20250806Direct Steward.pdf

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE )
APPLICATION OF ROCKY MOUNTAIN )
POWER FOR APPROVAL OF 2026 ) CASE NO. PAC-E-25-14
INTER-JURISDICTIONAL COST )
ALLOCATION PROTOCOL )
ROCKY MOUNTAIN POWER
Direct Testimony of Joelle R. Steward
August 2025

1 I . INTRODUCTION OF WITNESS AND QUALIFITIONS
2 Q. Please state your name, business address and present
3 position with PacifiCorp dba Rocky Mountain Power
4 ("Company") .
5 A. My name is Joelle R. Steward, and my business address
6 is 1407 West North Temple, Salt Lake City, Utah 84116 .
7 I am currently employed as Senior Vice President,
8 Regulation.
9 Q. Please summarize your education and business
10 experience.
11 A. 1 have a Bachelor of Arts degree in Political Science
12 from the University of Oregon and Master of Arts degree
13 in Public Affairs from the Hubert Humphrey Institute
14 of Public Policy at the University of Minnesota.
15 Between 1999 and March 2007, I was employed as a
16 Regulatory Analyst with the Washington Utilities and
17 Transportation Commission. I joined the Company in
18 March 2007 as a Regulatory Manager, responsible for
19 all regulatory filings and proceedings in Oregon. On
20 February 14, 2012, I assumed responsibilities
21 overseeing cost of service and pricing for the
22 Company. In May 2015, I assumed broader oversight over
23 regulatory affairs in addition to the cost of service
24 and pricing responsibilities . In 2017, I assumed the
25 role as Vice President, Regulation for Rocky Mountain
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Rocky Mountain Power

1 Power; and in November 2021, I assumed my current role
2 as Senior Vice President, Regulation for the Company.
3 Q. Have you appeared as a witness in previous regulatory
4 proceedings?
5 A. Yes . I have testified on various matters in the states
6 of Idaho, Utah, Wyoming, Oregon, and Washington.
7 II . PURPOSE OF TESTIMONY
8 Q. What is the purpose of your testimony?
9 A. The purpose of my testimony is to describe and support
10 the Company' s new inter-jurisdictional cost-
11 allocation methodology, the 2026 PacifiCorp Inter-
12 Jurisdictional Allocation Protocol ("2026 Protocol")
13 for use in Idaho, Utah, Wyoming, California, and
14 Oregon (collectively, the "Five States") . I discuss
15 the Company' s previous cost-allocation methodology
16 developed through the Multi-State Process ("MSP") and
17 summarize the standards the Idaho Public Utilities
18 Commission ("Commission") has applied in reviewing
19 these past methodologies . I explain the Company' s
20 phased filing of its new inter-jurisdictional cost-
21 allocation methodology, beginning with the Washington
22 2026 Protocol in April 2025, and the filing of the
23 2026 Protocol in Idaho and other states in July 2025 .
24 I outline the specific provisions of the 2026 Protocol
25 and explain how the recommended modifications to the
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Rocky Mountain Power

1 current allocation methodology, the 2020 PacifiCorp
2 Inter-Jurisdictional Allocation Protocol (the "2020
3 Protocol") approved in Case No. PAC-E-19-201 and
4 extended in Case No. PAC-E-23-13, 2 will produce rates
5 that are just and reasonable and provide benefits to
6 Idaho customers .
7 Q. Please summarize your testimony.
8 A. The Company is proposing a new cost allocation
9 methodology, the 2026 Protocol, to replace the
10 expiring 2020 Protocol, realign resources in light of
11 state disallowances of carbon costs, comply with state
12 law, and set the stage for future cost-allocation
13 changes that support diverging state policies . In this
14 filing, the Company proposes allocations based on two
15 resource portfolios—one portfolio for resource
16 allocations to Idaho, Utah, Wyoming, California, and
17 Oregon (the "Five-State Portfolio") and one portfolio
18 for a fixed allocation of resources to Washington (the
19 "Washington Fixed Portfolio") . Together, the
20 portfolios fully allocate all existing resources .
21 Costs for existing resources in the Five-State
1 In the Matter of Rocky Mountain Power's Application for Approval of the
2020 PacifiCorp Inter-Jurisdictional Allocation Protocol, Case No. PAC-
E-19-20, Order No. 34640 (Apr. 22, 2020) .
2 In the Matter of Rocky Mountain Power's Petition for Approval of an
Extension of the 2020 Inter-Jurisdictional Allocation Protocol, Case No.
PAC-E-23-13, Order No. 35984 (Nov. 2, 2023) .
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Rocky Mountain Power

1 Portfolio will continue to be dynamically allocated to
2 the Five States .
3 Because of unique state energy policies,
4 compliance timelines, and the inherent complexity in
5 transitioning from dynamic to fixed allocation
6 factors, the Company proposes a phased implementation
7 of changes to its cost-allocation methodology. The
8 Company began its Phase 1 implementation through the
9 filing of the Washington 2026 Protocol on April 1,
10 2025 . 3 The Washington 2026 Protocol provides for an
11 immediate realignment of the Chehalis generating
12 facility to become a situs resource to Washington,
13 assigns Washington the unallocated share of Rolling
14 Hills Wind which the Public Utility Commission of
15 Oregon previously disallowed, and incorporates a
16 limited realignment of other resources to remove coal
17 from Washington rates by January 1, 2026 . The
18 Washington 2026 Protocol also proposes to move from
19 dynamic allocation factors (System Generation or SG)
20 to fixed allocation factors (Fixed System Generation
21 or SG-F) , based on a four-year historical average of
22 relevant load data, for all existing non-emitting and
3 Washington Utilities and Transportation Commission v. PacifiCorp dba
Pacific Power and Light Co. , Docket No. UE-250224, Initial Filing (Apr.
1, 2025) .
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1 natural gas resources assigned to Washington (i .e . ,
2 the Washington Fixed Portfolio) .
3 As discussed in the direct testimony of Company
4 witness Cindy A. Crane, the Company will propose a
5 Phase 2 methodology to support its ability to meet
6 upcoming legal obligations and enable different
7 resource portfolios to comply with individual state or
8 regional energy policy. For example, Wyoming House
9 Bill ("HB") 200 (2020) 4 requires that a portion of load
10 in the state to be served by carbon capture technology
11 by July 1, 2033; HB 166 (2021) 5 establishes a
12 rebuttable presumption against coal or gas fueled
13 plant retirement; Oregon' s HB 2021 (2021) 6 and Senate
14 Bill ("SB") 1547 (2016) 7 set resource and emissions
15 targets starting in 2030; Utah SB 224 (2024) 8
16 establishes a preference for dispatchable generation;
17 Utah HB 411 (2019) 9 allows for Utah communities to opt-
18 in to programs to reach 100 percent renewable
19 generation by 2030; Washington SB 5116 (2019) , 10 the
20 Clean Energy Transformation Act ("CETA") , requires
21 greenhouse gas neutrality by 2030 and carbon free
4 WYO. STAT. ANN. §37-18-102 (a) (ii)
5 Wyo. STAT. ANN. §37-2-134.
6 OR. REV. STAT. §469A.400 et. seq.
' OR. REV. STAT. §757.518 et. seq.
8 UTAH CODE ANN. § 54-17-1001.
9 UTAH CODE ANN. § 54-17-901 et. seq.
ie WASH. REV. CODE §19.405.010 et. seq.
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1 retail electricity by 2045; and Washington HB 2528
2 (2020) 11 the Climate Commitment Act ("CCA") , requires
3 the purchase of allowances for emissions from various
4 sources in the state .
5 Q. Are there other important provisions proposed in the
6 2026 Protocol?
7 A. Yes . These include provisions addressing cost
8 allocations for new large load customers . The costs
9 caused by new large load customers (with an individual
10 customer demand of over 50 megawatts) will be situs
11 assigned when serving the new large load requires the
12 Company to make investments or incur costs for assets
13 placed in service after January 1, 2026 . For these
14 customers, the Company will work within the regulatory
15 framework (i .e . , a special contract or tariff) of that
16 state to assign costs to the new large load customer.
17 Q. Please explain how your testimony is organized.
18 A. My testimony is organized to discuss :
19 • The history and development of the 2026 Protocol;
20 • A review of the standards the Commission has used
21 in the past for reviewing cost-allocation
22 methodologies; and
11 WASH. REV. CODE §70.45.005 et. seq.
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1 • An overview of the 2026 Protocol proposed for Idaho
2 in Phase 1 and its benefits to Idaho customers .
3 Q. Are you also sponsoring any exhibits to your
4 testimony?
5 A. Yes . Exhibit No . 3 to my testimony presents the 2026
6 Protocol . Exhibit No. 4 to my testimony presents the
7 Washington 2026 Protocol .
8 III . HISTORY AND DEVELOPMENT OF THE 2026 PROTOCOL
9 Q. Why is inter-jurisdictional cost allocation necessary
10 for the Company?
11 A. As discussed in the testimony of Ms . Crane, the Company
12 provides retail electric service to more than two
13 million customers in the western states of Idaho,
14 Utah, Wyoming, California, Oregon, and Washington. 12
15 Importantly, the Company recovers the costs of
16 providing retail electric service to customers through
17 rates established in regulatory proceedings in each
18 state . To ensure states receive the appropriate
19 allocation of costs and benefits from the Company' s
20 integrated system, the Company has used the
21 collaborative MSP to address allocation issues . This
22 collaborative process has led to the development and
23 adoption of a series of inter-jurisdictional cost-
24 allocation methods over time .
12 Direct Testimony of Cindy A. Crane at 3 (Aug. 6, 2025) .
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Rocky Mountain Power

1 Q. What cost-allocation method is the Company currently
2 using in Idaho?
3 A. The Company uses the 2020 Protocol in Idaho . The
4 Commission adopted and approved the 2020 Protocol in
5 April 2020 . 13
6 Q. What is the 2020 Protocol?
7 A. The 2020 Protocol is an agreement between the Company
8 and certain parties, including regulatory agency
9 staff, consumer advocates, and other stakeholders in
10 Idaho, Utah, Wyoming, Washington, and Oregon; the
11 agreement also includes a state-specific Washington
12 Inter-Jurisdictional Allocation Methodology
13 ("WIJAM") . The parties to the 2020 Protocol agreed to
14 support commission adoption and use of the 2020
15 Protocol in all Company rate proceedings filed after
16 December 31, 2019, until the end of the "Interim
17 Period" on December 31, 2023 . The Idaho, 14 Utah, 15
13 In the Matter of Rocky Mountain Power's Application for Approval of the
2020 PacifiCorp Inter-Jurisdictional Allocation Protocol, Case No. PAC-
E-19-20, Order No. 34640.
14 In the Matter of Rocky Mountain Power's Application for Approval of the
2020 PacifiCorp Inter-Jurisdictional Allocation Protocol, Case No. PAC-
E-19-20, Order No. 34640 (Apr. 22, 2020) .
is In the Matter of the Application of Rocky Mountain Power for Approval
of the 2020 Inter-Jurisdictional Cost Allocation Agreement, Docket
No. 19-035-42, Order Approving 2020 Protocol (Apr. 15, 2020) .
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1 Wyoming, 16 Washington, 17 and 0regon18 commissions
2 approved the 2020 Protocol in 2020, and the California
3 Public Utilities Commission approved the 2020 Protocol
4 in the Company' s 2022 California general rate case . 19
5 Q. What was the ultimate goal of the 2020 Protocol?
6 A. The 2020 Protocol initiated a fundamental shift to
7 address inter-jurisdictional allocation factors with
8 an ultimate goal to move away from dynamic allocation
9 factors following the Interim Period and move to a
10 cost-allocation protocol with fixed allocation factors
11 for generation resources and state-specific resource
12 portfolios .
13 Q. Did the parties to the 2020 Protocol agree to extend
14 the Interim Period and the duration of the 2020
15 Protocol?
16 A. Yes . In March 2023, the parties agreed to an amendment
17 to the 2020 Protocol to extend the Interim Period and
18 the duration of the 2020 Protocol until December 31,
16 In the Matter of the Application of Rocky Mountain Power for Approval
of the 2020 Inter-Jurisdictional Cost Allocation Agreement, Docket No.
20000-572-EA-19 (Record No 15400) , Order (Dec. 3, 2020) .
17 In the Matter of Washington Utilities and Transportation Commission v.
PacifiCorp d/bla Pacific Power and Light Company, Docket Nos. UE-191024,
et al. , Final Order 09 / 07 / 12 (Dec. 14, 2020) .
18 In the Matter of PacifiCorp, dba Pacific Power, Request to Initiate an
Investigation of the Multi-Jurisdictional Issues and Approve an Inter-
Jurisdictional Cost Allocation Protocol, Docket No. UM 1050, Order No.
20-024 (Jan. 23, 2020) .
19 In the Matter of the Application of PacifiCorp (U901E) , for an Order
Authorizing a General Rate Increase Effective January 1, 2023, Application
22-05-006, Decision 23-12-016 (Dec. 14, 2023) (CPUC Decision 23-12-016) .
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1 2025 . The commissions in Idaho, 20 Utah, 21 Wyoming, 22 and
2 Oregon23 approved the requested extension. Washington
3 did not extend the WIJAM at that time because, by its
4 terms, the WIJAM continues until it is replaced.
5 California' s approval of the 2020 Protocol allowed for
6 the use of that cost-allocation methodology until it
7 is replaced in a future proceeding.
8 Q. Why did the parties seek to extend the Interim Period?
9 A. The 2020 Protocol defined certain unresolved issues as
10 "Framework Issues . " Before the extension, the parties
11 (including Washington parties that were signatories to
12 the 2020 Protocol) engaged in negotiations on the
13 Framework Issues through the Framework Issues
14 Workgroup. In those negotiations, the parties
15 considered alternative resource-allocation methods
16 (including the determination of states' fixed share of
17 new resource acquisitions for future allocations) ,
20 In the Matter of Rocky Mountain Power's Petition for Approval of an
Extension of the 2020 Inter-Jurisdictional Allocation Protocol, Case
No. PAC-E-23-13, Order No. 35984.
21 In the Matter of the Application of Rocky Mountain Power for an
Extension to the 2020 Inter-Jurisdictional Cost Allocation Agreement,
Docket No. 23-035-20, Order Approving Extension of the 2020 Protocol (July
27, 2023) .
22 In the Matter of the Application of Rocky Mountain Power for Authority
to Extend the 2020 Inter-Jurisdictional Cost Allocation Agreement Through
December 31, 2025, 20000-641-EA-23 (Record No. 17280) , Order (Feb. 6,
2024) .
23 In the Matter of PacifiCorp, dba Pacific Power, Request to Initiate an
Investigation of the Multi-Jurisdictional Issues and Approve an Inter-
Jurisdictional Cost Allocation Protocol, Docket No. UM 1050, Order No.
23-229 (June 30, 2023) .
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1 which they agreed warranted further review. The
2 extension allowed the parties to continue discussions
3 seeking to resolve the Framework Issues for a cost-
4 allocation methodology for the post-Interim Period.
5 Q. Why did the Commission ultimately agree to extend the
6 2020 Protocol?
7 A. The Commission approved the extension noting that
8 varying jurisdictional allocation methods could arise
9 that may result in the Company recovering more or less
10 than its prudently incurred costs, which could lead to
11 the Company encountering incentives to favor certain
12 states based upon their allocation protocols—not the
13 health of the system. 24
14 Q. Was the Framework Issues Workgroup able to reach
15 consensus on the Framework Issues?
16 A. No . The Framework Issues Workgroup met for several
17 years, but it was not able to reach consensus on a
18 further extension of the 2020 Protocol or the terms of
19 a replacement cost-allocation methodology by the end
20 of the Interim Period. In July 2024, the Company
21 informed its commissions that, given the
22 circumstances, it would propose a new cost-allocation
24 In the Matter of Rocky Mountain Power's Petition for Approval of an
Extension of the 2020 Inter-Jurisdictional Allocation Protocol, Case No.
PAC-E-23-13, Order No. 35984 at 3.
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1 methodology by December 31, 2025, in accordance with
2 Section 2 .2 . 3 of the 2020 Protocol . 25
3 Q. What are the principal challenges to the current cost-
4 allocation methodology that the Company has tried to
5 address through its proposed 2026 Protocol?
6 A. For decades, the Company has relied on cost-allocation
7 methods that dynamically allocate total system costs
8 to states . A foundational principle of these cost-
9 allocation protocols has been the use of the Company' s
10 system as a single whole : except for distribution, all
11 states were served from a common portfolio of assets,
12 including generation assets, which enabled the Company
13 to cost effectively plan for and operate as an
14 integrated whole, resulting in cost savings for all
15 customers . However, divergent state policies across
16 the Company' s six-state service territory are
17 increasingly challenging this foundational principle .
18 For example, Oregon SB 1547, 26 passed by the
19 Oregon legislature in 2016, requires the elimination
25 Section 2.2.3 of the 2020 Protocol reads: "If the Company determines
that it is unlikely that a Post-Interim Period Method agreement will be
reached before the end of the Interim Period, then the Company will
propose an allocation method for the Post-Interim Period for consideration
by the Commissions. Parties are free to take any position regarding
PacifiCorp's proposal, including proposing alternative allocation
methodologies, or initiating a complaint or investigation of PacifiCorp's
proposal."
26 In 2016, the Oregon Legislature enacted SB 1547 that, among other
things, increased the state's renewable portfolio standards (RPS) for
electricity providers. The bill also requires the Commission to conduct
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1 of coal from the electricity supplies to Oregon
2 customers of the Company by 2030 . 27 Oregon' s
3 requirement to remove coal from electricity supplies
4 will necessarily result in Oregon not being allocated
5 the costs and benefits of coal-fired generation while
6 other states continue to include those resources in
7 their electricity supply and in rates .
8 Divergent state policies have expanded since
9 that time, with California, 28 Oregon, 29 and Washington30
10 establishing zero emissions goals, Wyoming
11 establishing a carbon capture technology goal3l and
12 standards for the evaluation of thermal retirement, 32
13 and Utah enacting the Community Renewable Energy Act33
14 and establishing a preference for dispatchable
15 generation. 34
16 Q. How have the challenges of diverging state policies
17 been addressed in the 2026 Protocol?
an investigation and report to the Legislature on the impact of the
increased RPS requirements on (1) rates; (2) greenhouse gas emissions;
(3) electrical system reliability; (4) allocation of risk between electric
utilities and their customers; (5) cost recovery for the generation of
qualifying electricity; (6) resource procurement process; and (7)
forecasting of and rate treatment of projected state and federal
production tax credits. These requirements were first introduced in the
Oregon Legislature as HB 4036 but were later moved into SB 1547.
27 OR. REV. STAT. §757.518 (2) .
28 CAL. PUB. UTIL. CODE §454.53.
29 OR. REV. STAT. §469A.410 (1) (c) .
30 WASH. REV. CODE §19.405 et seq.
31 Wyo. STAT. ANN §37-18-102.
32 Wyo. STAT. ANN §37-2-134.
33 UTAH CODE ANN. §54-17-901.
34 UTAH CODE ANN. §54-17-1001.
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Rocky Mountain Power

