?
No.
ECAM DEFERRAL CALCULATION
Please describe the calculation of the ECAM deferral included in this filing.
Table 1 provides a summary of the total ECAM deferral and a breakdown of the
individual components of the ECAM. Exhibit No. I presents the aetailed calculation of
the ECAM deferral on a monthly basis .
Table 1 -2020 ECAM Deferral
NPC Differential for Defeirnl
EllF 04-6 Adjustment
LCAR
Total Defeirnl Before Sharing
Sharing Band
Customer Responsibility
Lake Side 2 Resource Addei·
Production Tax Credits
RlM Adjustment
REC Defei1-al
Interest on Defeirnl
Anmial Defeirnl (Jan -Dec 2020)
$ 5,656,015
(127,464)
(1,076,170)
4,452,381
90%
4,007,143
5,431,705
(100,831)
4,431,885
8,557
562,667
14,341 ,126
Painter, Di-3
Rocky Mountain Power
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
Q.
A.
Q.
A.
The first section of Table 1 summarizes the Idaho-allocated share of those items
for which Idaho customers and the Company share responsibility, including: NPC
differential, EITF 04-6 adjustment, and load change adjustment revenue ("LCAR")
costs. The next section calculates the 90 percent customers' share of the items above
and adds the following items which are refunded or collected in full (i.e., 100 percent):
the Lake Side 2 resource adder, PTCs, RTM deferral, REC revenues, and interest on
the deferral. The total of these items equals the ECAM deferral.
Does this filing reflect the regulatory asset associated with the 2013 Depreciation
Study?
Yes. In Case No. PAC-E-18-01 , the Commission ordered the Company to include the
depreciation regulatory asset created in Case No. PAC-E-13-02 in future Idaho ECAM
filings. As seen in Exhibit No. 1, the beginning balance, monthly deferral, and monthly
amortization are included as part of the ECAM deferral balance.
Based on your calculations, what is the balance expected to be in the ECAM
deferral account as of June 1, 2021?
The projected balance in the ECAM deferral account as of June 1, 2021 is
approximately $16.1 million. Table 2 summarizes the ECAM balancing account
activity starting with the December 2019 ECAM deferral balance of $27.3 million
approved in Case No. PAC-E-20-02. Approximately $14.3 million is added to the
balance from the annual deferral and interest during the Deferral Period, offset by $18.4
million of ECAM revenue collections. Table 2 then summarizes the depreciation
regulatory asset balance activity; the sum of the two is the balance for collection as of
December 31 , 2020.
Painter, Di-4
Rocky Mountain Power
1 Table 2 -Balancin Account Activi
ECAM Deferral Balance
Deferral Balance -Dec 31 , 2019 $ 27,286,382
Annual Deferral (Jan -Dec 2020) 13,778,459
Interest 562,667
ECAM Revenue Collection -Schedule 94 {18,416,430)
Activity Through December 31, 2020 $ 23,211 ,078
Depreciation Regulatory Asset Balance
Beginning Balance $ (76,878)
Annual Deferral (Jan -Dec 2020) 2,039,800
ECAM Revenue Collection -Schedule 94 (2,113,434)
Activity Through December 31, 2020 $ (150,512)
December 31, 2020 Balance For Collection $ 23,060,567
Schedule 94 Collection -Jan -May 2021 $ (6,994,766)
Interest 81,345
Expected Balance as of June 1, 2021 $ 16,147,146
2 Q. Please describe the ECAM calculations in Exhibit No. 1.
3 A. The ECAM deferral is calculated by comparing Idaho-allocated Actual NPC to the
4 NPC collected in rates on a monthly basis and deferring the differences into an ECAM
5 balancing account. Exhibit No. 1 includes details of the ECAM calculation. I have also
6 provided confidential work papers supporting this exhibit.
7 Q. How are the Base NPC and Actual NPC calculated?
8 A. The monthly Base NPC collected in rates, as set forth in Exhibit No. 1 line 6, is
9 calculated by taking the dollar-per-megawatt-hour Base NPC rate multiplied by the
10 actual Idaho retail sales. The Actual Idaho NPC, as set forth in Exhibit No. 1 line 15, is
11 calculated by dividing the monthly total Company Actual NPC in the Deferral Period
12 by the actual monthly system megawatt-hours ("MWh") in the Deferral Period. The
13 total Company Actual NPC dollar-per-megawatt-hour basis is then multiplied by Idaho
Painter, Di-5
Rocky Mountain Power
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
Q.
A.
Q.
A.
actual monthly MWh to calculate Actual Idaho NPC.
Please describe how the NPC deferral is calculated.
The deferral is calculated on a monthly basis by subtracting the Base NPC collected in
rates from the Actual Idaho NPC. For the Deferral Period, the NPC differential was
$5.7 million before applying the 90 I IO percent sharing.
What costs are included in the NPC differential for deferral?
The NPC differential for deferral captures all components of NPC as defined in the
Company's general rate case proceedings and modeled by the Company's production
dispatch model the Generation and Regulation Initiative Decision Tool ("GRID").
Specifically, Base NPC and Actual NPC include amounts booked to the following
FERC accounts:
Account 44 7 -Sales for resale; excluding on-system wholesale sales and other
revenues that are not modeled in GRID
Account 501 -Fuel, steam generation; excluding fuel handling, start-up fuel
(gas and diesel fuel, residual disposal), and other costs that are
not modeled in GRID
Account 503 -Steam from other sources
Account 54 7 -Fuel, other generation
Account 555 -Purchased power; excluding the Bonneville Power
Administration ("BPA") residential exchange credit pass­
through if applicable
Account 565 -Transmission of electricity by others
Painter, Di-6
Rocky Mountain Power
1 Q.
2 A.
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
Are adjustments made to the Actual NPC before comparing them to Base NPC?
Yes. The Company adjusts Actual NPC to reflect the ratemaking treatment of several
items, including:
• out of period accounting entries booked in the Deferral Period that relate to
operations before implementation of the ECAM on July 1, 2009;
• buy-through of economic curtailment by interruptible industrial customers;
• revenue from a contract related to the Leaning Juniper wind resource;
• situs assignment of the generation from Oregon solar resources procured to
satisfy Oregon Revised Statute ("ORS") 757.370 solar capacity standard;
• situs assignment of Oregon allocated amortization related to a prepaid
wheeling expense;
• situs assignment of certain Utah solar resources and Schedule 32 and 34
contract costs;
• coal inventory adjustments to reflect coal costs in the correct period;
• legal fees related to fines and citations included in the cost of coal;
• adjustments related to liquidated damages that occurred outside the Deferral
Period (all liquidated damage fees per a coal supply agreement are booked
in accordance with generally accepted accounting principles ("GAAP"));
• situs assignment of Reasonable Energy Price adjustments to qualifying
facilities ("QF"); and,
• an adjustment for reclassification of wholesale sales revenue above the
FERC price cap. Sales pending refund are accounted for in FERC Account
449, a non-regulatory NPC account instead ofFERC Account 447. Because
Painter, Di-7
Rocky Mountain Power
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
Q.
A.
Q.
A.
Q.
A.
this transaction is recorded in a non-NPC account and the wholesale sales
revenue is recorded in FERC Account 44 7, the adjustment should be
included in the 2021 ECAM to align the pending refund with the matching
sales revenue in accordance with GAAP.
Why is the July 1, 2009 cutoff used to determine out of period entries?
Since the ECAM took effect, customers' rates have been adjusted to recover essentially
all of the Company's actual net power costs, excluding any differences due to the 90 I
10 percent sharing band. Consequently, any accounting entries made during the current
Deferral Period that relate to any operating period since the ECAM took effect, should
also be reflected in customer rates, whether they increase or decrease Actual NPC.
Accounting entries related to operating periods before the inception of the ECAM
should not impact the ECAM deferral.
In addition to comparing Actual NPC to Base NPC, what other components are
included in the ECAM?
Six additional components are included in the ECAM calculations: (i) an adjustment
for deferred costs associated with coal mine stripping activities recorded under the
Financial Accounting Standards Board ("FASB") EITF 04-6; (ii) the LCAR
adjustment; (iii) a resource adder to collect the investment in the Lake Side 2 natural
gas generation facility; (iv) a true-up of PTCs; (v) the resource tracking mechanism
deferral; and (vi) a true-up of REC revenues as authorized in Order No. 32196.
How is the adjustment for accounting pronouncement EITF 04-6 included in the
ECAM?
The calculation of coal stripping costs on Line 17 of Exhibit No. 1 reflects Idaho's
Painter, Di-8
Rocky Mountain Power
I
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
Q.
A.
Q.
A.
allocated differences between the coal stripping costs incurred by the Company during
excavation and recorded on the Company's books pursuant to the guidance of the
accounting pronouncement EITF 04-6, and the amortization of the coal stripping costs
as approved by the Commission in Case No. PAC-E-09-08, Order No. 30987. For the
Deferral Period, the total EITF 04-6 coal stripping deferral adjustment is a $0.1 million
decrease to the ECAM deferral balance before the 90 / IO percent sharing.
