20260406Direct McCoy.pdf

RECEIVED
APRIL 6, 2026
IDAHO PUBLIC
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION ) CASE NO. PAC-E-26-04
OF PACIFICORP D/B/A ROCKY )
MOUNTAIN POWER FOR APPROVAL OF ) DIRECT TESTIMONY OF
SALE OF WASHINGTON SERVICE AREA ) SHELLEY E. McCOY
AND ACCOUNTING ORDER )
ROCKY MOUNTAIN POWER
CASE NO. PAC-E-26-04
April 2026

1 I . INTRODUCTION
2 Q. Please state your name, business address and present
3 position with PacifiCorp, d/b/a Rocky Mountain Power.
4 A. My name is Shelley E . McCoy, and my business address is
5 825 NE Multnomah Street, Suite 2000, Portland OR 97232 .
6 I am currently employed as the Director of Revenue
7 Requirement at PacifiCorp.
8 II . QUALIFICATIONS
9 Q. Briefly describe your education and professional
10 background.
11 A. I earned a Bachelor of Science degree in Accounting from
12 Portland State University in 1990 . In addition to my
13 formal education, I have attended several utility
14 accounting, ratemaking, and leadership seminars and
15 courses . I have been employed by PacifiCorp since
16 November 1996 . My past responsibilities have included
17 general and regulatory accounting, budgeting,
18 forecasting, and reporting. I assumed my current
19 position in November 2022 .
20 Q. What are your responsibilities as Director of Revenue
21 Requirement?
22 A. My primary responsibilities include overseeing the
23 calculation and reporting of PacifiCorp' s regulated
24 earnings or revenue requirement, ensuring that the
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1 inter-jurisdictional cost-allocation methodology is
2 correctly applied, and explaining those calculations to
3 regulators in the jurisdictions in which PacifiCorp
4 operates .
5 Q. Have you testified in previous regulatory proceedings?
6 A. Yes . I have provided testimony in multiple dockets
7 before the Idaho, Oregon, California, Utah, Washington,
8 and Wyoming public utility commissions .
9 III . PURPOSE OF TESTIMONY
10 Q. What is the purpose of your testimony in this proceeding?
11 A. My testimony supports PacifiCorp' s Application for
12 Approval of Sale of Washington Service Area and
13 Accounting Order to Gem Sub LLC ("Gem") , an affiliate of
14 Portland General Electric Company. Specifically, my
15 testimony provides details on:
16 • The estimated non-net power cost ("NPC") revenue
17 requirement impact of the sale prior to the sharing
18 of the gain associated with the goodwill value of
19 the business;
20 • The removal of balances and expenses from revenue
21 requirement associated with the sale;
22 • The inclusion of incremental coal plant accumulated
23 depreciation and decommissioning balances
24 collected from Washington customers in the revised
25 revenue requirement; and
26 • The calculation of updated allocation factors after
27 the removal of Washington.
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1 IV. ESTIMATED REVENUE REQUIREMENT IMPACT
2 Q. What assets is PacifiCorp selling?
3 A. As identified in PacifiCorp' s application and the direct
4 testimony of PacifiCorp witnesses Joelle R. Steward and
5 Nikki L. Kobliha, PacifiCorp is selling its Washington
6 service area and certain Washington-based assets
7 ("Service Area Transfer") . These assets include the
8 Chehalis plant, Goodnoe Hills Wind Farm, Marengo I and