1 A. As stated by Ms . Crane, states' energy policies
2 continue to develop and are being implemented in ways
3 that make it increasingly difficult for the Company to
4 operate and dispatch a single resource portfolio for
5 all customers across all jurisdictions while meeting
6 its legal obligations in each state . The 2026 Protocol
7 defines a Five-State Portfolio of resources, which
8 will continue to be dynamically allocated until the
9 cost-allocation methodology transitions to fixed
10 allocation factors planned for Phase 2 . Further, the
11 2026 Protocol proposes flexibility when allocating
12 costs for new resources to allow for state autonomy
13 when procuring new resources needed to achieve state-
14 specific policy objectives .
15 Q. Has the Company already submitted filings to state
16 regulatory bodies to implement a new cost-allocation
17 methodology under Section 2 .2 . 3 of the 2020 Protocol?
18 A. Yes . The Company filed the Washington 2026 Protocol
19 with the Washington Utilities and Transportation
20 Commission on April 1, 2025, in docket UE-250224 . This
21 proceeding is now pending, with a target decision date
22 that permits implementation of the Washington 2026
23 Protocol by January 1, 2026 .
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1 Q. Does the Company seek approval of the 2026 Protocol
2 under the same general timeframe as the Washington
3 2026 Protocol?
4 A. Yes, as much as possible, the Company hopes to keep
5 all states in sync as resources are realigned under
6 the 2026 Protocol and the Washington 2026 Protocol .
7 IV. STANDARD FOR REVIEW OF THE 2026 PROTOCOL
8 Q. Is the Company seeking to replace the current cost-
9 allocation methodology approved by the Commission in
10 Case No. PAC-E-19-20, and extended in Case No. PAC-E-
11 23-13?
12 A. Yes, the Company requests that the Commission approve
13 the new cost-allocation methodology in the 2026
14 Protocol to supersede the current allocation
15 methodology from the 2020 Protocol .
16 Q. The Company has presented previous cost-allocation
17 methodologies as part of an agreement among most
18 stakeholders, whereas the Company is seeking
19 stakeholder consideration of its proposal in this case
20 through the Commission' s contested case process . What
21 standard should the Commission apply to its review of
22 the Company' s filing?
23 A. In past cases the Commission has reviewed the proposed
24 allocation methodologies under Idaho Code § 61-501,
25 61-502, § 61-503 . Idaho Code § 61-501 specifically
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1 vests the Commission with the power and jurisdiction
2 to supervise and regulate the Company. The Commission
3 applies the standard of reasonableness to balance
4 fairness to the public as well as to the public utility
5 to determine just and reasonable rates .
6 V. THE 2026 PROTOCOL
7 Q. What is the 2026 Protocol?
8 A. The 2026 Protocol describes the Company' s allocation
9 and assignment methodology and future transition to
10 accommodate diverging resource35 portfolios needed to
11 address individual state energy policy. The 2026
12 Protocol is intended to : (1) supersede the 2020
13 Protocol for the Five States; and (2) operate in
14 conjunction with the Washington 2026 Protocol . Subject
15 to the provisions in the 2026 Protocol, once approved
16 by the appropriate state bodies charged with issuing
17 orders to establish rates, the 2026 Protocol can be
18 used to set just and reasonable rates in rate filings
19 in the Five States .
20 The 2026 Protocol implements components of the
21 2020 Protocol' s post-interim methodology framework,
22 modified to address the changing energy landscape . The
23 2026 Protocol realigns existing resources to enable
35 Resource includes both electric generation facilities and storage
technology.
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1 dispatch of different resource portfolios to meet
2 individual or regionally consistent state energy
3 policy mandates and improve planning processes while
4 providing the Company with the opportunity to recover
5 its costs .
6 Q. How does the 2026 Protocol benefit Idaho customers?
7 A. The 2026 Protocol benefits Idaho customers by
8 increasing Idaho' s ability to meet its future resource
9 adequacy and energy needs while providing flexibility
10 in the allocation of new resources needed to comply
11 with other state' s energy policies . In this way, the
12 2026 Protocol better aligns with cost-causation
13 principles as the Company seeks to comply with
14 diverging state policies, whereby Idaho customers will
15 be responsible for costs that reflect Idaho' s specific
16 needs .
17 Q. How will the 2026 Protocol impact revenue requirement
18 in Idaho?
19 A. The Company calculated the revenue requirement impact
20 by comparing the allocation of generation resources
21 using the 2020 Protocol compared to the 2026 Protocol .
22 For Idaho, the estimated revenue requirement increases
23 by approximately $2 . 5 million or 0 . 7 percent
24 ($0 . 9 million for net power costs ("NPC") and
25 $1 . 6 million for other costs) . Company witness Shelley
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I E . McCoy discusses the Company' s calculation of the
2 revenue requirement impact in more detail in her
3 testimony, and Company witness Ramon J. Mitchell
4 discusses the impact on NPC .
5 Q. How does the Company propose to track the cost-
6 allocation differences from implementing the 2026
7 Protocol until the costs are reflected in rates?
8 A. The Company plans to file a deferral to track the cost-
9 allocation differences from implementing the 2026
10 Protocol until these changes are reflected in rates .
11 Q. Please provide an overview of the sections of the 2026
12 Protocol .
13 A. The next section of my testimony will walk through the
14 key provisions of Sections 1 . 0 through 15 . 0 of the
15 2026 Protocol .
16 Section 1 . 0—Introduction
17 Q. Does the 2026 Protocol provide an introduction and
18 broader context for this filing?
19 A. Yes . The introduction summarizes the purpose and need
20 for the 2026 Protocol including how it enables the
21 Company to respond to several major changes in the
22 energy landscape, and as discussed above, realignment
23 of certain existing generation resources .
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1 Q. Does the 2026 Protocol prejudge prudence or limit the
2 Commission' s responsibility to determine prudence and
3 just and reasonable rates?
4 A. No . Section 1 . 0 of the 2026 Protocol makes clear that
5 the proposed allocation of a particular expense or new
6 investment to a state under the 2026 Protocol is not
7 intended to and will not prejudge the prudence of that
8 cost or the extent to which any particular cost may be
9 reflected in rates .
10 Q. Will the 2026 Protocol abrogate any of the
11 Commission' s rights or obligations?
12 A. No . Nothing in the 2026 Protocol is intended to
13 abrogate any commission' s right or obligation to
14 determine fair, just, and reasonable rates .
15 Section 2 . 0—Effective Period and Phase 1 Implementation
16 Q. What is the effective period of the 2026 Protocol?
17 A. Upon approval by the state commission in each
18 jurisdiction, the 2026 Protocol will be effective for
19 new regulatory rate filings in that jurisdiction
20 beginning January 1, 2026, and will remain effective
21 until superseded by a future amendment or new protocol
22 approved by the state commissions .
23 Q. Does the Company propose implementing a new cost-
24 allocation methodology in a single set of filings this
25 year?
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Rocky Mountain Power

1 A. No . As discussed above, the Company proposes a phased
2 approach for implementing its modified cost-allocation
3 methodology. Phase 1 includes the recommended adoption
4 of the Washington 2026 Protocol and the 2026 Protocol
5 in the Five States . The Company will present a Phase
6 2 filing to the state regulatory commissions to be
7 effective no later than 2030 . Phase 2 will encompass
8 additional elements, which may include : setting fixed
9 allocations among the Five States; the implementation
10 of a market settlement approach to NPC; the
11 reallocation of costs for resources needed to comply
12 with state laws that have binding compliance
13 milestones beginning 2030; and the allocation of
14 transmission costs .
15 Q. Why is it important to use a phased approach?
16 A. The scope of the 2026 Protocol primarily addresses the
17 expiration of the 2020 Protocol, Washington' s exit
18 from coal, and state disallowance of carbon costs .
19 Phase 2 will be significantly broader since it will
20 address complex operational and planning issues . The
21 Company needs additional time to develop a
22 comprehensive proposal for Phase 2 . Approval of the
23 2026 Protocol, which is a principled allocation
24 methodology, is necessary to replace the 2020 Protocol
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1 while the allocation methodology in Phase 2 is
2 developed.
3 Section 3 . 0 Allocation of Resources
4 Section 3. 1 - Existing Resource Portfolios
5 Q. Please describe the allocation of existing resources
6 under the 2026 Protocol.
7 A. There will be two portfolios of existing resources-
8 the Five-State Portfolio and the Washington Fixed
9 Portfolio . Resources in the Five-State Portfolio will
10 be dynamically allocated. The Washington Fixed
11 Portfolio is based on a fixed allocation or a situs
12 assignment of certain resources, as reflected in the
13 Washington 2026 Protocol .
14 There are four different subsets of resources
15 in the two portfolios . The first subset of resources
16 includes those that are allocated to both portfolios
17 (the Five-State Portfolio and the Washington Fixed
18 Portfolio) . The second subset is for resources that
19 are fully allocated to the Five-State Portfolio and
20 not included in the Washington Fixed Portfolio . The
21 third subset is for Rolling Hills Wind, which is
22 included in the Five-State Portfolio, with the
23 exception of Oregon, and in the Washington Fixed
24 Portfolio . The fourth subset includes Washington
25 situs-assigned resources that are fully allocated to
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1 the Washington Fixed Portfolio . The subsets of
2 resources included in the two portfolios are
3 summarized in the table below.
Plant Five-State Washington
Name/Resource Portfolio Fixed Total
Type (OR, CA, ID,UT, WY) portfolio
Resource Subset 1
Jim Bridger
Units 1 & 2 92 . 10% 7 . 90% 100%
Other Existing
Non-Emitting
92 . 10% 7 . 90% 100%
Resources (non-
QFs)
Legacy
Interruptible 92 . 10% 7 . 90% 100%
Contracts
Resource Subset 2
Other Natural
Gas and Coal 100% 0% 100%
(non-QFs)
Five State QFs 100% 0% 100%
Resource Subset 3
Rolling Hills
Wind (excluding 65 . 13% 34 . 87% 100%
OR)
Resource Subset 4
WA QFs 0% 100% 100%
Chehalis 0% 100% 100%
4 Section 3.2 - Dynamic Allocation of Five-State
5 Portfolio
6 Q. Please explain the Five-State Portfolio in more
7 detail .
8 A. As discussed above, the Five-State Portfolio will be
9 dynamically allocated for customers in Idaho, Utah,
10 Wyoming, California, and Oregon. Non-fuel generation
11 costs will be allocated using one of three different
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1 versions of a Five-State system generation factor
2 ("SG5") . The three versions of the SG5 factor account
3 for the different subsets of resources that are
4 included in the Five-State Portfolio . For non-emitting
5 resources (excluding Rolling Hills Wind and qualifying
6 facilities or "QFs") , Jim Bridger Units 1 and 2, and
7 legacy interruptible contracts, the Five States will
8 be allocated costs using a dynamic generation factor
9 excluding the fixed percentage allocated to Washington
10 ("SG5A") . For all other thermal units, excluding
11 Chehalis, and certain QFs, states will be allocated
12 costs using a dynamic generation factor among the Five
13 States ("SGSB") . For Rolling Hills Wind, states will
14 be allocated costs using a dynamic generation factor
15 among Idaho, Utah, Wyoming, and California excluding
16 the fixed percentage allocated to Washington
17 ("SGSC") . 36
18 Resource Subset 1
19 Q. For resource subset 1 , how does the Company propose to
20 allocate the non-emitting resources (excluding Rolling
21 Hills Wind and QFs) , Jim Bridger Units 1 and 2 , and
22 legacy interruptible contract resources?
36 Washington has been allocated the unallocated percentage of Rolling
Hills that had been previously disallowed from Oregon rates in 2008. See
In the Matter of PacifiCorp d1bla Pacific Power, 2009 Renewable Adjustment
Clause, Docket No. UE 200, Order No. 08-548 at 19-21 (Nov. 14, 2008) .
Steward, Di 23
Rocky Mountain Power