Please describe the LCAR adjustment.
The calculation of the LCAR adjustment is a symmetrical adjustment for over-or
under-collection of the energy-related portion of the Company's embedded revenue
requirement for production facilities as specified in Case No. GNR-E-10-03, Order No.
32206. The LCAR accounts for variances in Idaho load that cause the Company to
collect more or less of these production-related costs. The LCAR rate of $5 .54 per
MWh is used for the Deferral Period.
How is the LCAR adjustment calculated and what impact does it have on the
Deferral Period?
The LCAR adjustment assumes that the actual production-related costs of the LCAR
are equal to base, Exhibit No. l line 18. The actual production-related costs are then
compared to the LCAR revenue collection in rates, calculated by multiplying the LCAR
rate by the actual Idaho retail sales, Exhibit No. I line 21. The LCAR adjustment is the
difference between the actual production-related costs and the LCAR revenue, line 22
of Exhibit No. l, and is a $1 . l million decrease to the ECAM deferral balance before
the 90 / IO percent sharing.
Painter, Di-9
Rocky Mountain Power
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
Q.
A.
Q.
A.
Q.
A.
Please explain the sharing ratio between the Company and customers in the
ECAM.
The ECAM includes a symmetrical sharing ratio in which customers either pay or
receive 90 percent of the ECAM deferral balance, and the Company is responsible for
the remaining 10 percent. Line 24 of Exhibit No. 1 represents the customers' 90 percent
share of the monthly deferral shown on line 23 of Exhibit No. 1. For the Deferral
Period, the customers' share of the deferred balance is $4.0 million. The remaining
balance of$0.4 million associated with the Company's 10 percent share is not included
in the deferral balance as it is not recoverable from customers.
What is the amount of the Lake Side 2 resource adder in the current filing?
Pursuant to the stipulation in Case No. PAC-E-13-04, approved by Commission Order
No. 32910, the Company included a resource adder to recover the investment in the
Lake Side 2 generation plant which is not yet included in base rates. The resource adder
amounts to $1.99/MWh of the Lake Side 2 generation capped at 2,729,500 MWh or
$5.4 million for the calendar year. The total Lake Side 2 resource adder on line 27 of
Exhibit No. 1 for the Deferral Period was $5.4 million based on 3,171,917 MWh of
generation, but limited to 2,729,500 MWh due to the cap.
What is the amount of the PTC true-up in the current filing?
The PTC Deferral, on line 32 of Exhibit No. 1, is calculated by comparing the actual
Idaho-allocated PTC to the PTC customers receive through base rates. The PTC credit
in base rates is calculated by multiplying the approved PTC rate of $1.99/MWh by
Idaho retail sales. The difference is a $0.1 million decrease to the ECAM deferral.
Painter, Di-I 0
Rocky Mountain Power
I
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
Q.
A.
Q.
A.
Q.
A.
Q.
A.
Q.
A.
Please explain the RTM deferral.
The RTM deferral, on line 33 of Exhibit No. 1, is calculated per Exhibit No. 4 described
in Mr. McDougal's testimony. The RTM deferral during calendar year 2020 is
$4.4 million.
What is the amount of REC revenue adjustment in the current filing?
The REC revenue adjustment, on line 38 of Exhibit No. 1, is calculated by comparing
the actual Idaho-allocated REC revenue to the REC revenue credit customers receive
through base rates. The REC revenue credit in base rates is calculated by multiplying
the approved REC revenue rate of $0.09/MWh by Idaho retail sales. The difference is
a $9 thousand increase to the ECAM deferral.
What is the total ECAM deferred balance calculated in Exhibit No. 1?
The total ECAM deferred balance as of December 31, 2020 is $13.8 million, shown on
line 39 plus $563 thousand of interest on line 48 of Exhibit No. 1, for a total deferral
of $14.3 million.
Does the calculation of the ECAM deferral in this application comply with the
parameters of the Idaho ECAM as approved by the Commission?
Yes. Therefore, the Company recommends the Commission approve the ECAM
application for recovery of the $14.3 million prudently incurred ECAM costs.
DIFFERENCES IN NPC
On a total-Company basis, what was the difference between Actual NPC and Base
NPC for the Deferral Period?
On a total-Company basis, Actual NPC for the Deferral Period were $1.512 billion,
exceeding Base NPC for the Deferral Period by $27 million. Table 3 provides a high-
Painter, Di-11
Rocky Mountain Power
2
3
4 Q.
5
6 A.
7
8
9 Q.
10 A.
11
12
13
14
15 Q.
16 A.
level summary of the difference between Base NPC and Actual NPC by category on a
total-Company basis.
Table 3 -Net Power Cost Reconciliation($ millions)
TOTAL
Base NPC $ 1,485
Increase/(Decrease) to NPC:
Wholesale Sales Revenue 161
Purchased Power Expense 39
Coal Fuel Expense (149)
Natural Gas Expense (22)
Wheeling and Other Expense (3)
Total Increase/(Decrease) $ 27
Adjusted Actual NPC $ 1,512
Please describe the Base NPC the Company used to calculate the NPC component
of the ECAM deferral.
The Base NPC were set m Case No. PAC-E-16-12 and became effective
January 1, 2017. Base NPC used the 12-month test period of January 2016 through
December 2016 and set total-Company Base NPC at $1.485 billion.
Please describe the primary differences between Actual NPC and Base NPC.
From an accounting perspective, and as shown in Table 3, Actual NPC were higher than
Base NPC due to a $161 million reduction in wholesale sales and a $39 million increase
in purchased power expense. The items were partially offset by a $149 million
reduction in coal fuel expense, a $22 million decrease in natural gas expense, and a
$3 million decrease in wheeling and other expenses.
Please explain the changes in wholesale sales revenue.
Wholesale sales revenue declined relative to Base NPC due to higher market prices and
Painter, Di-12
Rocky Mountain Power
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
Q.
A.
Q.
A.
a reduction in the wholesale sales volume of market transactions (represented in GRID
as short-term firm and system balancing sales).
Of the $ 161 million decrease to wholesale sales, revenue from market
transactions represents the largest change to Base NPC. Market transactions are
$ 141 million lower than Base NPC due to higher market prices and lower volume of
market sales transactions. The average price of actual market sales transactions was
$11.46/MWh, or 49 percent, higher than the average price in Base NPC. Actual
wholesale market volumes were 8,353 gigawatt-hours ("GWh"), or 64 percent, lower
than the Base NPC. In addition, an expired contract accounted for $9 million of the
decrease in wholesale sales revenue.
Please explain the changes in purchased power expense.
Purchased power expense increased by $39 million with a $116 million increase
(54 percent) in QF transactions as the most significant driver, partially offset by the
expiration of a long-term purchase power contract. Actual QF transaction volumes were
1,884 GWh (53 percent) higher than Base NPC. The expiration of the Hermiston
purchase power agreement ("PPA") reduced purchased power costs by $31 .3 million.
Additionally, expenses from market transactions (represented in GRID as short­
term firm and system balancing purchases) decreased by $33.5 million compared to
Base NPC. Actual market purchases were 3,327 GWh (46 percent) lower than Base
NPC, but the average price of actual market purchases transactions was $12.95/MWh
(52 percent) higher than Base NPC.
Please explain the changes in wheeling expenses.
Actual long-term wheeling expenses decreased by $11.5 million when compared to
Painter, Di-13
Rocky Mountain Power
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
Q.
A.
Q.
A.
Q.
A.
Q.
A.
Base NPC but were offset by an increase of $ 12.1 million of short-term wheeling
expenses for a net increase of $0.6m.
Please explain the changes in coal fuel expense.
Coal fuel expense decreased because coal generation volume decreased 8,465 GWh
(22 percent) compared to Base NPC. The average cost of coal generation increased
from $19.96/MWh in Base NPC to $20.62/MWh in the Deferral Period, but the lower
generation volume results in an overall decrease of $149 million in coal fuel expense.
Please explain the changes in natural gas fuel expense.
The total natural gas fuel expense in Actual NPC decreased by $22 million compared
to Base NPC mainly due to a decrease in average cost of natural gas generation from
$23.06/MWh in Base NPC to $21.85/MWh in the Deferral Period. Additionally, there
was a decrease in gas generation volumes of 307 GWh (three percent).
IMPACT OF PARTICIPATING IN THE EIM
Are the actual benefits from participating in the EIM with CAISO included in the
ECAM deferral?
Yes. Participation in the EIM provides benefits to customers in the form of reduced
Actual NPC. The EIM benefits are embedded in Actual NPC through lower fuel and
purchased power costs. The Company is able to calculate the margin realized on its
EIM imports and exports, the inter-regional benefit. The Company's EIM inter-regional
benefit for the deferral period was $46.8 million.