9 II Wind Farms, and certain Washington-based transmission
10 and distribution assets .
11 Q. Are these assets used to serve Idaho customers and
12 included in Idaho rates?
13 A. Not all of the assets are used to serve Idaho customers .
14 The Chehalis plant, Goodnoe Hills and Marengo wind farms
15 and the transmission assets are used to serve Idaho
16 customers, and an allocation of these resources is
17 included in Idaho customer rates . The Washington
18 distribution assets are only used to serve Washington
19 customers and are therefore not included in Idaho
20 customer rates .
21 Q. What is the estimated non-NPC revenue requirement impact
22 of the proposed Service Area Transfer?
23 A. As shown in Table 1, the overall impact to Idaho' s non-
24 NPC revenue requirement is estimated to be an increase
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1 of $2 . 6 million, prior to the consideration of other
2 elements such as the proposed customer rate credits . My
3 Exhibit No. 6 and the supporting workpaper provide the
4 details of the below calculations . Please see
5 Ms . Steward' s testimony for the full impact of the sale .
Table 1 — Non-NPC Revenue Requirement Impact
Transition Period Post-Transition Period
Total Idaho Total Idaho
($mullions) Company Allocated Company Allocated
Production $ 14.0 $ 0.9 $ 14.0 $ 0.9
Transmission 25.4 1.7 25.4 1.7
Distribution 3.0 0.2 3.0 0.2
General&Other 23.2 1.4 23.2 1.4
Total before new revenues & credits 65.6 4.2 65.6 4.2
New wheeling revenues (23.9) (1.6) (13.7) (0.9)
Estimated Non-NPC Revenue
Re quire me nt $ 41.7 $ 2.6 $ 51.9
6 Q. Please describe the main elements of Table 1 .
7 A. The revenue requirement increase is broken out by major
8 function. The Production function includes the
9 reallocation of costs of all of PacifiCorp' s remaining
10 generation plants, excluding the cost of fuel . The
11 Transmission function reflects the reallocation of
12 PacifiCorp' s transmission system, which is almost
13 entirely offset by new wheeling revenues from the
14 transaction. The Distribution function reflects the
15 reallocation of common costs such as management,
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1 engineering, safety and wildfire mitigation that
2 supports distribution operations in all states . The
3 General & Other function includes administrative and
4 general costs, customer service, support costs and
5 property taxes for the business . Not included in Table
6 1 or in the estimated revenue requirement impact is the
7 change in the blended state tax rate described by Ms .
8 Kobliha. The change in the blended tax rate will be
9 included in future general rate cases and results of
10 operations filings . In addition to a recalculation of
11 the revenue requirement, PacifiCorp will also be
12 collecting new wheeling revenues from new transmission
13 service agreements as described in the direct testimony
14 of PacifiCorp witness Michael G. Wilding. These new
15 transmission service agreements are expected to provide
16 $23 . 9 million total Company, or $1 . 6 million Idaho
17 allocated, in new wheeling revenues during the
18 transition period, and $13 . 7 million total Company, $0 . 9
19 million Idaho allocated, post transition period.
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Rocky Mountain Power