1 A. Under the SG5A factor, the non-emitting resources
2 (excluding Rolling Hills Wind and QFs) , Jim Bridger
3 Units 1 and 2 natural gas facilities, and legacy
4 interruptible contracts will be allocated dynamically
5 to the Five States, while Washington will be allocated
6 a fixed share of these resources .
7 Q. What is the SG5A factor for Idaho?
8 A. While dynamic allocation means that the relative
9 percentage used to serve customers in the Five States
10 will vary on a year-to-year basis based on each state' s
11 relative load compared to the combined load of the
12 Five States, the Company estimates approximately
13 6 . 0159 percent of the costs from these resources will
14 be allocated to Idaho customers in 2026 .
15 Q. Why are the Jim Bridger Units 1 and 2 natural gas
16 facilities included in resource subset 1?
17 A. With the conversion of Jim Bridger Units 1 and 2 from
18 coal to natural gas, these resources provide capacity
19 benefits to the entire system and can be managed to
20 meet energy policies in all states to maintain
21 reliability. Accordingly, these resources will be
22 allocated to all states, similar to the non-emitting
23 resources . This essentially maintains the status quo
24 for these resources .
Steward, Di 24
Rocky Mountain Power

1 Resource Subset 2
2 Q. What resources are in resource subset 2?
3 A. Resource subset 2 includes non-QF coal and natural gas
4 resources (other than Chehalis and Jim Bridger Units
5 1 and 2) and certain QFs .
6 Q. How does the Company propose allocating these
7 resources in the 2026 Protocol?
8 A. All of the costs associated with these resources will
9 be allocated dynamically to the Five States using the
10 SG5B allocation factor.
11 Q. Will Washington receive a fixed percentage of these
12 resources?
13 A. No . These resources, with the exception of Hermiston,
14 were either not previously included in Washington
15 rates or must be removed to comply with Washington' s
16 CETA. Hermiston is included to balance resource
17 capacity given the realignment of Chehalis to address
18 Washington CCA requirements .
19 Q. What QFs are included in this resource subset?
20 A. Legacy QF power purchase agreements ("PPAs") , which
21 have previously been treated as system resources, are
22 included in resource subset 2 . As the legacy QF PPAs
23 expire, should they be renewed they will be removed
24 from this resource subset and treated as situs
25 resources based on the state where the power is
Steward, Di 25
Rocky Mountain Power

1 delivered to the Company' s system under a QF PPA
2 subject to that state commission' s authority.
3 Q. What is the SGSB allocation factor for Idaho?
4 A. While dynamic allocation means that the relative
5 percentage used to serve customers in the Five States
6 will vary on a year-to-year basis based on each state' s
7 relative load compared to the combined load of the
8 Five States, the Company estimates approximately
9 6 . 5317 percent of the costs from these resources will
10 be used to serve Idaho customers in 2026 .
11 Resource Subset 3
12 Q. What resources are in resource subset 3?
13 A. Resource subset 3 includes Rolling Hills Wind.
14 Q. What is Rolling Hills Wind?
15 A. Rolling Hills Wind is a 100 megawatt wind project sited
16 at the reclaimed Dave Johnston coal mine in Wyoming.
17 The facility began operations in 2009, and the Company
18 completed a repowering project at Rolling Hills in
19 2019 .
20 Q. Under the 2026 Protocol, will any generation from
21 Rolling Hills Wind be allocated to Idaho?
22 A. Yes . Idaho customers will receive a dynamically
23 allocated share of Rolling Hills equal to its current
24 allocation. In 2008, the Public Utility Commission of
25 Oregon disallowed recovery of Rolling Hills Wind costs
Steward, Di 26
Rocky Mountain Power

1 and excluded it from Oregon rates . 37 As a result,
2 approximately 26 percent of Rolling Hills Wind costs
3 and benefits are not currently allocated to any state .
4 The Company proposes to allocate the unallocated
5 portion of Rolling Hills Wind to Washington,
6 increasing Washington' s share of Rolling Hills Wind
7 from 7 . 8971 percent to 34 . 8727 percent . The remainder
8 of Rolling Hills Wind will be dynamically allocated to
9 Idaho, Utah, Wyoming, and California.
10 Resource Subset 4
11 Q. What resources are in resource subset 4?
12 A. Resource subset 4 includes Washington QFs and
13 Chehalis .
14 Q. Are any of these resources allocated to Idaho under
15 the 2026 Protocol?
16 A. No .
17 Q. Does situs assignment of Chehalis to Washington impact
18 NPC costs in Idaho?
19 A. As discussed in the testimony of Mr. Mitchell, not
20 taking into account costs related to compliance with
21 the Washington CCA, the total-Company NPC increase for
22 the Five States is estimated to be approximately
37 In the Matter of PacifiCorp, dba Pacific Power 2009 Renewable Adjustment
Clause Schedule 202, Docket No. UE 200, Order No. 08-548 at 20 (Nov. 14,
2008) .
Steward, Di 27
Rocky Mountain Power

1 $15 . 9 million. 38 For Idaho specifically, the initial
2 NPC impact calculation without Washington shows an
3 approximate NPC increase of $0 . 94 million, or 0 . 61
4 percent . 39
5 Importantly, however, Washington CCA costs for
6 2026 are forecasted to be approximately $54 . 9 million
7 on a total-company basis . 40 Once Chehalis is situs
8 assigned to Washington, the obligation to pay these
9 costs (an obligation that is now subject to litigation
10 in many states) is removed from the Five States . If
11 Washington CCA costs were factored into the Company' s
12 analysis, NPC decreases by approximately $31 . 1 million
13 in the Five States under the 2026 Protocol, or by $2 . 4
14 million, or 1 . 55 percent, on an Idaho-allocated
15 basis . 41
16 Section 3. 3 - Legacy Interruptible Contracts
17 Q. How does the Company propose to allocate the costs for
18 legacy interruptible contracts under the 2026
19 Protocol?
20 A. Under the 2026 Protocol, the Company proposes to
21 allocate the costs for legacy interruptible contracts
22 using the SGSA factor. This is consistent with current
38 See Direct Testimony of Ramon J. Mitchell at 13-14.
39 Id. at 13.
40 See Id. at 14-15.
41 Id. at 14.
Steward, Di 28
Rocky Mountain Power

1 practice and reflects the benefits provided by these
2 contracts to all states .
3 Q. How are benefits provided by these contracts?
4 A. Interruptible industrial loads provide benefits across
5 all states because they provide the ability to
6 coordinate the rapid reduction of large increments of
7 load in response to system or interconnection-wide
8 events . This can produce benefits for all customers by
9 reducing the impact of high market prices .
10 Section 3. 4 - Qualifying Facilities
11 Q. How does the Company propose to allocate costs of QF
12 PPAs?
13 A. The costs, any corresponding renewable energy
14 certificates ("RECs") , as applicable, and all
15 environmental attributes of QF PPAs are allocated
16 based on when the PPA was fully executed—on or before
17 December 31, 2019, or after December 31, 2019 .
18 Q. How are the costs and benefits for QF PPAs executed on
19 or before December 31 , 2019, allocated?
20 A. As mentioned above in the discussion of resource
21 subset 2, the costs, any corresponding RECs, as
22 applicable, and all environmental attributes of the QF
Steward, Di 29
Rocky Mountain Power

1 PPAs fully executed on or before December 31, 201942
2 will be allocated using the SG5B factor.
3 Q. What about the costs for QF PPAs executed after
4 December 31 , 2019?
5 A. The costs of QF PPAs fully executed or as to which a
6 legally enforceable obligation existed after
7 December 31, 2019, will be dynamically allocated with
8 the SG5B factor, up to the level of cost that is based
9 on a forecasted reasonable energy price . Any costs of
10 a QF PPA above the forecasted reasonable energy price
11 will be situs assigned and allocated to the state of
12 origin. The corresponding RECs, as applicable, and all
13 environmental attributes from the post-2020 QF PPAs
14 will also be situs assigned to the state of origin.
15 Q. What is the forecasted reasonable energy price?
16 A. The forecasted reasonable energy price is a single
17 blended market price derived from the Company' s
18 official forward price curve, scaled for hourly
19 prices . The calculation for this single blended market
20 price is discussed in Section 3 . 4 . 1 of the 2026
21 Protocol .
42 This includes all QF PPAs that were system allocated under the 2020
Protocol.
Steward, Di 30
Rocky Mountain Power

1 Q. Does the 2026 Protocol propose any other notable
2 deadlines regarding changes to the allocation of costs
3 and benefits for QF PPAs?
4 A. Yes . No later than January 1, 2030, the costs and all
5 environmental attributes for QF PPAs will be situs
6 assigned to the state of origin regardless of when the
7 QF PPA was executed.
8 Section 3. 5 - Demand-Side Management
9 Q. Does the 2026 Protocol change how demand-side
10 management program costs are allocated from the 2020
11 Protocol?
12 A. No . Costs associated with demand-side management
13 programs will continue to be directly allocated to the
14 state in which the investment is made (i .e . , situs
15 assigned) . Benefits from these programs, in the form
16 of reduced consumption and contribution to coincident
17 peak, will be reflected in the load-based dynamic
18 allocation factors .
19 Section 3. 6 - Allocation of New Resources
20 Q. How are new resources defined under the 2026 Protocol?
21 A. New resources are any non-QF generating facility
22 procured after April 1, 2025 . In this context, a
23 resource is `procured" when a generation or resource
24 contract is effective .
Steward, Di 31
Rocky Mountain Power

1 Q. How does the Company plan to allocate costs and
2 benefits for new generation resources?
3 A. The Company will propose an allocation for new
4 resources with a term or depreciable life longer than
5 three years at or before the time when a prudence
6 review occurs . New resources with a term or
7 depreciable life less than three years will be
8 allocated in accordance with the NPC calculation under
9 Section 4 . 0 of the 2026 Protocol, discussed below.
10 Section 3. 7 - State-Imposed Costs
11 Q. What are state-imposed costs?
12 A. State-imposed costs include, but are not limited to,
13 taxes, fees, and costs for environmental permitting
14 imposed on a generation resource or associated assets .
15 Q. How does the 2026 Protocol address state-imposed
16 costs?
17 A. Under the 2026 Protocol, state-imposed costs are
18 generally allocated consistent with the allocation of
19 the resource under the Five-State Portfolio .
20 Q. What about costs and revenues related to a state
21 greenhouse gas pricing program?
22 A. If a state imposes a carbon or greenhouse gas pricing
23 program (for example, a cap-and-trade program or a
24 carbon tax) on a resource, all costs and revenues
25 associated with that program will be situs assigned to
Steward, Di 32
Rocky Mountain Power

1 the state imposing that obligation. If the state
2 imposing a carbon or greenhouse gas pricing program is
3 not a jurisdiction with Company retail customers, or
4 if the costs are imposed by the federal government,
5 then the costs will be allocated consistent with the
6 Five-State Portfolio .
7 Q. How does the 2026 Protocol allocate the costs and
8 revenues for other state programs and initiatives?
9 A. Under the 2026 Protocol, costs and revenues will be
10 situs assigned when they are incurred to comply with
11 a program or initiative imposed by a particular state
12 on the Company in its role as a public utility serving
13 customers in that state . This includes portfolio
14 standards, customer generation programs, emissions
15 performance standards, voluntary renewable energy
16 programs, capacity standard programs, electric vehicle
17 programs, and the acquisition of RECs .
18 Section 3. 8 - Allocation of Decommissioning and
19 Closure Costs
20 Q. How does the 2026 Protocol allocate costs at plant
21 closure?
22 A. Upon closure of a resource before 2030, any remaining
23 rate base and associated expense, including
24 decommissioning costs, will be allocated consistent
25 with the dynamic allocation of the resource as part of
26 the Five-State Portfolio. For resources with a closure
Steward, Di 33
Rocky Mountain Power

1 date of 2030 or later, the Company will propose a
2 methodology for the treatment of closure and
3 decommissioning costs in Phase 2 of the 2026 Protocol .
4 Section 3. 9 - Capital Additions to Coal-Fired
5 Resources Before 2030
6 Q. How will the Company allocate costs associated capital
7 additions made before 2030?
8 A. To facilitate removal of coal generation from Oregon
9 rates in compliance with the requirements of Oregon
10 SB 1547, Oregon customers will be allocated a time-
11 based pro rata share of the costs for capital additions
12 to coal-fired resources made before 2030 . The pro rata
13 share would be based on the number of months left in
14 the Oregon depreciable life of the resource compared
15 to the number of months left in the longest depreciable
16 life of the resources used in Idaho, Utah, Wyoming, or
17 California. That ratio would then be applied to the
18 SBSB factor share of the investment . Costs associated
19 with any such capital additions will be dynamically
20 reallocated to the remaining states following Oregon' s
21 exit from the resource .
22 Section 4 . 0 Allocation of Net Power Costs
23 Q. How is NPC allocated in the 2026 Protocol?
24 A. For actual NPC filings, the Company will use the
25 allocation methodology in place when the NPC was or
26 will be incurred, to align the timing of the actual
Steward, Di 34
Rocky Mountain Power

1 costs incurred with the applicable allocation method
2 for cost recovery for that period. Before the
3 implementation of Phase 2, NPC will continue to be
4 dynamically allocated consistently with the allocation
5 factors identified in the 2026 Protocol . For NPC
6 filings, the allocation methodology that will be used
7 will be based upon the table below.
Annual
Actual NPC Year in Actual
Filing Filed Review Base NPC NPC
ECAM 2026 2025 2020 2020
Protocol Protocol
ECAM 2027 2026 2020 2026
Protocol Protocol
8 Q. What factors will be used to allocate NPC?
9 A. NPC will be allocated consistent with the allocation
10 factors identified for the appropriate FERC Account in
11 Appendix B of the 2026 Protocol . States will also
12 receive an allocation of the costs or revenues
13 resulting from the valuation of the difference between
14 the Five-State Portfolio' s load and allocated
15 resources using a dynamic SG5B factor, as described in
16 more detail by Mr. Mitchell . Situs generation
17 resources will continue to use the lower of cost or
18 market methodology, which is also further explained by
19 Mr. Mitchell .
20 Q. Does the Company anticipate changing its methodology
21 for allocating NPC?
Steward, Di 35
Rocky Mountain Power