How does the Company calculate its actual EIM benefits?
Using actual information from the EIM, including five-and 15-minute pricing, the
Company identifies the incremental resource that could have facilitated the transfer to
Painter, Di-14
Rocky Mountain Power
1
2
3
4
5
6 Q.
7 A.
8
9
11 Q.
12 A.
an adjacent EIM area or the CAISO in each five-minute interval. The benefit is then
calculated as the difference between the revenue received less the expense of generation
assumed to supply the transfer. In the event of an import, the benefit is equal to the cost
of the import minus the avoided expense of the generation that would have otherwise
been dispatched.
Please summarize your testimony.
The ECAM deferral of $14.3 million, including interest, for the Deferral Period, was
accurately calculated in compliance with previous Commission orders. Therefore, I
respectfully request that the Commission approve this application as filed with rates
effective June I, 2021 .
Does this conclude your direct testimony?
Yes.
Painter, Di-15
Rocky Mountain Power
Case No. PAC-E-21-09
Exhibit No. 1
Witness: Jack Painter
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Jack Painter
March 2021
klaho En.rgy Cost Ad Ju st met Mechanism Dtferr,
January 1, 2020 -December 31, 202<
Lino No.
ID Base NPC Embedded in Rates (S
Arnua1 Idaho BHe Load @ meter (M'Mi
NPC Rate Embedded in Base Rates ($JM'Mi
NPC Rate Embedded in Base Rates ($1M'Mi
ID Actual Sa}e1 0 Meter (MIMl)
ID NPC Colecled in Rates ($
PAC-E-16-12
PAC-E-16-12
Une1/Une:.
Une3
Une ◄xUne~
7 Total Company Adjusted Actual NPC Exd. Integration Adj. (S Ad_iusted Actual NPC
6 Intra-Hour Wird Integration Colt ($JM'Mi:
9 Third Party Wind Sold to W'tolesale (M'M'I:
10 Third Party Wind Adjustment ($)
11 Total Company Adjusted Actual NPC ($
12 Total Company Load@ lnpi.i (Mlfo.lh
13 Actual NPC (SIM'M'I)
14 ID Actual Load @ lnplA (MW,)
15 Actual ID NPC
16 NPCOifferentia
EITf 04-8 AdJustrMn1
17 Idaho .AJloeated EITF 04.6 Deferral Adjustment (S
LCAR
Note(1)
Une6xUneS
Line 7-Line 1C
Line 11 I Line 1~
Une13xUne1i
Une15-Unef
16 Act\lal Idaho Jurisdictional ECPC minus NPC (Assume Actual • PAC-E-16-12
19 LCAR Rate@ Meter ($/MW'!)
20 ID Actual Sales ct Meter (M'Mi) 21 LCAR Revenue Collected ttvough Base RalH (S
22 LCAR Adjustment
ECAM Deferral
PAC-E-16-12
UneS Une19xUne2C
Line 18-Line21
23 Total ECAM Deferral (NPC Deferral, EITF 04-6Adjustment. LC.t&..nof Lines: 16, 17, 2:. 24 Total ECAM Deferral •fl•r to% Shartn, Line 23 x 90%
Lakeside 2 R1t1ource Adde1
25 Lake Side 2 Generation (M'Mi
26 RelOUl'ce Adder Rate ($/MW'I)
'27 Tot•I Lake Side 2 Resource Adder (S
Production Tax CNdNs IPTCs]
26 ID Alocated PTC1 in Ratn (SIMVvh:
29 IDActt.a1Sale1@Meter(MW'I)
30 ID PTCs in Rates($)
31 ID Alocated Actual PTC1 ($'
32 ID PTC1 Deferral ($)
RTM Adjustment
33 ID RTM Adjustment ($)
R.newabh Ene,gy CrMtts (RECI Rewnu1
3◄ ID REC ReveNJe in Rates (SIMW'I:
35 ID Actual Sales ct Meter (MW'!)
36 ID REC Revenue in Rates ($
37 ID Alocated Actual REC Revenue (S 38 REC Revenue Adjuslm♦r. (S'.
39 Total Deferral
40 lnterestRate
ECAM Balanclng Account (S
◄1 Beginning Balan« ◄2 ECAM Deferral After Sharini; 43 lake Side 2 Resource Adda
44 PTC1 Deferral
45 RTM Adjustment
◄6 REC Revenue Adjustmeni ◄7 Less: Monthly ECAM Rider Revenues alocated to ECAl ◄6 Interest
49 ECAM Def•rral Balance ISi
Depreciation Regulatory Asset Balanclng Account 1:
Adjusted Actual NPC
PAC-E-13-0◄
Une25xUne2f
PAC-E·16-12
Lines
Line 28x Line~
Une31-Line3C
PAC-E·16-12
UneS
Line 3◄ x Line 3~
Line 37 • Line 3f
&Im of Lines 24. 'ZT. 32.33, 3f
Order No. 3420,4
Une2◄
Une'27 Une32
Une33
Une38
CY2011 =:m 3.407.486
26.90
Jan-20 -253.898 s;m:l"lo
, ..... -24◄.010 =
_.,. -213,50◄ ~
Af.f..Z0 2"-00
213,460 ~
M•~
306,791 =
Ji,n-20 -388.28< ~
Jul-Z0 -432,246 ~
A~..Z0
26.90
379,685 ~
.. ~
285,◄14 ,:m:m
Oct-,0 -263.264 -r:r;Ni:rr,1
Nov-lO -236,057 ~
DK-20 -303.734 s.m:m
Exhlbtt No.1
Total
~
S 123.339,662 S 122,232.768 $ 127,063,155 $ 104,812,359 S 111.412,548 $ 123,937,016 S 156.◄74.32◄ S 153.659,771 S 122,655,657 S 121.105,556 S 11◄,802,163 S 130,567.758 S 1,512,063,197
0.39 S
171.547 66,227
0.39 $
129,482 ~
0.39 $
119.032 ~
0.39 S
104,396 ~
0.39 S
100.976 ,a:98'i
0.39 S
94_,_◄79 ~
0.39 S
67_,_369
33.729
0.39 S
61,043 ~
0.39 S
61,221 ms.
0.39 S
137,066 ~
0.39 S
1'27.896 49.ffl
0.39
100_,_655
38,659
S 123,273,655
5,157,135 S 122,182.600 4,726,803
S 127,017,201
4,695,650
s 104,m,056
4.166,661
S 111,373,565
'4,395.668
S 123,900,541
4,728,05◄
S 156,440,595
5,569,932 S 153.628,◄8◄ 5,673,186 S 122,62◄,501 4,657,759 S 121,052,6◄1 ◄ ,586,289
$ 114,752,8013
◄,767.808 S 130,5◄8.699
5.294,469 = 31◄,197 r.s,o,.ii9 -= 297,016
7,677,543
UIUH
IDiS"
2◄1_,_624
6,535.636
m;m
= 235.623
5.924.812 -= 355_,_265
9,001.401 -= -406,911 ~
mm
= 469_,_168
13.130,751 =
~
378L03()
10.236,972
n;m
= 301.857
7,946,972 S
m;m
= 283_,_711
7,488,400
mm
= 270Ln3
6,517.022
m;m
24.66
314,660
7.758.762
im;mJ
2,711 i (!l,302) i (12,410) i (17,!li!I) i 126,376) i 167,Joij i iU,111) i 134,C!IJ) i il!l,123) i !10,Jz!I i 24,Jti i 22,!IZi
$ 1,536,179 $ 1,536,179 S 1,536,179 S 1,536.179 $ 1,536.179 $ 1.536.179 S 1,536,179 S 1,536,179 S 1,536,179 $ 1,536,179 S 1,536.179 S 1.536,179
$
s
5.54 S
253.898 = m;m
61◄_,_260
199,759
1.99 mm
(1.99) S
253.898
(506,216) s
ITTi::f.l I
m;,rT7'
(0.09) S
253.898 (22.785) S
52,729 7!1,!U $
UR.Rt$
200%
27,286,382 S
73283o4
397,520
(198,669)
2.69.7fil
75,51◄
(649.362) ◄6,017
27,980,004 S
5.54 S
24◄,010 = -
304,612
1.99 m;m
(1.99) $
24◄.010 (486,500) S
iFJ:mi s
m;m,
(0.09) S
244.010 (21,898) $
!796) 21,1or s
1,934,585$
200%
27,980,00◄ S
1,16◄,630
606,178
(18◄.505)
327,150
21,102
(1,059,802)
47.362
21,902,120 S
5.54 $
213,50◄ = mm
334.338
1.99 m:m
(1.99) $
213,50◄ (◄25,678) J 1~-::m1 s
m;m.