I Q. How was the non-NPC revenue requirement impact of the
2 Service Area Transfer estimated?
3 A. To estimate the impact, the total Company revenue
4 requirement for 20241 was compared to the total Company
5 revenue requirement after removing expenses and rate
6 base balances associated with the Service Area Transfer.
7 The revised revenue requirement was allocated using
8 updated allocation factors that exclude Washington. The
9 difference between the two amounts for Idaho is the
10 estimated revenue requirement impact .
11 Q. Please describe the process used for developing the
12 estimate.
13 A. Starting with actual accounting data for calendar year
14 2024, 2 PacifiCorp identified all components of non-NPC
15 revenue requirement that will be removed by the sale of
16 the Washington service area and the associated assets .
17 This includes electric plant in service, accumulated
18 depreciation, accumulated deferred income tax,
19 operations and maintenance expense, depreciation and
20 amortization expense, property taxes and the Washington
21 public utility tax. Additionally, Washington' s
22 allocation of wildfire liability accruals, legal
1 Final allocation factors and regulatory balances for 2025 were not
available at the time the analysis was performed.
2 Rate base was calculated using period ending December 31, 2024.
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Rocky Mountain Power

1 expenses and liability insurance premiums were removed,
2 as those costs will not be re-allocated to the other
3 five states . Finally, Washington' s incremental
4 accumulated depreciation and decommissioning balances
5 for the Jim Bridger and Colstrip generation plants were
6 added in to reflect the costs for these two generation
7 plants paid for by Washington customers that will be
8 reallocated with the other plant balances . After making
9 these adjustments, revenues, expenses and rate base were
10 reallocated to the remaining five states using updated
11 allocation factors, and then a revenue requirement
12 estimate was calculated for each state .
13 Q. What are the Washington incremental accumulated
14 depreciation and decommissioning balances?
15 A. Under Washington' s Clean Energy Transformation Act, the
16 costs of coal-fired generation, with the exception of
17 decommissioning, are not allowed in Washington customer
18 rates past 2025 . Therefore, the depreciable lives for
19 the Jim Bridger and Colstrip coal-fired units were set
20 to 2025 for PacifiCorp' s Washington customers . As a
21 result, the Washington system allocation under the 2020
22 PacifiCorp Inter-Jurisdictional Cost Allocation
23 Protocol ("2020 Protocol") , approximately eight percent,
24 of Jim Bridger Units 3 and 4 and the Colstrip plant are
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1 fully depreciated. This additional accumulated
2 depreciation balance is included in the reallocation of
3 plant balances to the other five states .
4 In addition to the incremental accumulated
5 depreciation, Washington customers have been paying
6 incremental decommissioning costs for the Jim Bridger
7 and Colstrip plants based on estimates from the Kiewit
8 Studies filed in PacifiCorp' s 2018 Depreciation Study. 3
9 This balance, which is a rate base deduction, has also
10 been reallocated as part of the generation plant
11 reallocation. The collection of decommissioning
12 estimates will continue through 2030 . After the Service
13 Area Transfer is complete, Gem will adopt PacifiCorp' s
14 tariffs and will remit to PacifiCorp on a quarterly basis
15 amounts collected under Washington Schedule 92,
16 Temporary Coal Cost Adjustment . These additional
17 collections for decommissioning will be added to the
18 existing balances and included in the future allocation
19 of generation rate base .
3 In the Matter of the Application of Rocky Mountain Power for
Authorization to Change Depreciation Rates Applicable to Electric
Property, Case No. PAC-E-18-08, Application (Sep. 11, 2018) .
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I Q. Were the lives of PacifiCorp' s other coal units
2 accelerated for Washington?
3 A. No . Under Washington' s approved allocation
4 methodologies, the West Control Area Inter-
5 Jurisdictional Allocation Methodology followed by the
6 Washington Interjurisdictional Allocation Methodology,
7 Jim Bridger and Colstrip were the only two coal-fired
8 plants included in Washington rates . Therefore, the
9 lives of the other coal plants were not accelerated for
10 Washington rates .
11 Q. Given that Washington customers did not pay for these
12 other coal plants, did this affect the recording of
13 depreciation on PacifiCorp' s books?
14 A. No . PacifiCorp records depreciation of its assets on a
15 total Company basis using the approved depreciation
16 rates from depreciation studies filed with the state
17 commissions in the states where PacifiCorp serves retail
18 customers . The depreciation expense is not impacted by
19 allocation methodologies or even variations in
20 allocation percentages between rate cases . Any
21 differentiation in depreciable lives, such as
22 Washington' s lives for the Bridger and Colstrip units,
23 is then recorded as an increment to the system
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1 depreciation expense based on the applicable allocation
2 factor under the 2020 Protocol .
3 Q. How were the allocation factors revised for this
4 estimate?
5 A. For each of the system allocation factors, such as System
6 Generation or Customer Number, the Washington component
7 was removed from the six-state allocation factors . The
8 remaining five-state allocation factors were then
9 proportionately recalculated to reflect five-state
10 allocations after the Service Area Transfer. This change
11 in the allocation factors reflects an increased
12 percentage of remaining resources allocated to each
13 state based on the algebraic formulas in the 2020
14 Protocol .
15 Q. What rate of return assumptions were relied upon in the
16 revenue requirement calculations?
17 A. To calculate the return-on-rate base component of
18 revenue requirement, PacifiCorp used a five-quarter
19 average 2024 actual capital structure and a 9 . 55 percent
20 average return on equity. The actual revenue requirement
21 impact will be dependent on each state' s authorized cost
22 of capital .
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Rocky Mountain Power