1 A. Yes . In Phase 2, as the Company moves to fixed
2 allocation factors, the Company proposes implementing
3 a market settlement-based NPC allocation methodology
4 to ensure that NPC can be allocated at a more granular
5 level to meet state-specific portfolios . Company
6 witness Michael G. Wilding discusses the Company' s
7 transition to nodal pricing, including the nodal-
8 pricing methodology, for NPC in greater detail in his
9 testimony. A nodal pricing regime will allow states to
10 pursue portfolios while maintaining the benefits of
11 system dispatch as much as practicable .
12 Section 5 . 0—Transmission Costs
13 Q. How has the allocation of system transmission costs
14 changed under the 2026 Protocol?
15 A. As is done in the 2020 Protocol, the Company proposes
16 that all existing system transmission costs continue
17 to be dynamically allocated among the Five States and
18 Washington using the SG factor. This allocation may be
19 subject to additional review and amendment in Phase 2 .
20 The only exception to this methodology applies to new
21 large loads, which is discussed in Section 13 . 0 of the
22 2026 Protocol .
23 Q. What percentage of system transmission does the
24 Company propose allocating to Idaho customers?
Steward, Di 36
Rocky Mountain Power

1 A. The SG factor would result in allocating approximately
2 6 . 0436 percent of system transmission costs to Idaho
3 customers, which will vary on a year-to-year basis
4 based on each state' s relative load compared to the
5 combined load. But for the exception pertaining to new
6 large loads, this is unchanged from the allocation
7 under 2020 Protocol and therefore is rate neutral .
8 Section 6. 0 Allocation of Distribution Costs
9 Q. Does the Company propose changing the allocation of
10 distribution-related expenses and capital costs under
11 the 2026 Protocol?
12 A. No . All distribution-related expenses and capital
13 costs that can be directly allocated will be directly
14 allocated (100 percent) to the states where the
15 related distribution facilities are located.
16 Section 7 . 0—Allocation of System Overhead Costs
17 Q. Does the Company propose changing the allocation of
18 system overhead ("SO") expenses under the 2026
19 Protocol?
20 A. While the Company proposes to continue to allocate
21 costs that support more than one function, such as
22 generation, transmission, or distribution plant, on
23 the SO factor, the calculation of the factor is updated
24 to be based on an equal one-third weighting of the
25 system capacity ("SC") factor, system energy ("SE")
Steward, Di 37
Rocky Mountain Power

I factor, and system gross plant distribution ("SGPD")
2 factor as shown in Appendix C to the 2026 Protocol .
3 This change in the allocation calculation is necessary
4 to reflect the fixed allocations of resources between
5 the Washington Fixed Portfolio and Five-State
6 Portfolio and is explained in more detail by Company
7 witness McCoy.
8 Section 8 . 0 Allocation of Taxes and Fees
9 Q. What has the Company changed about the allocation of
10 taxes and fees?
11 A. The treatment and allocation of taxes and fees
12 continue to remain largely the same as was approved in
13 the 2020 Protocol . Idaho has recently replaced its
14 property tax with a newly enacted Kilowatt Hour tax.
15 For purposes of the 2026 Protocol, this will continue
16 to be considered and allocated similar to the previous
17 Idaho property tax. No other revisions to the
18 allocation of taxes or fees are included in the 2026
19 Protocol . Ms . McCoy discusses the allocation of taxes
20 and fees more thoroughly in her direct testimony.
21 Section 9. 0 Allocation of Administrative and General Costs
22 Q. Does the Company propose changing how administrative
23 and general costs are allocated in the 2026 protocol?
24 A. Yes . Administrative and general costs, general plant
25 costs, and intangible plant costs, both expenses and
Steward, Di 38
Rocky Mountain Power

I investments, which can be directly allocated will be
2 directly allocated to the appropriate state . Those
3 costs that cannot be directly allocated will be
4 allocated among all states consistent with the factors
5 set forth in Appendix B as they were in the 2020
6 Protocol .
7 Section 10 . 0—Treatment of Oregon Direct Access Programs
8 Q. Under the 2026 Protocol, does the Company propose any
9 changes to how it currently addresses loads lost to
10 Oregon Direct Access Programs?
11 A. No, the Company does not propose any changes to its
12 current treatment of loads lost to Oregon Direct
13 Access Programs .
14 Section 11 . 0—Loss or Increase in Load
15 Q. Is there any change in how the 2026 Protocol treats
16 loss or increase in load from the 2020 Protocol?
17 A. No .
18 Section 12 . 0—Excess Liability Insurance and Liability
19 Allocation
20 Q. How will the costs for non-wildfire-related insurance
21 premiums for excess liability and costs for non-
22 wildfire liability be allocated among the states?
23 A. The costs for non-wildfire-related insurance premiums
24 for excess liability and costs for non-wildfire
25 liability not covered by insurance will be allocated
26 among the states using the SO factor. The costs for
Steward, Di 39
Rocky Mountain Power

1 any wildfire-related insurance coverage for generation
2 and transmission assets in states where the Company
3 does not have retail customers will be allocated using
4 the SO factor as well . The costs for wildfire-related
5 insurance coverage and liability in retail states will
6 be addressed on a state-by-state basis .
7 Q. Why is the Company proposing to address wildfire-
8 related insurance coverage and liability on a state-
9 by-state basis?
10 A. The Company' s expansive system covers a diverse range
11 of climate and vegetation zones, serving a combination
12 of sparsely populated rural and densely populated
13 urban areas, meaning that wildfire risk is not
14 identical across the system. Moreover, state policies
15 regarding wildfire liability for electric utilities
16 continue to evolve . The Company is currently engaging
17 with stakeholders on the appropriate treatment of
18 wildfire-related insurance coverage and liability for
19 its retail service states and is exploring options
20 beyond standard third-party insurance .
21 Section 13 . 0 Allocation of New Large Load
22 Q. How does the 2026 Protocol address New Large Load
23 customers?
24 A. The costs of New Large Load over 50 megawatts that
25 require the Company to make investments or incur costs
Steward, Di 40
Rocky Mountain Power

1 for assets placed in service after January 1, 2026,
2 will be assigned to the state in which the load is
3 located. The Company will work within potential
4 regulatory frameworks available in Idaho (i .e . , a
5 special contract or tariff) to assign the costs to the
6 New Large Load customer, as determined by the
7 Commission. These costs include, but are not limited
8 to, any new distribution costs, transmission costs,
9 generation costs (including power purchase agreements,
10 as applicable) , and contractual costs for providing
11 electrical service (i .e . , firm third-party
12 transmission rights) .
13 Section 14 . 0 Allocation of Gain or Loss from Sale of Assets
14 Q. How does the 2026 Protocol address the allocation of
15 gains or losses from the sale of assets?
16 A. Section 14 . 0 provides that the allocation of any gains
17 or losses from the sale of Company-owned assets will
18 be based on the assignment of the asset at the time of
19 the sale, unless the asset has been under that
20 assignment less than a calendar year from the
21 execution date of the sale agreement, in which case
22 any gains or losses would be allocated based on the
23 prior assignment shares . This provision is unchanged
24 from the 2020 Protocol .
Steward, Di 41
Rocky Mountain Power

1 Section 15 . 0—Interpretation and Governance
2 Q. Please explain Section 15 . 0 of the 2026 Protocol .
3 A. Section 15 . 0 of the 2026 Protocol provides details
4 regarding the interdependence of commission approvals,
5 establishing that any approval by a given commission
6 is contingent upon the 2026 Protocol being approved
7 unaltered by other commissions . In addition, to the
8 extent that an issue of interpretation causes an
9 allocation difference between multiple jurisdictions,
10 Section 15 . 0 describes the Company' s ability to
11 petition state commissions to amend the 2026 Protocol
12 and resolve any allocation discrepancies .
13 VI . RECOMMENDATION
14 Q. What action do you recommend the Commission take with
15 respect to the Company' s Application?
16 A. I recommend that the Commission approve the 2026
17 Protocol, based on a finding that there is good cause
18 for the Company' s 2026 Protocol, that the 2026
19 Protocol allows the Company an opportunity to recover
20 its prudently incurred costs, ensures that Idaho' s
21 share of costs is equitable among the states subject
22 to the 2026 Protocol, and is reasonable and in the
23 public interest .
24 Q. Does this conclude your direct testimony?
25 A. Yes .
Steward, Di 42
Rocky Mountain Power

Rocky Mountain Power
Exhibit No . 3
Case No . PAC-E-25-14
Witness : Joelle R. Steward
BEFORE THE IDAHO PUBLIC UTILITIES
COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Joelle R. Steward
2026 PacifiCorp Inter-Jurisdictional Allocation Protocol
August 2025

Rocky Mountain Power
Exhibit No.3 1 Page 1 of 46
Case No. PAC-E-25-14
Witness:Joelle R.Steward
2026 PacifiCorp Inter-Jurisdictional Allocation Protocol

Rocky Mountain Power
Exhibit No.3 1 Page 2 of 46
Case No. PAC-E-25-14
Witness:Joelle R.Steward
Contents
1.0 Introduction..........................................................................................................................1
2.0 Effective Period and Phase 1 Implementation.....................................................................3
3.0 Allocation of Resources.......................................................................................................4
3.1 Existing Resource Portfolios............................................................................................4
3.2 Dynamic Allocation of the Five State Portfolio............................................................... 5
3.3 Legacy Interruptible Contracts......................................................................................... 6
3.4 Qualifying Facilities......................................................................................................... 6
3.4.1 Forecasted Reasonable Energy Price.......................................................................... 7
3.5 Demand-Side Management.............................................................................................. 8
3.6 Allocation of New Resources........................................................................................... 8
3.7 State-Imposed Costs......................................................................................................... 8
3.8 Decommissioning and Closure Costs............................................................................... 9
3.9 Capital Additions—Coal Resources with Operational Lives Beyond 2030 .................... 9
4.0 Allocation of Net Power Costs ..........................................................................................10
5.0 Allocation of Transmission Costs......................................................................................11
6.0 Allocation of Distribution Costs........................................................................................11
7.0 Allocation of System Overhead Costs...............................................................................12
8.0 Allocation of Taxes and Fees.............................................................................................12
9.0 Allocation of Administrative and General Costs...............................................................13
10.0 Treatment of Oregon Direct Access Programs ..................................................................13
11.0 Loss or Increase in Load....................................................................................................13
12.0 Excess Liability Insurance and Liability Allocation..........................................................14
13.0 Allocation of Costs for New Large Load...........................................................................14
14.0 Allocation of Gain or Loss from Sale of Assets ................................................................14
15.0 Interpretation and Governance...........................................................................................15
Attached Appendices:
Appendix A Defined Terms
Appendix B —Allocation Factors by Revenue Requirement Components
Appendix C —Algebraic Definitions of Allocation Factors
Appendix D—Legacy Interruptible Contracts

Rocky Mountain Power
Exhibit No.3 1 Page 3 of 46
Case No. PAC-E-25-14
Witness:Joelle R.Steward
1 1.0 Introduction
2 The 2026 PacifiCorp Inter-Jurisdictional Allocation Protocol (the "2026 Protocol")
3 describes PacifiCorp's cost allocation and assignment methodology to take effect on January 1,
4 2026, subject to Commission approvals. The 2026 Protocol is the first phase in a multi-phase
5 process to transition PacifiCorp's cost-allocation methodology to accommodate diverging resource
6 portfolios and changes to operations needed to address individual state energy policies. The 2026
7 Protocol is intended to: (1) supersede the 2020 Protocol' in the Five States; and (2) operate in
8 conjunction with the Washington 2026 Protocol. Subject to the provisions set forth below, once
9 approved by Commissions, the 2026 Protocol can be used to set just and reasonable rates in rate
10 filings in the Five States. The 2026 Protocol describes a cost-allocation methodology, which, if
11 used by all Five States for rate proceedings filed with rates effective beginning January 1, 2026,
12 will align costs and benefits for customers and afford PacifiCorp a reasonable opportunity to
13 recover all of its prudently incurred expenses and investments and earn its authorized rate of return.
14 The Five States are implementing energy policies that make it increasingly difficult for
15 PacifiCorp to operate and maintain a single resource portfolio for customers across all jurisdictions
16 while meeting its legal obligations in each state. The 2026 Protocol implements a transition from
17 a cost-allocation methodology that is consistent with the operation of a single resource portfolio
18 to a cost-allocation methodology that is consistent with state or regional resource portfolios needed
19 to meet load obligations on a least-cost basis, while complying with state energy policies and
20 preventing cross-subsidization among jurisdictions. In addition, full allocation of all prudently
21 incurred resources maximizes state benefits and supports the financial health of PacifiCorp. The
22 2026 Protocol marks an initial step to transition the allocation of costs to align with changes in
' Capitalized terms in the 2026 Protocol are defined herein or in Appendix A.

Rocky Mountain Power
Exhibit No.3 1 Page 4 of 46
Case No. PAC-E-25-14
Witness:Joelle R.Steward
23 operations and to establish rate base in a manner that aligns costs and benefits consistent with state
24 energy policies. The transition will be facilitated by participation in the Extended Day Ahead
25 Market where market settlements can be used to allocate Net Power Costs associated with the
26 Resource portfolio allocated to each state. This first phase of the transition is being implemented
27 in the 2026 Protocol, which realigns existing Resources to allocate costs based on near-term state
28 energy policy and legal obligations ("Phase I"). This includes specific energy policy decisions
29 made around the Chehalis natural gas facility ("Chehalis"), and all other thermal generation
30 facilities.Additionally, the 2026 Protocol maintains a roughly similar resource adequacy position
31 for each jurisdiction when compared against the 2020 Protocol. The 2026 Protocol provides a path
32 for a second phase of a cost allocation transition that will support PacifiCorp's ability to meet
33 upcoming legal obligations and enable different resource portfolios to comply with individual state
34 or regional energy policy mandates ("Phase 2"). For example, Oregon's House Bill ("HB") 20212
35 and Senate Bill ("SB") 15473 set resource and emissions targets starting in 2030; Utah SB 2244
36 establishes a preference for dispatchable generation; Utah HB 4115 allows for Utah communities
37 to opt-in to programs to reach 100 percent renewable generation by 2030; Washington SB 5116,E
38 the Clean Energy Transformation Act, requires greenhouse gas neutrality by 2030 and carbon free
39 retail electricity by 2045; Washington HB 2528,E the Climate Commitment Act, requires the
40 purchase of allowances for emissions from various sources in the state; and Wyoming HB 200
41 requires a portion of load in the state to be served by carbon capture technology by July 1, 2033.8
2 ORS §469A.400 et. seq.
s ORS §757.518 et. seq.
4 UTAH CODE Arne.§ 54-17-1001.
5 UTAH CODE Arne.§ 54-17-901 et. Seq.
6 WASH.REv.CODE§19.405.010 et seq.
WASH.REv.CODE§70.45.005 et. seq.
8 WYO.STAT. §37-18-102(a)(ii).