(0.09) S
213,50◄ (19,160) S
~;~His
1,IJUUJ i
200%
28,902,120 S
1,020,988
665.333 (188,577)
389,170
(55,◄12)
(967.13◄) ◄6,691
21,115,379 S
5.54 S
213,◄60 = m:m
232.6◄9
1.99 mm
(1.99) S
213,460 (◄25,590) S
1~H:Si s
5.54 S
306,791 rnl!f.m
im:mn
560_,_53◄
126,03◄
1.99 -(1.99) S
306,791
(611.671) s
'm:UW s
5.54 $
388.28-1 = im:mrr
'61
25Z268
1.99 m;m
(1.99) S
388.28-4 (77◄,150) J <m:m> s
5.54 S
432,2◄6 = im:mn
329,456
1.99 mm
(1.99) S
432,2◄6
(661,800) J
(469,805! 391,115 $
Hi,zil i 311,U) $ 310,tit i 372,111 i
(0.09) S (0.09) S (0.09) S (0.09) S
213,◄60 306,791 388.28-1 432:,2◄6 (19.156) S (27,532) $ (34.846) S (38,791) S
i2i:*iii $
17,625 ~i;;~ $ (963) U,357 $ Jr,Hr $
1,2'11,J!IS J uu:113 1 IR,!151 $ UR.mi
2.00% 2.00% 200% 200%
29,615,379 S 30,286,607 S 30,693,6◄6 S 29,623,063 S
467,930 50◄,◄81 (◄15,550) 538.637
462,9n 250.806 502,013 655,617
(95,653) 123,555 219,921 391,995
396,281 368.483 360.7ll9 372,186
(26,976) ◄5,357 32,37◄ 37.806
(783,170) (938,219) (1,620.711) (2,646,◄67)
50.045 50.m 50.389 49,163
30,211,107 S S0,693,141 S 29,123,013 S 29,222,003 S
5.54 S
379.685 = ~
359,671
1.99 m;m
(1.99) S
379.685
(757,006) J
(384,2◄1! 372,766 $
5.54 S
285,◄1◄ = iw.mTT
282,210
1.99 m;m-
(1.99) S
285,◄1◄
(569,051) s
(436,1◄2) 132,909 $
5.54 S
263.264 = '7T,m
536_,_003
265.1)()6
1.99 m;m
(1.99) S
263.264 (52◄,889) S <j:}J:~1 $
5.54 S
238.057 = m;m
356L278
43,497
1.99 11:m
(1.99) S
238.Cfil (◄7◄,631) J
ITT:;fili $
340,Jtt i S47,7U i Ut7!1t i :HO,oii i
(0.09) $ (0.09) S (0.09) S (0.09) S
379.685 285,◄1◄ 263.264 238.057 (34,074) $ (25.614) $ (23,626) S (21,364) S
386 21J~l s i~:~ls 1~;~:r~ s u;:ao s
Rt:!111 $ 1J!l7~1'1 $ 1.ffl,!121 $ 377,JR I
200% 200% 200% 2.00%
29,222,003 S 27,722,357 S 26,939,607 S 26,597,266 S
(518,832) 169,631 482,◄03 320,650
715,745 561,598 5'27,362 86.559 372,7fi£J 132.909 (97,092) (249,646)
3◄0,3n 3◄7,76◄ 45'.757 390.068
34.460 25.575 (20,909) (170,277)
(2,◄91,576) (2,085,740) (1,733,◄39) (2,368,5&4) 47,◄1◄ ◄5,51-4 4".577 ◄2,669
27,722,357 S H,931,107 S 21,517,211 S 24,141,725 S
....
303.734 = iw.m,
534,
1.99
(1.99)
303.73'
(605,577) 1;~:~s:1 -(0.09)
303.73' (27,258)
!17,319) 1,1!1
~.2711
200%
24,648,725
(◄80,660)
(327.635)
393.065
9.939
(1,072,226)
39.850
23,211,071
~
$ 1,511,567,747
58,◄39,613 ~
100,391,959
t;m;m
jT!T,fflf
18,◄34,143
= JT,m;mf
◄.452.381 4,007,143
~
lffif,ffll
u,ir,m
J;m
u,m,m
23,211,071
rn () X ;o <:D> 2:o ~;g3-
l): ~ ~ s::: ~ ~ :_ g lir ►-o:a. n00>0> ~'71~ s·
D> N-. '1J -·-. 0 ;-oa~ -, <O -. -,
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF ROCKY MOUNTAIN POWER
REQUESTING APPROVAL OF $16.1
MILLON NET POWER COST DEFERRAL
) CASE NO. PAC-E-21-09
)
) DIRECT TESTIMONY OF
) ROBERT M. MEREDITH
ROCKY MOUNTAIN POWER
CASE NO. PAC-E-21-09
March 2021
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
Q.
A.
Q.
A.
Q.
A.
Q.
A.
Please state your name, business address and present position with PacifiCorp,
dba Rocky Mountain Power ("the Company").
My name is Robert M. Meredith. My business address is 825 NE Multnomah Street,
Suite 2000, Portland, Oregon 97232. My present position is Director, Pricing and Cost
of Service.
Qualifications
Briefly describe your educational and professional background.
I graduated from Oregon State University with a Bachelor of Science degree in
Business Administration and a minor in Economics. In addition to my formal
education, I have attended various industry-related seminars. I have worked for the
Company for 16 years in various roles of increasing responsibility in the Customer
Service, Regulation, and Integrated Resource Planning departments. I have over 10
years of experience preparing cost of service and pricing related analyses for all of the
six states that PacifiCorp serves. In March 2016, I became Manager, Pricing and Cost
of Service. In June 2019, I was promoted to my current position.
Have you testified in previous regulatory proceedings?
Yes. I have previously filed testimony on behalf of the Company in regulatory
proceedings in Idaho, Utah, Wyoming, Oregon, Washington and California.
What is the purpose of your testimony in this proceeding?
My testimony presents and supports the Company's proposed rates to recover the 2020
Energy Cost Adjustment Mechanism ("ECAM") deferral balances through Electric
Service Schedule No. 94 -Energy Cost Adjustment ("Schedule 94").
Meredith, Di-I
PacifiCorp
1 Background
2 Q. What level of revenues is Schedule 94 currently designed to collect?
3 A. Schedule 94 is currently designed to collect approximately $19.2 million-$7.7 million
4 for Tariff Contract 400, $0.6 million for Tariff Contract 401 , and $11.0 million for the
5 standard tariff customers-based on Idaho loads from Case No. PAC-E-15-09.
6 Proposed Rate Change for Schedule 94
7 Q.
8 A.
9
10
11
12
13
14
15
16
17 Q.
18 A.
19
20 Q.
21 A.
22
Please describe the Company's proposed rate change in this case.
The 2020 ECAM application proposes to decrease Schedule 94 rates to recover
approximately $16.1 million from June I , 2021 to May 31, 2022. The $16.1 million
includes $14.4 million for the 2020 ECAM Deferral, plus approximately $8.9 million
remaining from the 2019 ECAM balance, for a total balance of $23.2 million as of
December 31, 2020. This is offset by a net credit of $150,512 in the depreciation
regulatory asset balance and $6.9 million Schedule 94 forecasted revenue collection
from January I , 2021 through May 31, 2021, as shown in Table 2 of Mr. Jack Painter's
testimony. Mr. Painter explains in his testimony the components of the 2020 ECAM
deferred balance.
Please explain the proposed rate change for Tariff Contracts 400 and 401.
The proposed rate for Tariff Contracts 400 and 401 is the same as for standard tariff
customers with transmission delivery service voltage.
What is the impact of the proposed ECAM rates?
As summarized in my Exhibit No. 2, these rate change proposals result in a decrease
of 1.3 percent for Tariff Contract 400 and Tariff Contract 401. Standard tariff customers
Meredith, Di-2
PacifiCorp
will also see an average decrease of 0.9 percent, or $1.8 million.
2 Calculation of Proposed Rates for Schedule 94
3 Q.
4 A.
5
6
7
8
9
10
11
12
13
14 Q.
15 A.
16
17 Q.
18 A.
19
20
21 Q.
22 A.
How were the proposed Schedule 94 rates developed for all customers?
The proposed rates for all customers were developed in four steps. First, I developed
their kilowatt-hour ("kWh") consumption at the generation level by multiplying their
retail loads at the delivery service voltage level with the corresponding line loss factors.
Next, an overall average rate at the generation level was developed by dividing their
total collection target identified above with their kWh consumption at the generation
level. Finally, rates by delivery voltage level were developed by multiplying the above
overall average rate at the generation level with the corresponding line loss factors. As
a result, the Company proposes Schedule 94 rates of 0.477, 0.461 and 0.449 cents per
kWh for secondary, primary and transmission delivery service voltages, respectively,
for all customers.
Please describe Exhibit No. 2.