I Q. When will the actual Idaho impact of the Service Area
2 Transfer be known?
3 A. A specific and more detailed calculation for the revenue
4 requirement impact for Idaho will be included in
5 PacifiCorp' s next general rate case .
6 V. ALLOCATION FACTORS
7 Q. What allocation methodology was assumed in the
8 calculation of allocation factors?
9 A. Allocation factors were calculated in accordance with
10 2020 Protocol . While the 2020 Protocol expired at the
11 end of 2025, it is the most recent allocation methodology
12 approved by the Idaho Public Utilities Commission
13 ("Commission") and used to establish current rates .
14 Therefore, it is a logical option for evaluating impacts
15 of the Service Area Transfer.
16 Q. How were the allocation factors adjusted for the Service
17 Area Transfer?
18 A. Consistent with the accounting data, PacifiCorp began
19 with the 2024 normalized allocation factors used in
20 PacifiCorp' s December 2024 Results of Operations report
21 filed with the Commission. 4 Next the Washington
22 percentages were set to zero, and the remaining
4 Rocky Mountain Power's December 2024 Results of Operations Report
(filed Apr. 28, 2025) .
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I percentages were proportionately recalculated for the
2 other jurisdictions . This approach preserves the dynamic
3 nature of the allocation factors established under the
4 2020 Protocol and reflects how those factors naturally
5 shift when underlying data-such as energy usage-changes
6 for one or more states .
7 Q. What were the changes to the updated allocation factors?
8 A. Table 2 shows a comparison of key allocation factors for
9 the original 2024 data and the revised calculations
10 without Washington for each jurisdiction. These
11 percentages are a snapshot in time and will fluctuate
12 with the underlying data, but provide a reasonable
13 expectation of the impact of removing Washington from
14 the calculation of allocation factors .
Table 2 - Comparison of Allocation Factors
Factor Description Factor CA OR WA UT ID WY FERC Total
System Generation SG 1.32% 26.16% 7.47% 45.12% 6.04% 13.86% 0.02% 100.00%
System Generation-Revised SG 1.43% 28.27% 0.00% 48.77% 6.53% 14.98% 0.02% 100.00%
System Energy SE 1.30% 25.20% 7.22% 44.58% 6.24% 15.44% 0.02% 100.00%
System Energy-Revised SE 1.40% 27.16% 0.00% 48.04% 6.73% 16.64% 0.02% 100.00%
Customer Number CN 2.22% 30.30% 6.61% 49.60% 4.29% 6.98% 0.00% 100.00%
Customer Number-Revised CN 2.37% 32.44% 0.00% 53.11% 4.60% 7.48% 0.00% 100.00%
System Overhead SO 2.49% 27.30% 7.37% 44.33% 5.75% 12.75% 0.01% 100.00%
System Overhead-Revised SO 2.69% 29.47% 0.00% 47.85% 6.21% 13.76% 0.02% 100.00%
VI . CONCLUSION
15 Q. What is your recommendation for the Commission?
16 A. I recommend that the Commission find Idaho customers
17 will not be harmed by the sale of the Washington-based
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I generation and transmission assets included in the
2 Service Area Transfer and approve the asset sale .
3 Q. Does this conclude your direct testimony?
4 A. Yes .
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Rocky Mountain Power

Case No. PAC-E-26-04
Exhibit No. 6
Witness : Shelley E. McCoy
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Shelley E . McCoy
Non-Net Power Cost Revenue Requirement Impact
of Washington Sale
April 2026

Rocky Mountain Power
Exhibit No.6 Page 1 of 1
Case No. PAC-E-26-04
Witness:Shelley E.McCoy
Rocky Mountain Power
Application for Service Area Transfer
Estimated Revenue Requirement Change Due to Washington Sale
After Adjustments
2024 Data
Adjustments
Est.WA Impact
Liability Taxes No WA Incr. Before New New
Wildfire Insurance Longer Accum Wheeling Wheeling
Function Total Impact Liability Costs Costs Incurred Depr/Decom Revenues Revenues Adjusted Impact
Production 20,792,817 (6,756,829) 14,035,988 14,035,988
Transmission 25,328,046 25,328,046 (23,913,389) 1,414,657
Distribution 3,014,401 3,014,401 3,014,401
General 81,072,605 (27,748,938) (7,457,363) (22,640,385) 23,225,919 23,225,919
Total 130,207,868 (27,748,938) (7,457,363) (22,640,385) (6,756,829) 65,604,353 (23,913,389) 41,690,964
State Allocations
Function CA OR LIT ID WY FERC Total
Production 200,982 3,944,601 6,827,869 920,847 2,138,499 3,189 14,035,988
Transmission 20,247 401,360 690,798 92,148 209,776 328 1,414,657
Distribution 45,908 861,536 1,478,254 192,702 435,358 641 3,014,401
General 599,424 6,826,162 11,246,906 1,425,210 3,124,589 3,627 23,225,919
Total 866,562 12,033,660 20,243,827 2,630,907 5,908,223 7,785 41,690,964