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Exhibit No.3 1 Page 5 of 46
Case No. PAC-E-25-14
Witness:Joelle R.Steward
42 The proposed allocation of a particular expense or new investment to a state under the 2026
43 Protocol is not intended to and will not prejudge the prudence of that cost or the extent to which
44 any particular cost may be reflected in rates. Nothing in the 2026 Protocol is intended to abrogate
45 any Commission's right or obligation to determine fair,just, and reasonable rates.
46 2.0 Effective Period and Phase 1 Implementation
47 The 2026 Protocol aligns costs and benefits for customers within the requirements of their
48 state energy policies. It makes the changes necessary to realign the system to reflect the existing
49 legal obligations and resource constraints that take effect January 1, 2026. Moving forward,
50 PacifiCorp will present a Phase 2 filing to the Commissions to be effective no later than 2030, and
51 it will encompass additional elements, which may include: setting fixed allocations among the
52 Five States; the implementation of a market settlement approach to Net Power Costs;9 the
53 reallocation of Resources to comply with state laws that have binding compliance milestones
54 beginning 2030; and the allocation of transmission assets.
55 Upon approval by the Commission in each jurisdiction,the 2026 Protocol will be effective
56 for new regulatory filings in that jurisdiction beginning January 1, 2026, and will remain effective
57 until superseded by a future amendment or new protocol approved by the Commission.
58 Phase 1 implementation provides for an immediate realignment of Chehalis to become a
59 Situs resource to Washington and incorporates a limited realignment of Resources to remove coal
60 from Washington rates by January 1, 2026. PacifiCorp will file for deferred accounting to track
61 the costs and benefits from Phase 1. Once the 2026 Protocol is approved in a jurisdiction, the
9 PacifiCorp may propose to move to a market settlement approach for NPC before Phase 2.

Rocky Mountain Power
Exhibit No.3 1 Page 6 of 46
Case No. PAC-E-25-14
Witness:Joelle R.Steward
62 revised cost allocation factors will be implemented through rate proceedings initiated after such
63 approval.10
64 3.0 Allocation of Resources
65 3.1 Existing Resource Portfolios
66 There will be two portfolios of existing Resources—the Five State portfolio and the
67 Washington fixed portfolio. The Five State portfolio is for customers in the Five States, and
68 Resources in this portfolio will be dynamically allocated among those states.The Washington fixed
69 portfolio includes a fixed allocation or Situs assignment of certain Resources, as reflected in the
70 Washington 2026 Protocol.
71 There are four different subsets of Resources in the two portfolios. The first subset of
72 Resources includes those that are allocated to both portfolios (the Five State portfolio and the
73 Washington fixed portfolio). The second subset is for Resources that are fully allocated to the Five
74 State portfolio and not included in the Washington fixed portfolio. The third subset is for Rolling
75 Hills Wind, which is included in the Five State portfolio, with the exception of Oregon, and in the
76 Washington fixed portfolio. The fourth subset includes Washington Situs Resources that are fully
77 allocated to the Washington fixed portfolio.The subsets of Resources included in the two portfolios
78 are summarized in the table below.
10 The Washington 2026 Protocol was proposed in Washington through a power-cost only rate case filed in April 2025.
See In the Matter of Washington Utilities and Transportation Commission v PacifiCorp d1b/a Pacific Power and Light
Co.,Docket No.UE-250224,Initial Filing(Apr. 1,2025).

Rocky Mountain Power
Exhibit No.3 1 Page 7 of 46
Case No. PAC-E-25-14
Witness:Joelle R.Steward
Plant Name/Resource Five State Portfolio Washington Total
Type (OR, CA,ID,UT,WY) Fixed Portfolio
Resource Subset 1
Jim Bridger Units 92.10% 7.90% 100%
1 & 2
Other Existing Non-
Emitting Resources 92.10% 7.90% 100%
non-QFs
Legacy Interruptible 92.10% 7.90% 100%
Contracts
Resource Subset 2
Other Natural Gas and 100% 0% 100%
Coal (non-QFs)
Five State QFs 100% 0% 100%
Resource Subset 3
Rolling Hills Wind 65.13% 34.87% 100%
excluding OR
Resource Subset 4
WA QFs 0% 100% 100%
Chehalis 0% 100% 100%
79 3.2 Dynamic Allocation of the Five State Portfolio
80 The Five State portfolio will be dynamically allocated for customers in the Five States.
81 Non-fuel generation costs will be allocated using one of three different versions of a Five State
82 system generation factor("SG5").The allocation of fuel cost and other variable costs are discussed
83 in Section 4 and identified in Appendix B. The three versions of the SG5 factor account for the
84 different subsets of Resources that are included in the Five State portfolio. For non-emitting
85 Resources (excluding Rolling Hills Wind and QFs), Jim Bridger Units 1 and 2, and Legacy
86 Interruptible Contracts, costs will be allocated to the Five States using a dynamic generation factor
87 excluding the fixed percentage allocated to Washington ("SGSA"). For all other thermal units,
88 excluding Chehalis, and certain QFs, costs will be allocated using a dynamic generation factor
89 ("SGSB") to the Five States. For Rolling Hills Wind, costs will be allocated using a dynamic
90 generation factor among California, Idaho, Utah, and Wyoming excluding the fixed percentage

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Exhibit No.3 1 Page 8 of 46
Case No. PAC-E-25-14
Witness:Joelle R.Steward
91 allocated to Washington("SG5C").11 Additional information pertaining to the allocation of Legacy
92 Interruptible Contracts and QFs is addressed in Sections 3.3 and 3.4, respectively.
Plant Name/Resource Type Five State Dynamic
Allocation Factors
Resource Subset 1
Jim Bridger Units 1 & 2 SG5A
Other Existing Non-Emitting Resources SG5A
non-QFs
Legacy Interruptible Contracts SG5A
Resource Subset 2
Other Natural Gas and Coal (non-QFs) SG513
Five States' QFs pre-2020 SG5B (Sites Starting 2030)
Five States' QFs post-2020 Situs
Resource Subset 3
Rolling Hills Wind SG5C
93 3.3 Legacy Interruptible Contracts
94 The costs incurred for certain interruptible industrial load contracts (identified in
95 Appendix D as Legacy Interruptible Contracts)will be allocated using the SG5A Factor.Revenues
96 associated with these Legacy Interruptible Contracts will be included in state revenues, and loads
97 of the associated interruptible contract customers will be included in dynamic allocation factors as
98 appropriate (see Appendix D).
99 3.4 Qualifying Facilities
100 The costs, any corresponding Renewable Energy Certificate ("RECs"), and all
101 environmental attributes of Five States' QF power purchase agreements ("PPAs") are allocated
102 based on when the QF PPA was fully executed as outlined in this section. No later than January 1,
103 2030, all of the Five States' QF PPA costs, and all environmental attributes will be Situs assigned
104 to the state of origin.
" Under the Washington 2026 Protocol, Washington will be allocated the unallocated percentage of Rolling Hills
Wind that had been previously disallowed from Oregon rates in 2008.See In the Matter of PacifiCorp d/b/a Pacific
Power, 2009 Renewable Adjustment Clause,Docket No.UE 200,Order No.08-548 at 19-21 (Nov. 14,2008).

Rocky Mountain Power
Exhibit No.3 1 Page 9 of 46
Case No. PAC-E-25-14
Witness:Joelle R.Steward
105 The costs,any corresponding RECs,and all environmental attributes of the Five States'QF
106 PPAs fully executed on or before December 31,201912 will be allocated using the SG513 allocation
107 factor.
108 The costs of post-2020 QF PPAs will be dynamically allocated using the SG513 factor,
109 priced at a forecasted reasonable energy price outlined in Section 3.4.1, and any cost of a post-
110 2020 QF PPA above the forecasted reasonable energy price will be Situs assigned and allocated to
111 the state of origin.The corresponding RECs and all environmental attributes of post-2020 QF PPAs
112 will be Situs assigned to the state of origin.
113 3.4.1 Forecasted Reasonable Energy Price
114 The forecasted reasonable energy price is a single blended market price derived from
115 PacifiCorp's official forward price curve, scaled for hourly prices, that will be used for setting QF
116 pricing for any Post 2020 QF PPAs. The single blended market price is calculated by applying the
117 appropriate weighting to the hourly scaled prices from the official forward price curve for each
118 market hub. The weightings per market hub are identified in the table below.
Market Hub Weighting by Month-HLH
Market Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
COB 0.00% 0.55% 1.34% 0.82% 3.45% 4.01% 8.41% 3.69% 8.58% 0.97% 1.79% 1.20%
Mid Columbia 24.42% 30.21% 55.74% 63.22% 70.849/6 87.39% 81.05% 83.85% 75.88% 42.27% 34.30% 40.74%
Palo Verde 1.52% 2.53% 1.07% 0.66% 0.54% 0.03% 0.76% 1.89% 1.85% 2.55% 3.45% 0.30%
Four Corners 64.72% 58.689/o 35.94% 27.40% 16.15% 5.75% 4.12% 2.17% 3.82% 45.79% 52.88% 44.47%
Mead 0.18% 0.13% 1.23% 1.46% 1.52% 1.749/6 1.95% 3.30% 6.649/o 0.33% 0.12% 0.57%
Mona 1 9.1651. 7.900/6 2.94%1 2.03%1 1.79%1 0.749/6 0.01%1 0.18% 1.82% 7.82% 7.46% 2.18%
NOB I 0.00% 0.00-/ol 1.75% 4.409/6 5.72%1 0.33%1 3.709/. 4.92% 1.41% 0.27% 0.00% 10.54%
Total 1 100.00%1 100.00% 100.00'/0 100.0oo/ol 100.00%j 100.000/o 100.009/. 100.00% 100.00% 100.00% 100.00% 100.00%
Market Hub Weighting by Month-LLH
Market Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
COB 0.00% 0.99% 5.179/o 3.53% 15.50% 15.169/o 5.97% 1.21% 0.31% 2.43% 3.44% 1.16%
Mid Columbia 58.74% 60.10% 76.589/o 66.36% 71.82% 80.41% 85.52% 92.26% 83.27% 62.78% 66.30% 59.09%
Palo Verde 0.00% 1.12% 0.42% 0.04% 0.39% 0.40'/o 2.71% 3.049/o 0.00% 0.92% 1.91% 2.30%
Four Corners 33.45% 34.669/o 13.63% 26.49% 10.441/o 3.30% 5.35% 2.39% 11.60% 27.69% 26.36% 29.65%
Mead 0.00% 0.06% 0.949/o 0.44% 0.93% 0.47% 0.25% 0.00%1 0.00%1 0.57% 0.00% 0.00%
Mona 1 7.81%1 3.07%1 1.54%1 2.41%1 0.92%1 0.27%1 0.009/6 1.11%1 4.82%1 5.61%1 1.99% 7.80%
NOB 1 0.00%1 0.00% 1.7 /o 0.73% 0.00%1 0.00% 0.20% 0.00%1 0.00%1 0.00%1 0.00% 0.00%
Total 1 100.00%.1 100.00% 100.00% 100.0oo/ol 100.00%1 100.0oo/ol 100.00%.1 100.00%1 100.00%1 100.00%1 100.00% 100.00%
12 This includes all QF PPAs that were system allocated under the 2020 Protocol.

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Exhibit No.3 1 Page 10 of 46
Case No. PAC-E-25-14
Witness:Joelle R.Steward
119 The weighting will be applied by month and by heavy load hours ("HLH") and light load
120 hours ("LLH"). The forecasted reasonable energy price, used for allocation purposes, shall be
121 established at the time a QF PPA is fully executed.
122 3.5 Demand-Side Management
123 Costs incurred for Demand-Side Management Programs will be allocated on a Situs basis
124 to the state in which the investment is made. Reduced consumption and contribution to coincident
125 peak, will be reflected in the dynamic allocation factors.
126 3.6 Allocation of New Resources
127 PacifiCorp will propose an allocation factor for new Resources with a term or depreciable
128 life longer than three years at or before a prudence review occurs. New Resources with a term or
129 depreciable life less than three years will be allocated in accordance with Section 4.New Resources
130 are any non-QF generating facility procured after April 1, 2025.13
131 3.7 State-Imposed Costs
132 Costs imposed by state law on a Resource, such as taxes, fees, and environmental
133 permitting will be allocated consistent with the allocation of the Resource under Section 3.2 unless
134 specifically identified in this section.If a state imposes a carbon or greenhouse gas pricing program
135 (e.g., a cap-and-trade program or a carbon tax) on a Resource, the costs and revenues associated
136 with that program will be Situs assigned to the state imposing that obligation. If the state imposing
137 a carbon or greenhouse gas pricing program is not a jurisdiction with PacifiCorp retail customers,
138 or if the costs are imposed by the federal government, then the costs will be allocated consistent
139 with Section 3.2.
13 For the purposes of this section,a Resource is procured when the contract procuring generation(PPA,asset purchase
agreement,build transfer agreement,etc.)is effective.

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Exhibit No.3 1 Page 11 of 46
Case No. PAC-E-25-14
Witness:Joelle R.Steward
140 Costs and revenues will be Situs assigned when they are incurred to comply with a program
141 or initiative imposed by a particular state on PacifiCorp in its role as a public utility serving
142 customers in that state. This includes Portfolio Standards, customer generation programs,
143 emissions performance standards, voluntary renewable energy programs, capacity standard
144 programs, electric vehicle programs, and the acquisition of RECs.
145 3.8 Decommissioning and Closure Costs
146 Upon Closure of a Resource, any remaining rate base and associated expense will be
147 allocated consistent with Section 3.2. For Resources with a Closure date before 2030,
148 Decommissioning Costs will be allocated based on the allocation factors identified in Section 3.2.
149 For Resources with a Closure date of 2030 or later, PacifiCorp will propose a methodology in
150 Phase 2.
151 3.9 Capital Additions—Coal Resources with Operational Lives Beyond 2030
152 To facilitate the removal of coal generation from Oregon rates, capital additions on coal-
153 fired Resources made before December 31, 2029, will be allocated to Oregon on a time-based pro
154 rata share until December 31, 2029. The cost of capital additions on coal-fired Resources made
155 before 2030 will be dynamically reallocated to the remaining Five States. Oregon's pro rata share
156 will be based on the number of months left in Oregon's depreciable life of the Resource compared
157 to the number of months left in the longest depreciable life of the Resource used in the remaining
158 Five States. For example, if a $100,000 investment is made at a plant where 15 months remain in
159 Oregon's depreciable life and 123 months remain in the longest depreciable life for that plant in
160 the remaining Five States, the following is the calculation for Oregon's pro rata share of the
161 investment.14
14 The percentages and amounts identified in the example below are used for illustrative purposes and may not reflect
the actual dynamic allocation factors.