Exhibit No. 2 shows the 2014 loads used to develop rates, the line loss adjusted loads,
the allocation of the ECAM price change, and the percentage change by rate schedule.
Please describe Exhibit No. 3.
Exhibit No. 3 contains clean and legislative copies of the proposed Electric Service
Schedule No. 94, Energy Cost Adjustment. The Company requests that the proposed
Schedule 94 rates become effective on June 1, 2021.
Does this conclude your direct testimony?
Yes.
Meredith, Di-3
PacifiCorp
Case No. PAC-E-21-09
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 2021
Average Line
No. Description Sch. Cust
(I) (2) (3)
Residential Sales
1 Residential Service
2 Residential Optional TOD
AGA Revenue
4 Total Residential
5 Commercial & Industrial
6 General Service -Large Power
7 General Svc. -Lg. Power (R&F)
8 Subtotal-Schedule 6
9 General Service -High Voltage
IO Irrigation
11 Comm. & Ind. Space Heating
12 General Service
13 General Service (R&F)
14 Subtotal-Schedule 23
15 General Service Optional TOD
16 Special Contract I
17 Special Contract 2
I 8 AGA Revenue
36
6
6A
9
10
19
23
23A
35
400
401
46,059
13,484
59,543
1,036
214
1,250
17
4,969
103
6,634
2,314
8,948
3
EXHIBIT NO. 2
ESTIMATED IMPACT OF PROPOSED ECAM ADJUSTMENT
FROM ELECTRIC SALES TO ULTIMATE CONSUMERS
DISTRIBUTED BY RATE SCHEDULES IN IDAHO
HISTORIC 12 MONTHS ENDED DECEMBER 2014
Present
Rev
At Meter At ECAM Proposal Present
MWH
(4)
442,589
235,152
677,741
303,011
30,600
333,611
121,001
602,488
5,151
153,848
33,450
187,299
1,893
1,443,926
107,486
($000)
(5)
$49,602
$22,484
$3
$72,090
$23,667
$2,616
$26,283
$7,626
$54,316
$438
$14,913
$3,376
S/8,289
$123
$86,967
$6,264
$478
MWh by Voltage Generation ~ Rate ¢/kWh ECAM Rev Net Change
_s ____ P__ T MWh ~ _s __ P __ T_ ($000) ~ ~
(6) (7) (8) (9) (IO) (II) (12) (13) (14) (15) (16)
442,589
235,152
677,741
258,477
30,600
289,077
602,488
5,151
152,484
32,839
185,323
1,893
0
44,534
U.534
1,364
611
1,975
0
0
121,001
0
1,443,926
107,486
487,503
259,016
$2,113 0.477 0.461 0.449
$1,123 0.477 0.461 0.449
746,519 $3,235 ------
332,125
33,705
365,830
125,363
663,629
5,674
169,411
36,822
206,233
2,085
1,495,980
111,361
$1,439 0.477 0.461
$146 0.477 0.461
$1,585
$543 0.477 0.461
$2,876 0.477 0.461
$25 0.477 0.461
$734 0.477 0.461
$160 0.477 0.461
$894
$9 0.477 0.461
$6,483
$483
0.449
0.449
0.449
0.449
0.449
0.449
0.449
0.449
0.449
0.449
$2,527
$1,343
($414)
($220)
-0.8%
-0.9%,
$3,870 ($635) -0.8%
$1,720
$175
$1,895
$644
$3,440
$29
$878
$191
$1,069
$11
$7,682
$572
($281)
($29)
($310)
($100)
($564)
($5)
($144)
($31)
($175)
($2)
($1,198)
($89)
-1.1%
-1.0%
-I.I%
-1.2%
-1.0%
-1.0%
-0.9%
-0.9°/o
-0.9%
-1.3%
-1.3%
-1.3%
19 Total Commercial & Industrial ___ ,_5,~2_93_ 2,802,855 $200,786 1,083,932 ~ _1_,_672,413 2,976,154 $12,898 $15,342 ~2~444) -1.1%
20 Public Street Lighting
21 Security Area Lighting
22 Security Area Lighting (R&F)
23 Street Lighting -Company
24 Street Lighting -Customer
25 AGA Revenue
26 Total Public Street Lighting
27 Total Sales to Ultimate Cu,tomers
28 Total (wlo Sch 400,401)
29 Voltage Line Loss Factors applied to rates:
7
7A
II
12
193
136
37
234
600
75,435
75,433
267
107
87
2.424
2,884
3,483,480
~
$102
$44
$40
$436
$0
$621
$273,497
$J8Q,265
Rev. R.'lmt Unallocated
30 Total Company Current Deferral Rate (cents/kWh): ECAM deferral $16.147 0.433
31
32
33
267
107
87
2,424
2,884 0
1,764,558 46,510
~ 46,510
Allocated
0
1,672,413
w,ooi
.Ll.QH!i
0.477
I 06475 I 03605
0.461 0.449
294
117
95
2.670
3,177
$1 0.477 0.461 0.449
$1 0.477 0.461 0.449
$0 0.477 0.461 0.449
$12 0.477 0.461 0.449
$14
3,725,850 $16,147 'i,ii's,m S9TsT ---
Prop_osed Rates
.S. f I
Total Tariff Customer Rate I 0.477 0.461 0.449
Total Schedule 400 Rate 0.449
Total Schedule 401 Rate O 449
$2
$1
$0
$14
$16
($0) -0.2%
($0) -0.2%
($0) -0.2%
($2) -0.5%
($3) -0.4%
$19,228 ($3,081) -1.1% sio.m ($1,793) -:0.W.
Current Rates
.S. f I
0.571 0.549 0.532
0.532
0.532
~
S' m ~ C'l~;:o "'m -· o "(l)CTO ::0 CD ;.~
g. ~ ~ :s:: CD • • o ;:::i_ "1J "-> C :s:: )> "1J ;a • () Q) Q) :s:: m~ 5· ~ ~--cl' ~To~ ;:::;.'.0-.(D ~co--..,
Case No. PAC-E-21-09
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 2021
I.P.U.C. No. 1
Eleven+eB-th Revision of Sheet No. 94.1
Canceling TenNiR-th Revision of Sheet No. 94.1
ROCKY MOUNTAIN POWER
ELECTRIC SERVICE SCHEDULE NO. 94
STATE OF IDAHO
Energy Cost Adjustment
AVAILABILITY: At any point on the Company's interconnected system.
APPLICATION: This Schedule shall be applicable to all retail tariff Customers talcing 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.
Secondary
Schedule 1 0.477~ per kWh
Schedule 6 0.477~ per kWh
Schedule 6A 0.477~ per kWh
Schedule 7 0.477~ per kWh
Schedule 7A 0.477~ per kWh
Schedule 9
Schedule 10 0.477~ per kWh
Schedule 11 0.477~ per kWh
Schedule 12 0.477m.¢ per kWh
Schedule 19 0.477~ per kWh
Schedule 23 0.477~ per kWh
Schedule 23A 0.477~ per kWh
Schedule 24 0.477~ per kWh
Schedule 35 0.477~ per kWh
Schedule 35A 0.477~ per kWh
Schedule 36 0.477~ per kWh
Schedule 400
Schedule 401
Submitted Under Case No. PAC-E-~21-09
ISSUED: April I, 2020March 31, 2021
Delivery Voltage
Primary
0.461M9¢ per kWh
0.461M9¢ per kWh
0.46JM9¢ per kWh
0.461M9¢ per kWh
0.461M9¢ per kWh
0.461M9¢ per kWh
0.461M9¢ per kWh
Transmission
0.449~¢ per kWh
0.449£1.¢ per kWh
0.449£1.¢ per kWh
EFFECTIVE: June 1, 20210
I.P.U.C. No. 1
Eleventh Revision of Sheet No. 94.1
Canceling Tenth Revision of Sheet No. 94.1
ROCKY MOUNTAIN POWER
ELECTRIC SERVICE SCHEDULE NO. 94
STATE OF IDAHO
Energy Cost Adjustment
AVAILABILITY: At any point on the Company's interconnected system.
APPLICATION: This Schedule shall be applicable to all retail tariff Customers talcing 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.