Rocky Mountain Power
Exhibit No.3 1 Page 12 of 46
Case No. PAC-E-25-14
Witness:Joelle R.Steward
(Oregon Life in months/Total Remaining Life in months)x Investment x Oregon SG513 Factor,
or, in the example above:
(15 months/ 123 months)x $100,000 x 28.27%= $3,448
162 The remainder of the investment will be proportionately allocated to the remaining Five
163 States , resulting in the cost allocation shown in the table below.
California Oregon Washington Utah Idaho Wyoming Total
1.92% 3.45% 0.00% 65.67% 8.79% 20.17% 100.00%
$1,923 $3,448 $0 $65,672 $8,792 $20,165 $100,000
164 4.0 Allocation of Net Power Costs
165 The table below summarizes the transition from the 2020 Protocol to the 2026 Protocol for
166 Net Power Cost filings. Before implementation of Phase 2, Net Power Costs will continue to be
167 dynamically allocated consistent with the allocation factors identified in this 2026 Protocol. For
168 Net Power Cost filings, the allocation methodology that will be used will be based upon the table
169 identified below.
2020 Protocol 2026 Protocol
Annual NPC Year in Actual Year in
Filings Filed Review Base NPC NPC Filed Review Base NPC Actual NPC
OR PCAM 2026 2025 2020 Protocol 2020 Protocol 2027 2026 2020 Protocol 2026 Protocol
UT EBA 2026 2025 2020 Protocol 2020 Protocol 2027 2026 2020 Protocol 2026 Protocol
WY ECAM 2026 1 2025 2020 Protocol 2020 Protocol 2027 2026 2020 Protocol 2026 Protocol
ID ECAM 2026 2025 2020 Protocol 2020 Protocol 2027 2026 2020 Protocol 2026 Protocol
WA PCAM 2026 2025 2020 Protocol 2020 Protocol 2027 2026 2026 Protocol 2026 Protocol
CA ECAC 2026 2025 2020 Protocol 2020 Protocol 2027 2026 2020 Protocol 2020 Protocol
Balancing
170 Net Power Costs will be allocated consistent with the allocation factors identified for the
171 appropriate FERC Account in Appendix B. Each of the Five States will also receive an allocation
172 of the costs or revenues resulting from the valuation of the difference between the Five-State
173 portfolio's load and allocated Resources using a dynamic SG513 factor. Specifically,at the monthly
174 granularity,the difference between: (1) the aggregate Five State portfolio's generation and market
175 purchases; less (2)the aggregate Five State portfolio's load and market sales,will be valued at the

Rocky Mountain Power
Exhibit No.3 1 Page 13 of 46
Case No. PAC-E-25-14
Witness:Joelle R.Steward
176 monthly average short-term firm market transaction price. The average short-term firm market
177 transaction price is the sum of all short-term firm transactions in dollars divided by the sum of all
178 short-term firm transactions in megawatt-hours. PacifiCorp may propose to revise or integrate a
179 market settlements-based methodology into the allocations of Net Power Costs. Situs Resources
180 will continue to use the lower of cost or market methodology.15
181 5.0 Allocation of Transmission Costs
182 The costs associated with transmission assets will be dynamically allocated among the Five
183 States and Washington using the system generation ("SG") factor, as more thoroughly defined in
184 Appendix C. All revenues recovered through PacifiCorp's Open Access Transmission Tariff or
185 other transmission rate schedules approved by the FERC will be allocated based on the SG factor.
186 FERC Account 565 wheeling expenses will be allocated according to Appendix B. The 2026
187 Protocol does not preclude PacifiCorp from participating in any independent transmission
188 organization, regional transmission organization, or other similar wholesale transmission market
189 subject to the jurisdiction and oversight of the FERC.Nothing in this section is intended to prevent
190 PacifiCorp from using an alternative allocation of transmission costs for New Large Load
191 customers as described in Section 13.0.
192 6.0 Allocation of Distribution Costs
193 All distribution-related expenses and capital costs that can be directly allocated will be
194 directly allocated to the states where the related distribution facilities are located. Those
195 distribution expenses that cannot be directly allocated will be allocated among the states on a
196 system net plant distribution("SNPD") factor, as shown in Appendix C.
is This method compares the actual cost of a resource (such as a PPA)to the prevailing market price for electricity.
The lower of the two values is used to allocate costs to states that do not have Situs responsibility for the resource.
The state to which the resource is Situs assigned pays the difference between: (1)the actual cost of the resource;and
(2)the total amount recovered from the other states.This method is unchanged from the 2020 Protocol.

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Exhibit No.3 1 Page 14 of 46
Case No. PAC-E-25-14
Witness:Joelle R.Steward
197 7.0 Allocation of System Overhead Costs
198 Costs that support more than one function, such as generation,transmission,or distribution
199 plant, will continue to be allocated on the system overhead ("SO") factor but will be calculated
200 based on an equal one-third weighting of the system capacity("SC") factor, system energy("SE")
201 factor, and system gross plant distribution("SGPD") factor, as shown in Appendix C.
202 8.0 Allocation of Taxes and Fees
203 Income taxes will be calculated using the federal tax rate and PacifiCorp's combined state-
204 effective tax rate. State-specific Schedule M and deferred income tax amounts will be allocated
205 using PacifiCorp's tax software system. The Washington public utility tax is allocated using the
206 SO factor in lieu of a Washington income tax.
207 Franchise taxes, revenue related taxes, local business income taxes, Commission
208 assessments and fees, and usage-related taxes are allocated Situs or treated as pass through.
209 Property taxes are allocated based on gross plant using the gross plant system ("GPS")
210 factor as identified in Appendix C. State taxes enacted as a replacement for property taxes, such as
211 the Idaho Kilowatt Hour tax,will be considered the same as property tax and allocated on the GPS
212 factor. Amounts collected as a separate line on customer bills will be reflected as a reduction to
213 that state's allocation of property taxes in the revenue requirement calculation.
214 Generation and fuel-related taxes or royalties, other than those associated with a carbon or
215 greenhouse gas pricing program(see Section 3.7),will follow the allocation of the Resource under
216 Section 3.2. Other taxes such as payroll taxes are embedded in the cost of expense or capital.
217 Balances associated with the Trojan Plant decommissioning will be allocated using the Trojan
218 Plant decommissioning factor as identified in Appendix C.

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Exhibit No.3 1 Page 15 of 46
Case No. PAC-E-25-14
Witness:Joelle R.Steward
219 9.0 Allocation of Administrative and General Costs
220 Administrative and general costs, general plant costs, and intangible plant costs, both
221 expenses and investments,which can be directly allocated will be Situs assigned to the appropriate
222 state. Those costs that cannot be directly allocated will be allocated among states consistent with
223 the factors set forth in Appendix B.
224 10.0 Treatment of Oregon Direct Access Programs
225 Customer loads electing to be served on one- and three-year Oregon Direct Access
226 programs will be included in the dynamic allocation factors, and the transition cost payments from
227 these customers will be Situs assigned and allocated to Oregon.
228 Customers electing to be served under the Oregon five year opt-out program will be treated
229 consistent with Order No. 15-060, as clarified through Order No. 15-067, of the Public Utility
230 Commission of Oregon in docket UE 267, and Oregon Schedule 296, which allow Oregon Direct
231 Access customers to permanently opt-out of cost-of-service rates after payment of ten years of
232 transition costs. If an Oregon Direct Access customer is paying transition costs,the Oregon Direct
233 Access customer's load(s) will be included in dynamic allocation factors, and the transition cost
234 payments from these customers will be Situs-assigned to Oregon. If any Oregon Direct Access
235 customer reaches the end of the 10-year period covered by the transition cost payments,the load(s)
236 for that Oregon Direct Access customer will be excluded from dynamic allocation factors. If any
237 Oregon Direct Access customer returns to PacifiCorp service after the end of the 10-year period
238 covered by the transition cost payments, the load(s) for that Oregon Direct Access customer will
239 be addressed as an increase in load under Section 11.0.
240 11.0 Loss or Increase in Load
241 Any loss or increase in retail load occurring as a result of condemnation or
242 municipalization, sale or acquisition of new service territory that involves less than five percent of

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Exhibit No.3 1 Page 16 of 46
Case No. PAC-E-25-14
Witness:Joelle R.Steward
243 the Five State load, realignment of service territories, changes in economic conditions, or gain or
244 loss of customers (unless described in Sections 10.0 or 13.0) will be reflected in changes in the
245 dynamic allocation factors. The allocation or assignment of costs and benefits arising from a
246 merger, sale, or acquisition transaction proposed by PacifiCorp involving more than five percent
247 of the Five State load will be considered on a case-by-case basis in the course of Commission
248 approval proceedings.
249 12.0 Excess Liability Insurance and Liability Allocation
250 The costs for non-wildfire related insurance premiums for excess liability and costs for
251 non-wildfire liability not covered by insurance will be allocated using the SO factor. The costs for
252 wildfire related insurance coverage and liability in retail service states will be addressed on a state-
253 by-state basis.
254 13.0 Allocation of Costs for New Large Load
255 The costs associated with New Large Load that require PacifiCorp to make investments or
256 incur costs for assets placed in service after January 1, 2026, will be assigned to the state in which
257 the load is located. PacifiCorp will work within the regulatory framework (i.e., a special contract
258 or tariff) within that state to assign the costs to the New Large Load customer, as determined by
259 that state's Commission. These costs include, but are not limited to, any new distribution costs,
260 transmission costs, generation costs (including power purchase agreements, as applicable), and
261 contractual costs for providing electrical service (i.e., firm third-party transmission rights).
262 14.0 Allocation of Gain or Loss from Sale of Assets
263 Any gain or loss from the sale of PacifiCorp-owned assets will be allocated among or to
264 states based upon the proportional allocation or assignment of the asset at the time of the execution
265 date of the sale agreement. Each Commission will determine the appropriate allocation of the gain
266 or loss allocated to that state as between PacifiCorp's customers and shareholders. For assets that

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Exhibit No.3 1 Page 17 of 46
Case No. PAC-E-25-14
Witness:Joelle R.Steward
267 have been reassigned for less than one calendar year as of the execution date of the sale agreement,
268 states will be allocated the gain or loss as if the asset had not been reassigned.
269 15.0 Interpretation and Governance
270 To the extent that an issue of interpretation causes an allocation difference between
271 multiple jurisdictions as a result of the 2026 Protocol,PacifiCorp may petition other Commissions
272 to amend this 2026 Protocol to resolve any allocation discrepancies.
273 The 2026 Protocol has been developed as an integrated, interdependent whole. If any
274 Commission disapproves, alters, or conditions approval of the 2026 Protocol, PacifiCorp may
275 petition for an amendment to revise the 2026 Protocol.

Rocky Mountain Power
Exhibit No.3 1 Page 18 of 46
Case No. PAC-E-25-14
Witness:Joelle R.Steward
APPENDIX A- DEFINED TERMS
1 For purposes of the 2026 PacifiCorp Interjurisdictional Allocation Protocol, the following
2 terms will have the following meanings:
3 • "2020 Protocol"refers to the 2020 PacifiCorp Inter-Jurisdictional Allocation Protocol.
4 • "Closure"means the permanent retirement and termination of operation of a Resource.
5 • "Commission(s)" means a public utility commission established by statute in
6 California, Idaho, Oregon, Utah, or Wyoming.
7 • "Decommissioning Costs" means all costs of a plant or unit removal, and
8 environmental remediation or reclamation(including any asset retirement obligations),
9 net of any salvage value realized, to physically retire a generation resource.
10 • "Demand-Side Management Programs" means programs intended to reduce
11 electricity use through activities or programs that promote electric energy efficiency or
12 conservation,more efficient management of electric energy loads,or reductions in peak
13 demand.
14 • "FERC" means the Federal Energy Regulatory Commission.
15 • "FERC Account" refers to the specific accounting identified in Title 18 CFR §101.
16 • "Five State(s)" means the states of California, Idaho, Oregon, Utah and Wyoming.
17 • "Legacy Interruptible Contract" means the two interruptible industrial load
18 contracts between PacifiCorp and P4 Production that began on January 1, 2022, and
19 with Nucor-Steel Utah that began on March 1, 2022.
20 • "Net Power Costs" or "NPC" means the cost of power supply incurred, net of any
21 sales for resale (wholesale power sales). The cost of power supply includes fuel,
22 purchased power, and transmission of electricity by others (wheeling expense).

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Exhibit No.3 1 Page 19 of 46
Case No. PAC-E-25-14
Witness:Joelle R.Steward
23 • "New Large Load" means an existing or new customer requesting new or additional
24 service with a demand of 50 megawatts or greater.
25 • "Oregon Direct Access" means a program under Oregon's electric restructuring law
26 (ORS 757.600 to ORS 757.687) allowing nonresidential consumers to purchase
27 electricity from a certified electricity service supplier other than PacifiCorp.
28 • "Portfolio Standards" means any requirement to serve load or portion of load with
29 specific types of resources, which can be measured on an energy or capacity basis.
30 • "Qualifying Facility" or "QF" means small power production or cogeneration
31 facilities developed under the Public Utility Regulatory Policies Act of 1978 (PURPA).
32 • "Resources"means Company-owned, leased, or contracted generating plants, energy-
33 storage facilities and mines, long term wholesale contracts, short-term purchases and
34 sales and non-firm purchases and sales, and QF PPAs.
35 • "Situs" means the allocation of all of the cost or attribute to a single state.
36 • "Trojan Plant"means the decommissioned nuclear plant for which PacifiCorp is still
37 recovering costs.
38 • "2026 Washington Protocol" refers to the PacifiCorp Inter-Jurisdictional Allocation
39 Protocol for use in Washington filed in docket UE-250224 before the Washington
40 Utilities and Transportation Commission.

Rocky Mountain Power
Exhibit No.3 1 Page 20 of 46
Case No. PAC-E-25-14
Witness:Joelle R.Steward
2026 Protocol -Appendix B
Allocation Factors by Account by Revenue Requirement Components
1 2 3 4 5
2020 PROTOCOL 2026 Protocol
FERC ACCT ACCT NAME REVENUE REQUIREMENT COMPONENTS ASSIGNED TO FACTOR FACTOR FACTOR
Sales to Ultimate Customers
440 Residential Sales
Retail Revenues Direct assigned-Jurisdiction S S
442 Commercial&Industrial Sales
Retail Revenues Direct assigned-Jurisdiction S S
444 Public Street&Highway Lighting
Retail Revenues Direct assigned-Jurisdiction S S
445 Other Sales to Public Authority
Retail Revenues Direct assigned-Jurisdiction S S
448 Interdepartmental
Retail Revenues Direct assigned-Jurisdiction S S
447 Sales for Resale
Wholesale Sales Direct assigned-Jurisdiction S S
Nan-Firm SE SESA
Firm SG SGSA
449 Provision for Rate Refund
Direct assigned-Jurisdiction S S
Transmission SG SG
Other Electric Operating Revenues
450 Forfeited Discounts&Interest
Retail Revenues Direct assigned-Jurisdiction S S
451 Misc Electric Revenue
Retail Revenues Direct assigned-Jurisdiction S S
Other-Common SO SO
453 Water Sales
Water Sales SG SGSA
Water Sales SG SGSB
454 Rent of Electric Property
Retail Revenues Direct assigned-Jurisdiction S S
Common SG SG
Other-Common SO SO
456 Other Electric Revenue
Retail Revenues Direct assigned-Jurisdiction S S
Wheeling Nan-firm,Other SE SE
Common SO SO
Wheeling-Firm,Other SG SG
Customer Related CN CN
1

Rocky Mountain Power
Exhibit No.3 1 Page 21 of 46
Case No. PAC-E-25-14
Witness:Joelle R.Steward
Allocation Factors by Account by Revenue Requirement Components
1 2 3 4 5
2020 PROTOCOL 2026 Protocol
FERC ACCT ACCT NAME REVENUE REQUIREMENT COMPONENTS ASSIGNED TO FACTOR FACTOR FACTOR
Miscellaneous Revenues
41160 Gain on Sale of Utility Plant-CR
Distribution S S
Production-Jim Bridger Units 1&2,Non-Emitting(except Rolling Hills) SG SGSA
Production-Thermal(except Chehalis and Jim Bridger Units 1&2) SG SGSB
Production-Rolling Hills SG SGSC
Production-Chehalis SG S
Transmission SG SG
General Office SO sO
41170 Lass on Sale of Utility Plant
Distribution S S
Production-Jim Bridger Units 1&2,Non-Emitting(except Rolling Hills) SG SGSA
Production-Thermal(except Chehalis and Jim Bridger Units 1&2) SG SGSB
Production-Rolling Hills SG SGSC
Production-Chehalis SG S
Transmission SG SG
General Office SO sO
4118 Gain from Emission Allowances
SO2 Emission Allowance sales SE SESB
41181 Gain from Disposition of NOX Credits
NOX Emission Allowance sales SE SE56
421 (Gain)/Loss on Sale of Utility Plant
Distribution S S
Production-Jim Bridger Units 1&2,Non-Emitting(except Rolling Hills) SG SGSA
Production-Thermal(except Chehalis and Jim Bridger Units 1&2) SG SGSB
Production-Rolling Hills SG SGSC
Production-Chehalis SG S
Transmission SG SG
General Office SO SO
Customer Related CN CN
Miscellaneous Expenses
4311 Interest on Customer Deposits
Customer Service Deposits CN CN
Direct assigned-Jurisdiction S S
Steam Power Generation
500,502,504-514 Operation Supervision&Engineering
Jim Bridger Units 1&2 SG SGSA
Steam Plant,Other Than Jim Bridger Units 1&2 SG SGSB
501 Fuel Related
Jim Bridger Units 1&2 SE SESA
Other SE SESB
503 Steam From Other Sources
Steam Royalties SE SESA
Steam Royalties SE SESB
509 Allowances
California Wholesale GHG Obligation SG SGSA
California Retail GHG Obligation S S
2

Rocky Mountain Power
Exhibit No.3 1 Page 22 of 46
Case No. PAC-E-25-14
Witness:Joelle R.Steward
Allocation Factors by Account by Revenue Requirement Components
1 2 3 4 5
2020 PROTOCOL 2026 Protocol
FERC ACCT ACCT NAME REVENUE REQUIREMENT COMPONENTS ASSIGNED TO FACTOR FACTOR FACTOR
Nuclear Power Generation
517-532 Nuclear Power O&M
Nuclear Plants O&M SG SGSA
Hydraulic Power Generation
535-545 Hydro O&M
Hydro Plant O&M SG SGSA
Solar Power Generation
558 Solar Plant O&M
Solar Plant O&M S S
Solar Plant O&M SG SGSA
Wind Power Generation
558 Wind Plant O&M
Wind Plant O&M-Except Rolling Hills SG SGSA
Wind Plant O&M-Rolling Hills Wind SG SGSC
Renewable Generation
559 Renewable Plant O&M
Geothermal SG SGSA
Other Power Generation
546,548-554 Operation Super&Engineering
Other Production Plant O&M-Chehalis SG S
Other Production Plant,Except Chehalis SG SGSB
547 Fuel
Other Fuel Expense(except Chehalis) SE SESB
Chehalis SE S
Other Power Supply
555 Purchased Power
Tracking Mechanisms S S
New QFs-Post 2020 S
QFs-Pre 2020 SGSB
Firm SG SGSA
Non-firm SE SESA
EDAM/EIM SGSA
556 System Control&Load Dispatch
Other Expenses SG SG
557 Other Expenses
Direct assigned-Jurisdiction S S
Other Expenses SE SESA
Other Expenses SE SESB
Other Expenses SG SG
Transmission Expense
560-564,566-573 Transmission O&M
Transmission Plant O&M SG SG
565 Transmission of Electricity by Others
Firm Wheeling SG SGSA
Non-Firm Wheeling SE SESA
GRID Management Charge SG SGSA
Energy Storage Expense
578 Energy Storage O&M
Energy Storage O&M N/A S
Energy Storage O&M N/A SGSA
3

Rocky Mountain Power
Exhibit No.3 1 Page 23 of 46
Case No. PAC-E-25-14
Witness:Joelle R.Steward
Allocation Factors by Account by Revenue Requirement Components
1 2 3 4 5
2020 PROTOCOL 2026 Protocol
FERC ACCT ACCT NAME REVENUE REQUIREMENT COMPONENTS ASSIGNED TO FACTOR FACTOR FACTOR
Distribution Expense
580-598 Distribution O&M
Direct assigned-Jurisdiction S S
Other Distribution SNPD SNPD
Customer Accounts Expense
901-905 Customer Accounts O&M
Direct assigned-Jurisdiction S S
Total System Customer Related CN CN
Customer Service Expense
907-910 Customer Service O&M
Direct assigned-Jurisdiction S S
Total System Customer Related CN CN
Sales Expense
911-916 Sales Expense O&M
Direct assigned-Jurisdiction S S
Total System Customer Related CN CN
Administrative&Gen Expense
920-935 Administrative&General Expense
Direct assigned-Jurisdiction S S
Customer Related CN CN
Mine SE SESB
FERC Regulatory Expense-Transmission SG SG
FERC Regulatory Expense-Hydro SG SGSA
General SO SO
Depreciation Expense
403SP Steam Depreciation
Jim Bridger Units 1&2 SG SGSA
Steam Plant-Except Jim Bridger Units 1&2 SG SG56
403NP Nuclear Depreciation
Nuclear Plant SG SGSA
403HP Hydro Depreciation
Hydro SG SGSA
403OP Other Production Depreciation
Other Production Plant-Chehalis SG S
Other Production Plant,Except Chehalis SG SG56
403XP Solar Production Depreciation
Solar Plant S S
Solar Plant SG SGSA
403WP Wind Production Depreciation
Wind-Except Rolling Hills SG SGSA
Rolling Hills Wind SG SGSC
403RP Renewable Production Depreciation
Geothermal SG SGSA
4

Rocky Mountain Power
Exhibit No.3 1 Page 24 of 46
Case No. PAC-E-25-14
Witness:Joelle R.Steward
Allocation Factors by Account by Revenue Requirement Components
1 2 3 4 5
2020 PROTOCOL 2026 Protocol
FERC ACCT ACCT NAME REVENUE REQUIREMENT COMPONENTS ASSIGNED TO FACTOR FACTOR FACTOR
403EP Energy Storage Depreciation
Energy Storage N/A S
Energy Storage N/A SGSA
403TP Transmission Depreciation
Transmission Plant SG SG
403 Distribution Depreciation Direct assigned-Jurisdiction
Land&Land Rights S S
Structures S S
Station Equipment S S
Storage Battery Equipment S S
Poles&Towers S S
OH Conductors S S
UG Conduit S S
UG Conductor S S
Line Trans S S
Services S S
Meters S S
Inst Cust Prem S S
Leased Property S S
Street Lighting S S
403GP General Depreciation
Mining SE SESB
Customer Related CN CN
General SO SO
403MP Mining Depreciation
Mining Plant SE SESB
Amortization Expense
404GP Amort of LT Plant-Capital Lease Gen
Direct assigned-Jurisdiction S S
General SO SO
Customer Related CN CN
404SP Amort of LT Plant-Cap Lease Steam
Steam Production Plant SG SGSB
4041P Amort of LT Plant-Intangible Plant
General SO SO
Mining Plant SE SESB
Customer Related CN CN
404MP Amort of LT Plant-Mining Plant
Mining Plant SE SESB
404HP Amortization of Other Electric Plant
Hydro SG SGSA
405 Amortization of Other Electric Plant
Direct assigned-Jurisdiction S S
5

Rocky Mountain Power
Exhibit No.3 1 Page 25 of 46
Case No. PAC-E-25-14
Witness:Joelle R.Steward
Allocation Factors by Account by Revenue Requirement Components
1 2 3 4 5
2020 PROTOCOL 2026 Protocol
FERC ACCT ACCT NAME REVENUE REQUIREMENT COMPONENTS ASSIGNED TO FACTOR FACTOR FACTOR
406 Amortization of Plant Acquisition Adj
Direct assigned-Jurisdiction S S
Thermal Production Plant SG SGSB
Non-Emitting Production Plant SGSA
Transmission SG
407 Amort of Prop Losses,Unrec Plant,etc.
Direct assigned-Jurisdiction S S
Thermal Production Plant SG SG56
Non-Emitting Production Plant SG SGSA
Transmission SG SG
Taxes Other Than Income
408 Taxes Other Than Income
Direct assigned-Jurisdiction S S
Property GPS GPS
System Taxes SO SO
Misc Energy SE SE
Misc Production SG SGSA
Misc Production-Rolling Hills SG SGSC
Deferred ITC
41140 Deferred Investment Tax Credit-Fed
ITC DGU DGU
41141 Deferred Investment Tax Credit-Idaho
ITC DGU DGU
Interest Expense
427 Interest on Long-Term Debt
Direct assigned-Jurisdiction S S
Interest Expense SNP SNP
428 Amortization of Debt Disc&Exp
Interest Expense SNP SNP
429 Amortization of Premium on Debt
Interest Expense SNP SNP
431 Other Interest Expense
Interest Expense SNP SNP
432 AFUDC-Borrowed
AFUDC SNP SNP
Interest&Dividends
419 Interest&Dividends
Interest&Dividends SNP SNP
6

Rocky Mountain Power
Exhibit No.3 1 Page 26 of 46
Case No. PAC-E-25-14
Witness:Joelle R.Steward
Allocation Factors by Account by Revenue Requirement Components
1 2 3 4 5
2020 PROTOCOL 2026 Protocol
FERC ACCT ACCT NAME REVENUE REQUIREMENT COMPONENTS ASSIGNED TO FACTOR FACTOR FACTOR
Deferred Income Taxes
41010 Deferred Income Tax-DR
Direct assigned-Jurisdiction S S
Chehalis S
Non-Emitting and Jim Bridger Units 1&2 SG SGSA
Other Thermal Production SG SGSB
Rolling Hills SGSC
Transmission SG SG
Customer Related CN CN
General SO SO
Property Tax related GPS GPS
Miscellaneous SNP SNP
Trojan TROJD TROJD
Distribution SNPD SNPD
Mining Plant SE SESB
Bad Debt BADDEBT BADDEBT
Tax Depreciation TAXDEPR TAXDEPR
41110 Deferred Income Tax-CR
Direct assigned-Jurisdiction S S
Chehalis S
Non-Emitting and Jim Bridger Units 1&2 SG SGSA
Other Thermal Production SG SG56
Rolling Hills SGSC
Transmission SG SG
Customer Related CN CN
General SO SO
Property Tax related GPS GPS
Miscellaneous SNP SNP
Trojan TROJD TROJD
Distribution SNPD SNPD
Mining Plant SE SESB
Contributions in Aid of Construction CIAC CIAC
Book Depreciation SCHMDEXP SCHMDEXP
Schedule-M Additions
SCHMAF Additions-Flow Through
Direct assigned-Jurisdiction S S
SCHMAP Additions-Permanent
Direct assigned-Jurisdiction S S
Mining related SE SESB
General SO SO
Chehalis S
Non-Emitting and Jim Bridger Units 1&2 SG SGSA
Other Thermal Production SG SGSB
Rolling Hills SGSC
Transmission SG SG
Depreciation SCHMDEXP SCHMDEXP
7

Rocky Mountain Power
Exhibit No.3 1 Page 27 of 46
Case No. PAC-E-25-14
Witness:Joelle R.Steward
Allocation Factors by Account by Revenue Requirement Components
1 2 3 4 5
2020 PROTOCOL 2026 Protocol
FERC ACCT ACCT NAME REVENUE REQUIREMENT COMPONENTS ASSIGNED TO FACTOR FACTOR FACTOR
SCHMAT Additions-Temporary
Direct assigned-Jurisdiction S S
Bad Debt BADDEBT BADDEBT
Contributions in Aid of Construction CIAC CIAC
Miscellaneous SNP SNP
Trojan TROJD TROJD
Chehalis S
Nan-Emitting and Jim Bridger Units 1&2 SG SGSA
Other Thermal Production SG SGSB
Rolling Hills SGSC
Mining Plant SE SESB
Transmission SG SG
Property Tax GPS GPS
General SO SO
Depreciation SCHMDEXP SCHMDEXP
Distribution SNPD SNPD
Schedule-M Deductions
SCHMDF Deductions-Flow Through
Direct Assigned-Jurisdiction S S
Chehalis S
Non-Emitting and Jim Bridger Units 1&2 SG SGSA
Other Thermal Production SG SGSB
Rolling Hills SGSC
Transmission SG SG
SCHMDP Deductions-Permanent
Direct Assigned-Jurisdiction S S
Mining Related SE SESB
Depreciation SCHMDEXP SCHMDEXP
Miscellaneous SNP SNP
General SO SO
SCHMDT Deductions-Temporary
Direct Assigned-Jurisdiction S S
Bad Debt BADDEBT BADDEBT
Miscellaneous SNP SNP
Chehalis S
Non-Emitting and Jim Bridger Units 1&2 SG SGSA
Other Thermal Production SG SGSB
Rolling Hills SGSC
Mining related SE SESB
Transmission SG SG
Property Tax GPS GPS
General SO SO
Depreciation TAXDEPR TAXDEPR
Distribution SNPD SNPD
Customer Related CN CN

Rocky Mountain Power
Exhibit No.3 1 Page 28 of 46
Case No. PAC-E-25-14
Witness:Joelle R.Steward
Allocation Factors by Account by Revenue Requirement Components
1 2 3 4 5
2020 PROTOCOL 2026 Protocol
FERC ACCT ACCT NAME REVENUE REQUIREMENT COMPONENTS ASSIGNED TO FACTOR FACTOR FACTOR
State Income Taxes
40911 State Income Taxes
40911 Income Before Taxes CALCULATED CALCULATED
40911 Renewable Energy Tax Credit,Except Rolling Hills SG SGSA
40911 Renewable Energy Tax Credit-Rolling Hills SGSC
40911 PacifiCorp Minerals Inc. SE SE56
40911 Foreign Tax Credit SO SO
Adjustments to Calculated Tax
Federal Income Taxes
40910 FIT True-up S S
40910 Renewable Energy/Production Tax Credit,Except Rolling Hills SG SGSA
40910 Renewable Energy/Production Tax Credit-Rolling Hills SGSC
40910 Fuel Tax Credit SESA
40910 Fuel Tax Credit SESB
40910 Misc. SO
Steam Production Plant
310-316 Steam Plants
Jim Bridger Units 1&2 SG SGSA
Steam Plant other than Jim Bridger Units 1&2 SG SGSB
Nuclear Production Plant
320-325 Nuclear Plant
Nuclear Plant SG SGSA
Hydraulic Plant
330-336 Hydro Plant
Hydro SG SGSA
Solar Production Plant
338 Solar Plant
Solar Plant S S
Solar Plant SG SGSA
Wind Production Plant
338 Wind Plant
Wind-Except Rolling Hills SG SGSA
Rolling Hills Wind SG SGSC
Renewable Production Plant
339 Renewable Plant
Geothermal SG SGSA
Other Production Plant
340-346 Other Production Plant
Other Production Plant-Chehalis SG S
Other Production Plant,Except Chehalis SG SGSB
Transmission Plant
350-359 Transmission Plant
Transmission Plant SG SG
9