Secondaa
Schedule 1 0.477¢ per kWh
Schedule 6 0.477¢ per kWh
Schedule 6A 0.477¢ per kWh
Schedule 7 0.477¢ per kWh
Schedule 7A 0.477¢ per kWh
Schedule 9
Schedule 10 0.477¢ per kWh
Schedule 11 0.477¢ per kWh
Schedule 12 0.477¢ per kWh
Schedule 19 0.477¢ per kWh
Schedule 23 0.477¢ per kWh
Schedule 23A 0.477¢ per kWh
Schedule 24 0.477¢ per kWh
Schedule 35 0.477¢ per kWh
Schedule 35A 0.477¢ per kWh
Schedule 36 0.477¢ per kWh
Schedule 400
Schedule 401
Submitted Under Case No. PAC-E-21-09
ISSUED: March 31, 2021
Delivery Voltage
Primary
0.461¢ per kWh
0.461¢ per kWh
0.461¢ per kWh
0.461¢ per kWh
0.461¢ per kWh
0.461¢ per kWh
0.461 ¢ per kWh
Transmission
0.449¢ per kWh
0.449¢ per kWh
0.449¢ per kWh
EFFECTIVE: June 1, 2021
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF ROCKY MOUNTAIN POWER
REQUESTING APPROVAL OF $16.1
MILLON NET POWER COST DEFERRAL
) CASE NO. PAC-E-21-09
)
) DIRECT TESTIMONY OF
) STEVEN R. MCDOUGAL
ROCKY MOUNTAIN POWER
CASE NO. PAC-E-21-09
March 2021
Q.
2
3 A.
Please state your name and business address with PacifiCorp, dba Rocky
Mountain Power ("the Company").
My name is Steven R. McDougal, and my business address is 1407 W. North Temple,
4 Suite 330, Salt Lake City, Utah 84116.
5 QUALIFICATIONS
6 Q.
7 A.
8
9
10
11
12
13
14
15 Q.
16 A.
17
18
19
20 Q.
21 A.
22
Please describe your education and professional background.
I received a Master of Accountancy from Brigham Young University with an emphasis
in Management Advisory Services and a Bachelor of Science degree in Accounting
from Brigham Young University. In addition to my formal education, I have also
attended various educational, professional, and electric industry-related seminars. I
have been employed with PacifiCorp and its predecessor, Utah Power and Light
Company, since 1983. My experience includes various positions with regulation,
finance, resource planning, and internal audit. My current position is the Director of
Revenue Requirements.
What are your current responsibilities with the Company?
My primary responsibilities include overseeing the calculation and reporting of the
Company's regulated earnings and revenue requirement, assuring that the
interjurisdictional cost allocation methodology is correctly applied, and explaining
those calculations to regulators in the jurisdictions in which the Company operates.
Have you testified in previous proceedings?
Yes. I have provided testimony in regulatory proceedings in California, Idaho, Oregon,
Utah, Washington, and Wyoming.
McDougal, Di-1
PacifiCorp
PURPOSE OF TESTIMONY
2 Q. What is the purpose of your testimony?
3 A. I explain and support the Company's request, through this Energy Cost Adjustment
4 Mechanism ("ECAM"), for recovery of collectively $4.43 million for repowering and
5 Energy Vision 2020, before carrying charge, as calculated and deferred through the
6 approved Resource Tracking Mechanism ("RTM"). These amounts are included in the
7 ECAM as shown in Mr. Jack Painter's Testimony, Exhibit 1, line 33. I also summarize
8 modifications to the accounting treatment of the excess deferred income tax ("EDIT")
9 balances that resulted from the 2017 Tax Cuts and Jobs Act ("TCJA").
10 RESOURCE TRACKING MECHANISM
II Q.
12
13 A.
14
15
16
17
18
19
20
21
22
Please briefly describe the background and purpose of the resource tracking
mechanism, ("RTM").
In Case No. PAC-E-17-06, filed on July 3, 2017, the Company applied for approval of
the plan to upgrade ( or "repower") its existing wind resources and approval of
associated ratemaking treatment. On November 21, 2017, the Company and
intervening parties reached a stipulated agreement ("Stipulation") that allows the
Company to use the ECAM to recover the replacement cost of certain assets, new
investment, incremental energy production, and wind repowering project PTCs through
the RTM. The RTM and ECAM will capture the costs and benefits of the repowered
wind facilities until they are recovered in base rates through a general rate case. The
Stipulation between the parties was approved by Commission Order No. 33954, dated
December 28, 2017.
McDougal, Di-2
PacifiCorp
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
Q.
A.
In Case No. PAC-E-17-07, filed on July 3, 2017, the Company applied for
approval of the plan to build new wind projects and the proposed Aeolus-to­
Bridger/ Anticline transmission line. On July 20, 2018, the Company and intervening
parties reached a stipulated agreement that allows the Company to use the ECAM to
track new investment, energy production, and PTCs associated with the Stipulated
Projects through the RTM. The ECAM will capture the costs up to the level of benefits
of the new wind facilities and Energy Vision 2020 until they are recovered in base rates
through a general rate case. The amount above the benefits will be deferred as a
regulatory asset for recovery in the next general rate case. The is consistent with the
stipulation in Case No. PAC-E-17-07, paragraph 14, that states:
The Stipulating Parties agree that the Company will maintain a cap on
the annual total cost of the Stipulated Projects not to exceed the annual
project benefits in the ECAM and RTM. Costs that are passed on to
customers through the RTM, before the next general rate case, will be
capped at the level of benefits that will flow through the ECAM, as such,
on a combined basis, the ECAM and the RTM will not result in a net
cost to customers associated with the Stipulated Projects. Any costs
above this cap will be deferred as a regulatory asset for recovery to be
set in the next general rate case.1
Which projects are included in the RTM and this ECAM?
The RTM is split into two parts, shown as Exhibit 4a and 4b, to account for the
differences between the settlement for repowered wind assets approved as part of Case
No. PAC-E-17-06 and the settlement for transmission and new wind assets approved
as part of Case No. PAC-E-17-07. Below is a description of the assets included in both
exhibits.
1 In the Matter of the Application of Rocky Mountain Power for a Certificate of Public Convenience and
Necessity and Binding Ratemaking treatment for New Wind and Transmission Facilities, Case No. PAC-E-
1707, Stipulation at 5 (May 9, 2018) ("2018 Settlement Stipulation"); Order No. 34104 (July 20, 2018)
(approving May 9 stipulation).
McDougal, Di-3
PacifiCorp
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
• Exhibit 4a includes the repowered wind projects. Three repowering projects
were completed and placed in service during 2020 that, combined with the
projects completed in 2019 and included in the prior RTM, produced an Idaho­
allocated net benefit of $2,718,684. The new projects are the Marengo 1 & 2
and Dunlap wind facilities.
• Exhibit 4b includes new wind projects and transmission. It includes three
Energy Vision 2020 wind projects, Cedar Springs, TB Flats I & II, and Ekola
Flats, along with the Energy Vision 2020 transmission project. In addition,
Exhibit 4b includes the Prior Mountain wind project and will also include the
Foote Creek I wind repowering project in future RTM deferrals, consistent with
the settlement in Case No. PAC-E-20-03 that states:
Ratemaking treatment for the Pryor Mountain wind resource and
the repowering of Foote Creek I to match costs and benefits with
a cost cap amount each year at the benefit level. The Company
may propose to include these resources in the RTM/ECAM,
consistent with the terms agreed to in Case No. PA C-E-17-07.
Prudency will be determined during the next General Rate
Case.2
The Combination of these Energy Vision 2020 projects produced an
Idaho-allocated net benefit of $7,483 for customers.
2 In the Matter of Rocky Mountain Power 's Application to Increase Its Rates and Charges in Idaho and for
Approval of Proposed Electric Service Schedules and Regulations, Case No. PAC-E-20-03, Application of
Rocky Mountain Power, Attachment 1 at 2 (July 2, 2020);Order No. 34884 (December 31, 2020) (approving
settlement stipulation).
McDougal, Di-4
PacifiCorp
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
Q.
A.
Q.
A.
Has the Company calculated the wind repowering deferral and Energy Vision
2020 under the RTM guidelines that were agreed to in the Stipulation and
approved by the Commission?
Yes. The deferral calculations follow the design and operation of the RTM as submitted
in the Direct Testimony of Jeffrey K. Larsen pages 6-16 and Exhibit 12 that was
referenced and approved in the Stipulation and Final Order of Case No. PAC-E-17-063
and the approved in the Stipulation and Final Order of Case No. PAC-E-17-07.4 The
RTM, along with the ECAM, will capture and match all the costs and benefits of the
repowered wind facilities and Energy Vision 2020 until such time as they are recovered
in base rates.
What are the costs and benefits associated with repowering and Energy Vision
2020 that the Company has included in the RTM deferral?
The Company has included the following items in the RTM on a monthly basis
beginning when a repowered or new wind project is placed into service:
• The pre-tax return on investment;
• Operation and maintenance expense;
• Depreciation expense;
• Property taxes;
• Wind taxes, if assessed;
• Net Power Cost ("NPC") benefits;
• Wheeling Revenue; and
3 In the Matter of the Application Rocky Mountain Power for Binding Ratemaking Treatment for Wind
Repowering, Case No. PAC-E-17-06, Testimony of Jeffrey K. Larsen (July 5, 2017); Stipulation (November 24,
2017); Order No 33954 (December 28, 2017).
4 2018 Settlement Stipulation; Order No. 34104.
McDougal, Di-5
PacifiCorp
2
3
4
5
6
7
8
9
IO
l l
12
13
14
15
16
17
18
19
20
21
22
23
Q.
A.
Q.
A.
• PTC benefits.
Has the Company prepared an exhibit showing the calculated amount of the wind
repowering deferral and Energy Vision 2020 deferral under the approved RTM
guidelines?
Yes. Exhibit No. 4a and 4b show the calculation of the December 31, 2020 RTM
deferral balance which results in a $4.43 million charge to be collected from customers
through the ECAM. This exhibit is structured similar to Exhibit 12 of Mr. Larsen's
Direct Testimony referenced above.
Line 18 of Exhibit No. 4a and Line 17 of Exhibit No. 4b shows that the repowered
wind projects and Energy Vision 2020 projects produced a net revenue
requirement of $936 thousand. Why is the Company seeking recovery of $4.43
million through the ECAM?
The RTM was approved to match all of the costs and benefits associated with the
repowered wind projects and Energy Vision 2020 and pass those onto customers.
Absent the RTM, the ECAM only captures some of the benefits and does not included
any of the costs incurred to produce those benefits. The ECAM will return to customers
100 percent of the Production Tax Credits (PTC) of $6.44 million, and 90 percent of
NPC benefit of $739 thousand, shown on lines 21 and 24 from Exhibit 4a and lines 20
and 23 from Exhibit 4b, respectively. Combined, the ECAM would return to customers
$7.18 million, absent the RTM. Due to the sharing band in the ECAM, 10 percent of
the NPC benefits would not have been passed onto customers absent the RTM. Further,
the ECAM does not capture any of the costs incurred by the Company to repower the
wind facilities and Energy Vision 2020 projects. The purposes of the RTM are to
McDougal, Di-6
PacifiCorp
2
3
4
5
6
7
8
9
10
l l
12
13
14
15
16
17
Q.
A.
Q.
A.
capture those costs and match them with the benefits. The $2.74 million, on line 27,
represents Idaho's share of the net benefit produced by the repowered wind facilities
and Energy Vision 2020. The $4.43 million RTM deferral allows the Company to
recover the net costs that are not reflected in the ECAM.
Has the Company included a carrying charge on the RTM deferral balance in
Exhibit No. 4?
No. Although the RTM deferral balance is subject to a carrying charge, the monthly
RTM deferral balance is summed with the other ECAM components and receives a
carrying charge as part of the overall carrying charge calculation.
What is the revenue requirement that is deferred for consideration in the next rate
case?
The settlement in Case No. PAC-E-17-07 states that "Any costs above this cap will be
deferred as a regulatory asset for recovery to be set in the next general rate case."5 The
settlement in Case No. PAC-E-20-03 has similar language, subject to a prudency
review. Based on the language in these settlements, the Company is deferring for
recovery in the next general rate case the $392,184 revenue requirement on line 17 of
Exhibit 4b, less the $25,000 credit per the stipulation in PAC-E-17-07 on line 26 of
18 Exhibit 4B, or $367,184.
19 TAX REFORM CREDIT
20 Q.
21 A.
22
Was a credit from the 2017 TCJA EDIT netted against the 2020 ECAM Deferral?
No. While tax savings from the federal tax reform Tax Cuts and Jobs Act ("TCJA")
were netted against the 2018 and 2019 ECAM deferral balances as prescribed in Order
5 2018 Settlement Stipulation at 5, ,r 14.
McDougal, Di-7
PacifiCorp
2 Q.
3 A.
4
5
6
7
8
9
10
11
12 Q.
13 A.
No. 34331 6 they were not netted against the 2020 ECAM deferral.
Describe th,e treatment of the Tax Reform Credit approved in Order No. 348847•
In Case No. PAC-E-20-03 the Company filed a settlement with the Commission
requesting authorization to modify the Tax Stipulation approved in Order No. 34331.
The settlement requested authorization for the remaining EDIT balance savings from
the TCJA to be retained and used to buy-down or offset the net plant balance and
closure costs of Cho Ila Unit No. 4 and to offset the January I, 2022 rate increase. Order
No. 34884 authorized the Company to stop refunding the 2017 TCJA EDIT effective
with the 2020 ECAM and use the remaining EDIT savings to offset the net plant
balance, decommissioning, and closure costs for Cho Ila unrecovered plant and mitigate
the rate impact of the January I, 2022 rate increase.
Does this conclude your direct testimony?
Yes.
66 In the Matter of the Investigation into the Impact of Federal Tax Code Revisions on Utility Costs and
Ratemaking, Case No. GNR-U-18-01.
7 In the Matter of Rocky Mountain Power's Application to Increase Its Rates and Charges in Idaho and for
Approval of Proposed Electric Service Schedules and Regulations, Case No. PAC-E-20-03.
McDougal, Di-8
PacifiCorp
Case No. PAC-E-21-09
Exhibit No. 4
Witness: Steven R. McDougal
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Steven R. McDougal
March 2021
PacifiCorp
Idaho
V\,lnd Repowering -Monthly RTM Deferral Calculation
Revenue Requirement
For the Month Ending December 31, 202C
$-Dollars
Line
No. Reference
Plant Revenue Requirement
1 Capital Investment Footnote 1
2 Depreciation Reserve Footnote 1
3 Accumulated DIT Balance Footnote 1
4 Net Rate Base (previous month) sum of lines 1-3
5 Pre-Tax Rate of Return line 36
6 Pre-Tax Return on Rate Base line 4 • line 5
7 \fvholesale \fvheeling Revenue Footnote 4
8 Operation & Maintenance Footnote 3
9 Depreciation Footnote 3 & 6
10 Property Taxes Footnote 3
11 Wind Tax Footnote 3
12 Total Plant Revenue Requirement sum of lines 6-11
Net Power Cost
13 NPC Incremental Savings Footnote 3
PTC Benefit
14 PTC Benefit Footnote 3
15 Gross-up for taxes line 14 • (line 34 -1)
16 PTC Revenue Requirement sum oflines 14 and 15
17 Depreciation Expense Adjustment Footnote 6 & 7
18 Rev. Requirement sum of lines 12, 13, 16, 17
Adjustment for ECAM Pass-through
19 PTC Revenue Requirement line 16
20 Percentage included in ECAM (100%) ID ECAM Sharing %
21 ECAM Pass-through line 19 • line20
22 NPC Incremental Savings line 13
23 Percentage included in ECAM (90%) ID ECAM Sharing %
24 ECAM Pass-through line 22 • line 23
25 Rev. Reqt. after ECAM Pass-through line 18 -line 21 -line 24
25.5 Authorized Capped Recovery line 26 -line 25
26 Total Deferral -ID Share Footnote 5
27 Net Customer (Benefit) sum of lines 21 , 24, 26
Deferral Balance -ID Share
28 Beginning Deferral Balance line 32 of previous year
29 Monthly Deferral Footnote 5
30 Deferral Collection Footnote 3
31 Carrying Charge Footnote 2
32 Ending Deferral Balance sum of lines 28-31
33 Federal/State Combined Tax Rate
34 Net to Gross Bump up Factor= (1/(1-tax rate)) ( 1/( 1-tax rate))
35 Deferred Balance Carrying Charge Footnote 2
36 Pretax Return Case No. PAC-E-15-09
37 Property Tax Rate Rate as percent of net
plant in PAC-E-15-09
38 Idaho SG Factor Case No. PAC-E-15-09
39 Idaho GPS Factor Case No. PAC-E-15-09
Footnotes:
1) Ending monthly capital balance of the previous month.
2) The RTM deferral balance is included in the ECAM carrying charge
calculation and is therefore zero here.
3) Equals the monthly sum of all projects
4) Not Applicable for Repowering
Total
Company
927,970,785
(18,117,827)
(61,996,180)
847,856,778
9.003%
76,328,451
-
(687,308)
31,247,868
5,447,143
411,006
112,747,161
(13,516,653)
(80,591,342)
(26,274,735)
(106,866,077)
(37,377,882)
(45,013,451)
24.5866%
1.3260
2.00%
9.003%
0.78%
6.0136%
5.7978%
5) The RTM is capped until the next general rate case so that, after taking into account the
wind repowering benefits that will flow through the Company's ECAM, ii will
not operate to surcharge customers.
6) Actual depreciation expense will be adjusted by the impact of the retired assets
until the next depreciation study
7) Depreciation Expense for the replaced equipment currently in rates is removed
as an incremental revenue requirement savings.
Rocky Mountain Power
Exhibit No. 4 Page 1 of 2
Case No. PAC-E-21-09
Witness: Steven R. McDougal
Exhlblt4a
Jan.-Dec. 2020
Factor Factor% Idaho Allocated
SG 6.0136% 55,804,451
SG 6.0136% (1,089,534)
SG 6.0136% (3,728,202)
50,986,715
9.003%
4,207,580
SG 6.0136% -
SG 6.0136% (41,332)
SG 6.0136% 1,879,122
GPS 5.7978% 315,814
SG 6.0136% 24,716
6,385,901
SG 6.0136% (812,837)
SG 6.0136% (4,846,441)
(1,580,057)
(6,426,498)
SG 6.0136% (2,247,756)
(3,101,191)
(6,426,498)
100%
(6,426,498)
(812,837)
90%
1731,554)
4,439,368
4,439,368
(2,718,684)
439,595
4,439,368
(256,430)
-
4,622,533
Line No.
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
PacifiCorp
Idaho
Energy Vision 2020 -Monthly RTM Deferral Calculation
Revenue Requirement
For the Month Ending December 31, 2020
$-Dollars
Plant Revenue Requirement
Capital Investment
Depreciation Reserve
Accumulated DIT Balance
Net Rate Base (previous month)
Pre-Tax Rate of Return
Pre-Tax Return on Rate Base
'M1olesale 'M1eeling Revenue
Operation & Maintenance
Depreciation
Property Taxes
WndTax
Total Plant Revenue Requirement
Net Power Cost
NPC Savings
PTC Benefit
PTC Benefit
Gross-up for taxes
PTC Revenue Requirement
Rev. Requirement
Adjustment for ECAM Pass-through
PTC Revenue Requirement
Percentage included in ECAM (100%)
ECAM Pass-through
NPC Savings
Percentage included in ECAM (90%)
ECAM Pass-through
Rev. Reqt. after ECAM Pass-through
24.5 Authorized Capped Recovery
25 Total Deferral -ID Share
26 Annual $300,000 Benefit provided by Company
27 Net Customer (Benefit)
Deferral Balance -ID Share
28 Beginning Deferral Balance
29 Monthly Deferral
30 Deferral Collection
31 Carrying Charge
32 Ending Deferral Balance
33 Federal/State Combined Tax Rate
34 Net to Gross Bump up Factor= (1/(1-tax rate))
35 Deferred Balance Carrying Charge
36 Pretax Return
37 Property Tax Rate
38 Idaho SG Factor
39 Idaho GPS Factor
Footnotes:
1) Ending monthly capital balance of the previous month.
Reference
Footnote 1
Footnote 1
Footnote 1
sum of lines 1-3
line 36
line 4 • line 5
Footnote 4
Footnote 3
Footnote 3
Footnote 3
Footnote 3
sum of lines 6-11
Footnote 3
Footnote 3
line 14 • (line 34 -1)
sum of lines 14 and 15
sum of lines 12, 13, 16
line 16
ID ECAM Sharing %
line 19 • line 20
line 13
ID ECAM Sharing %
line 22 • line 23
line 17 -line 20 -line 23
line 25 -line 24
Footnote 5
Final Order No. 34104
sum of lines 20, 23, 25, 26
line 32 of previous year
Footnote 5
Footnote 3
Footnote 2
sum of lines 28-31
(1/(1-tax rate))
Footnote 2
Case No. PAC-E-15-09
Rate as percent of net
plant in PAC-E-15-09
Case No. PAC-E-15-09
Case No. PAC-E-15-09
2) The RTM deferral balance is included in the ECAM carrying charge
calculation and is therefore zero here.
3) Equals the monthly sum of all projects
4) 'M1eeling Revenue is based on the 2021 IRP
5) The RTM is capped until the next general rate case so that, after taking into account the
new wind generation benefits that will flow through the Company's ECAM, it will
not operate to surcharge customers.
6) Annual $300,000 Benefit provided by Company stipulated in Final Order No. 34104
Total
Company
718,253,320
(1, 122,399)
11,101,804)
716,029,117
9.234%
5,509,807
(1,331,623)
135,552
2,381,349 -
130,912
6,825,996
(130,912)
(130,814)
142,649)
(173,463)
6,521,621
24.5866%
1.3260
1.00%
9.234%
0.78%
6.0136%
5.7978%
Rocky Mountain Power
Exhibit No. 4 Page 2 of 2
Case No. PAC-E-21-09
Witness: Steven R. McDougal
Exhibit4b
Dec-20
Factor Factor% Idaho
Allocated
SG 6.0136% 43,192,882
SG 6.0136% (67,497)
SG 6.0136% (66,258)
43,059,127
9.234%
331,338
SG 6.0136% (80,079)
SG 6.0136% 8,152
SG 6.0136% 143,205
GPS 5.7978% -
SG 6.0136% 7,873
410,488
SG 6.0136% (7,873)
SG 6.0136% (7,867)
(2,565)
(10,431)
392,184
(10,431)
100%
(10,431)
(7,873)
90%
(7,085
409,701
(392,184)
17,517
(25,000)
(25,000)
-
(7,483)
--
(7,483)
CUSTOMER NOTICES
.. ROCKY MOUNTAIN
~POWER
POWERING YOUR GREATNESS
FOR IMMEDIATE RELEASE
Media Hotline [phone]
Price decrease proposed for Idaho customers
Annual energy cost adjustment
BOISE, Idaho (March 31, 2021) -Rocky Mountain Power proposes a 1.1 percent decrease overall for
customers in its 2021 annual energy cost adjustment. Typical residential customers using 800 kilowatt­
hours per month would see a decrease of approximately $9.00 on their annual electricity bill.
"Rocky Mountain Power is committed to bringing the best value to our customers for their hard-earned
dollars," said Tim Solomon, regional business manager for Rocky Mountain Power in Rexburg. "As a
provider of one of the most essential public services, we're pleased to pass on to customers the lower
costs of providing service. This annual adjustment continues to ensure Rocky Mountain Power
customers always pay some of the lowest prices in the nation for the energy they need."
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. If actual costs are lower, the amount is
returned to customers on their monthly bill. During the past year the company's energy-related
expenses decreased by $7.8 million. Pending commission approval, the changes would take effect June
1, 2021 with the following impact on each rate schedule:
Residential Schedule 1-0.8% decrease
Residential Schedule 36-0.9% decrease
General Service Schedule 6 -1.1% decrease
General Service Schedule 9 -1.2% decrease
Irrigation Service Schedule 10-1.0% decrease
Commercial & Industrial Heating Schedule 19 -1.0% decrease
General Service Schedule 23 -0.9% decrease
General Service Schedule 35 -1.3% decrease
Public Street Lighting -0.4% decrease
Tariff Contract 400-1.3% decrease
Tariff Contract 401-1.3% decrease
The public will have an opportunity to comment on the proposal as the commission studies the
company's request. The commission must approve the proposed changes before they can take effect. A
copy of the company's application is available for public review on the commission's website,
www.puc.idaho.gov, under Case No. PAC-E-21-09. Customers may also subscribe to the commission's
RSS feed to receive periodic updates via email. The request is also available at the company's offices in
Rexburg, Preston, Shelley and Montpelier, although due to COVID-19 pandemic restrictions, the
company urges customers to utilize on line resources:
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
Annual energy cost adjustment
Proposed net price decrease
Rocky Mountain Power requests recovery of power costs.
On March 31, 2021, Rocky Mountain Power asked the
Idaho Public Utilities Commission to approve the 2020
incremental energy related costs of $14.3 million, a net
decrease of $3.1 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 costs
to provide electricity to Idaho customers and the amount
collected from customers through current prices.
Pending commission approval, the decrease would take
effect June 1, 2021. All customer classes will see a net
decrease to their rates resulting from the recent changes
in costs of providing energy to customers. The proposed
adjustment will allow Rocky Mountain Power to continue
to provide safe, reliable electric service to its customers.
Typical residential customers using 800 kilowatt-hours per
month would see a decrease of approximately $9.00 a
year on their electricity bill. The following is a summary of
the percentage impacts by customer class:
• Residential Schedule 1 -0.8% decrease
• Residential Schedule 36 -0.9% decrease
• General Service Schedule 6 -1.1 % decrease
• General Service Schedule 9 - 1.2% decrease
• Irrigation Service Schedule 10 - 1.0% decrease
• Commercial & Industrial Heating Schedule 19 -
1.0% decrease
• General Service Schedule 23 -0.9% decrease
• General Service Schedule 35 -1.3% decrease
• Public Street Lighting -0.4% decrease
• Tariff Contract 400 -1.3% decrease
• Tariff Contract 401 -1.3% decrease
The public w ill 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-21-09.
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
due to COVID-19 pandemic restrictions, the company
encourages customers to utilize online resources.
Idaho Public Utilities Commission
11331 W Chinden Blvd
Building 8, Suite 201A
Boise, ID 83714
www.puc.idaho.gov
Rocky Mountain Power offices
• Rexburg -127 East Main
• Preston -509 S. 2nd E.
• Shelley -852 E. 1400 N.
• Montpelier -24852 U.S. Hwy 89
For more information about your rates and rate schedule,
go to rockymountainpower.net/rates.
~ROCKY MOUNTAIN
~POWER