Rocky Mountain Power
Exhibit No.3 1 Page 29 of 46
Case No. PAC-E-25-14
Witness:Joelle R.Steward
Allocation Factors by Account by Revenue Requirement Components
1 2 3 4 5
2020 PROTOCOL 2026 Protocol
FERC ACCT ACCT NAME REVENUE REQUIREMENT COMPONENTS ASSIGNED TO FACTOR FACTOR FACTOR
Distribution Plant
360-373 Distribution Plant
Direct assigned-Jurisdiction S S
Other Distribution SNPD SNPD
Energy Storage
387 Energy Storage Plant
Energy Storage Plant N/A S
Energy Storage Plant N/A SG5A
General Plant
389-398 General Plant
Direct assigned-Jurisdiction S S
Customer Related CN CN
General SO SO
Mining SE SE513
399 Coal Mine
Mining Plant SE SE513
1011346 General Gas Line Capital Leases
Capital Lease S
Capital Lease SG SG5B
1011390 General Capital Leases
Direct assigned-Jurisdiction S S
General SO SO
Chehalis SG S
Other Thermal Production SG SG56
Transmission SG SG
Intangible Plant
301 Organization
Direct assigned-Jurisdiction S S
302 Franchise&Consent
Direct assigned-Jurisdiction S S
Other Thermal Production SG SG56
Production-Non-Emitting SG SG5A
Transmission SG SG
303 Miscellaneous Intangible Plant
Customer Related CN CN
General SO SO
Mining SE SE513
303 Less Non-Utility Plant
Direct assigned-Jurisdiction S S
10

Rocky Mountain Power
Exhibit No.3 1 Page 30 of 46
Case No. PAC-E-25-14
Witness:Joelle R.Steward
Allocation Factors by Account by Revenue Requirement Components
1 2 3 4 5
2020 PROTOCOL 2026 Protocol
FERC ACCT ACCT NAME REVENUE REQUIREMENT COMPONENTS ASSIGNED TO FACTOR FACTOR FACTOR
Rate Base Additions
105 Plant Held For Future Use
Direct assigned-Jurisdiction S S
Other Thermal Production SG SGSB
Production-Non-Emitting SG SGSA
Transmission SG SG
Mining Plant SE SESB
114 Electric Plant Acquisition Adjustments
Direct assigned-Jurisdiction S S
Other Thermal Production SG SGSB
Production-Non-Emitting SGSA
Transmission SG SG
115 Accum Provision for Asset Acquisition Adjustments
Direct assigned-Jurisdiction S S
Other Thermal Production SG SGSB
Production-Non-Emitting SGSA
Transmission SG SG
124 Weatherization
Direct assigned-Jurisdiction S S
General SO SO
128 Pensions
General SO SO
182W Weatherization
Direct assigned-Jurisdiction S S
186W Weatherization
Direct assigned-Jurisdiction S S
151 Fuel Stock
Steam Production Plant SE SESB
152 Fuel Stack-Undistributed
Steam Production Plant SE SESB
25316 UAMPS Working Capital Deposit
Mining Plant SE SESB
25317 DG&T Working Capital Deposit
Mining Plant SE SESB
25319 Provo Working Capital Deposit
Mining Plant SE SESB
11

Rocky Mountain Power
Exhibit No.3 1 Page 31 of 46
Case No. PAC-E-25-14
Witness:Joelle R.Steward
Allocation Factors by Account by Revenue Requirement Components
1 2 3 4 5
2020 PROTOCOL 2026 Protocol
FERC ACCT ACCT NAME REVENUE REQUIREMENT COMPONENTS ASSIGNED TO FACTOR FACTOR FACTOR
154 Materials and Supplies
Direct assigned-Jurisdiction S S
Chehalis S
Non-Emitting and Jim Bridger Units 1&2 SG SGSA
Other Thermal Production SG SGSB
Rolling Hills SGSC
Transmission SG SG
Mining SE SESB
General SO SO
Distribution SNPD SNPD
163 Stores Expense Undistributed
General SO SO
165 Prepayments
Direct assigned-Jurisdiction S S
Property Tax GPS GPS
Chehalis S
Non-Emitting and Jim Bridger Units 1&2 SG SGSA
Other Thermal Production SG SG56
Rolling Hills SGSC
Transmission SG SG
Mining SE SESB
General SO SO
182M Misc Regulatory Assets
Direct assigned-Jurisdiction S S
Chehalis S
Non-Emitting and Jim Bridger Units 1&2 SG SGSA
Other Thermal Production SG SG56
Rolling Hills SGSC
Transmission SG SG
Mining SE SESB
General SO SO
186M Misc Deferred Debits
Direct assigned-Jurisdiction S S
Chehalis S
Non-Emitting and Jim Bridger Units 1&2 SG SGSA
Other Thermal Production SG SG56
Rolling Hills SGSC
Transmission SG SG
General SO SO
Mining SE SESB
12

Rocky Mountain Power
Exhibit No.3 1 Page 32 of 46
Case No. PAC-E-25-14
Witness:Joelle R.Steward
Allocation Factors by Account by Revenue Requirement Components
1 2 3 4 5
2020 PROTOCOL 2026 Protocol
FERC ACCT ACCT NAME REVENUE REQUIREMENT COMPONENTS ASSIGNED TO FACTOR FACTOR FACTOR
Working Capital
CWC Cash Working Capital
Direct assigned-Jurisdiction S S
OWC Other Working Capital
131 Cash SNP SNP
141 Notes Receivable SO so
143 Other Accounts Receivable SO so
232 Accounts Payable SO so
232 Accounts Payable SE SE513
232 Accounts Payable SG SG
25330 Other Deferred Credits-Misc SE SE56
230 Other Deferred Credits-Misc SE SE56
254105 ARO Reg Liability SE SE56
Rate Base Deductions
235 Customer Service Deposits
Direct assigned-Jurisdiction S S
2281 Prov for Property Insurance
Prov for Property Insurance-Jurisdiction S S
Prov for Property Insurance SO SO
2282 Prov for Injuries&Damages
Prov for Injuries&Damages-Jurisdiction S S
Prov for Injuries&Damages SO SO
2283 Prov for Pensions and Benefits
Prov for Pensions and Benefits SO SO
22841 Accum Misc Oper Prov-Other
Chehalis WA EFSEC CO2 Mitigation Oblig S
254105 FAS 143 ARO Regulatory Liability
ARO S S
Trojan Plant TROJD TROJD
230 Asset Retirement Obligation
Trojan Plant TROJD TROJD
252 Customer Advances for Construction
Direct assigned-Jurisdiction S S
Transmission SG SG
Customer Related CN CN
25398 S02 Emissions
S02 Emissions SE SE513
25399 Other Deferred Credits
Direct assigned-Jurisdiction S S
Transmission SG SG
General SO SO
Mining SE SE513
13

Rocky Mountain Power
Exhibit No.3 1 Page 33 of 46
Case No. PAC-E-25-14
Witness:Joelle R.Steward
Allocation Factors by Account by Revenue Requirement Components
1 2 3 4 5
2020 PROTOCOL 2026 Protocol
FERC ACCT ACCT NAME REVENUE REQUIREMENT COMPONENTS ASSIGNED TO FACTOR FACTOR FACTOR
254 Regulatory Liabilities
Insurance Provision SO SO
190 Accumulated Deferred Income Taxes
Direct assigned-Jurisdiction S S
Bad Debt BADDEBT BADDEBT
Chehalis S
Non-Emitting and Jim Bridger Units 1&2 SG SGSA
Other Thermal Production SG SGSB
Rolling Hills SGSC
Transmission SG SG
Customer Related CN CN
General SO SO
Miscellaneous SNP SNP
Trojan TROJD TROJD
Distribution SNPD SNPD
Mining Plant SE SESB
281 Accumulated Deferred Income Taxes
Chehalis S
Non-Emitting and Jim Bridger Units 1&2 SG SGSA
Other Thermal Production SG SGSB
Rolling Hills SGSC
Transmission SG SG
282 Accumulated Deferred Income Taxes
Direct assigned-Jurisdiction S S
Depreciation DITBAL DITBAL
Chehalis S
Non-Emitting and Jim Bridger Units 1&2 SG SGSA
Other Thermal Production SG SG56
Rolling Hills SGSC
Transmission SG SG
Customer Related CN CN
General SO SO
Miscellaneous SNP SNP
Depreciation TAXDEPR TAXDEPR
Depreciation SCHMDEXP SCHMDEXP
System Gross Plant GPS GPS
Contribution in Aid of Construction CIAC CIAC
Mining SE SESB
14

Rocky Mountain Power
Exhibit No.3 1 Page 34 of 46
Case No. PAC-E-25-14
Witness:Joelle R.Steward
Allocation Factors by Account by Revenue Requirement Components
1 2 3 4 5
2020 PROTOCOL 2026 Protocol
FERC ACCT ACCT NAME REVENUE REQUIREMENT COMPONENTS ASSIGNED TO FACTOR FACTOR FACTOR
283 Accumulated Deferred Income Taxes
Direct assigned-Jurisdiction S S
Depreciation DITBAL DITBAL
Chehalis S
Non-Emitting and Jim Bridger Units 1&2 SG SGSA
Other Thermal Production SG SG56
Rolling Hills SGSC
Transmission SG SG
Customer Related CN CN
General SO SO
Miscellaneous SNP SNP
Trojan TROJD TROJD
Property Tax GPS GPS
Mining Plant SE SESB
255 Accumulated Investment Tax Credit
Direct assigned-Jurisdiction S S
Investment Tax Credits ITC84 ITC84
Investment Tax Credits ITC85 ITC85
Investment Tax Credits ITC86 ITC86
Investment Tax Credits ITC88 ITC88
Investment Tax Credits ITC89 ITC89
Investment Tax Credits ITC90 ITC90
Investment Tax Credits SG SG
Production Plant Accum Depreciation
108SP Steam Prod Plant Accumulated Depr
Jim Bridger Units 1&2 SG SGSA
Steam Plant other than Jim Bridger Units 1&2 SG SG56
108NP Nuclear Prod Plant Accumulated Depr
Nuclear Plant SG SGSA
108HP Hydraulic Prod Plant Accum Depr
Hydro SG SGSA
108xP Solar Plant-Accumulated Depr
Solar Plant S S
Solar Plant SG SGSA
108WP Wind Plant-Accumulated Depr
Wind-Except Rolling Hills SG SGSA
Rolling Hills Wind SG SGSC
108RP Renewable Plant-Accumulated Depr
Blundell SG SGSA
108OP Other Production Plant-Accum Depr
Other Production Plant-Chehalis SG S
Other Production Plant SG SGSB
108EP Energy Storage Plant Accum Depr
Energy Storage N/A S
Energy Storage N/A SGSA
Trans Plant Accum Depr
108TP Transmission Plant Accumulated Depr
Transmission Plant SG SG
15

Rocky Mountain Power
Exhibit No.3 1 Page 35 of 46
Case No. PAC-E-25-14
Witness:Joelle R.Steward
Allocation Factors by Account by Revenue Requirement Components
1 2 3 4 5
2020 PROTOCOL 2026 Protocol
FERC ACCT ACCT NAME REVENUE REQUIREMENT COMPONENTS ASSIGNED TO FACTOR FACTOR FACTOR
Distribution Plant Accum Depr
108360-108373 Distribution Plant Accumulated Depr
Direct assigned-Jurisdiction S S
108D00 Unclassified Dist Plant-Acct 300
Direct assigned-Jurisdiction S S
108DS Unclassified Dist Sub Plant-Acct 300
Direct assigned-Jurisdiction S S
108DP Unclassified Dist Sub Plant-Acct 300
Direct assigned-Jurisdiction S S
General Plant Accum Depr
108GP General Plant Accumulated Depr.
Direct assigned-Jurisdiction S S
Customer Related CN CN
General SO SO SO
Mining Plant SE SE56
108MP Mining Plant Accumulated Depr.
Mining Plant SE SE56
1081390 Accum Depr-Capital Lease
General SO SO
1081399 Accum Depr-Capital Lease
Direct assigned-Jurisdiction S S
Accum Provision For Amortization
111 SP Accum Prov for Amort-Steam
Steam Plants SG SGSA
Steam Plants SG SGSB
111 GP Accum Prov for Amort-General
Direct assigned-Jurisdiction S S
Customer Related CN CN
General SO SO SO
111 HP Accum Prov for Amort-Hydro
Hydro SG SGSA
1111P Accum Prov for Amort-Intangible Plant
General SO SO
Mining SE SESB
Customer Related CN CN
1111P Less Non-Utility Plant
Direct assigned-Jurisdiction S S
111390 Accum Prov Amort-Capital Leases
Distribution S S
Other Thermal Production SG SGSB
Production-Non-Emitting SG SGSA
General SO SO
16

Rocky Mountain Power
Exhibit No.3 1 Page 36 of 46
Case No. PAC-E-25-14
Witness:Joelle R.Steward
APPENDIX C - DEFINITIONS OF ALLOCATION FACTORS
i denotes count of jurisdictions. j denotes count of month in a year. N is the number of
regulatory jurisdictionsin which PacifiCorp operates and to which it allocates costs.
Bad Debt Expense Factor("BADDEBT")
BADDEBTi = ACCT904i
Zi=N
1 ACCT904i
where:
BADDEBTi = Bad Debt Expense Factor for jurisdiction i.
ACCT904i = Balance in FERC Account 904 for jurisdiction i.
N = Number of jurisdictions.
The BADDEBT Factor is calculated by dividing the FERC account 904 Uncollectible Accounts
amount for a jurisdiction by the total 904 amount for all jurisdictions. The factor allocates tax-
related costs for bad debt related expenses.
Contributions in Aid of Construction Factor ("CIAC")
CIACi
CIACNAi
= N
Zi=1 CIACNAi
where:
CIAO = Contributions in Aid of Construction Factor for
jurisdiction i.
CIACNAi — Contributions in aid of construction—net additions for
jurisdiction i.
N — Number of jurisdictions.
The CIAC Factor is calculated by dividing the contribution in aid of construction net additions
for a jurisdiction by the total contribution in aid of construction net additions for all jurisdictions.
The factor allocates tax-related costs for contributions in aid of construction.
Customer Number Factor ("CN")
C USTi
CNi = �N COST
i=i i
where:
CNi = Customer Number Factor for jurisdiction i.
CUSTi = Total electric customers for jurisdiction i.
N = Number of jurisdictions.

Rocky Mountain Power
Exhibit No.3 1 Page 37 of 46
Case No. PAC-E-25-14
Witness:Joelle R.Steward
The Customer Number Factor is calculated using the ratio of number of customers for a
jurisdiction to the total number of electric customers for all jurisdictions. The factor is used to
allocate customer-related costs.
Deferred Tax Balance Factor("DITBAL")
DITBALAi
DITBALi = iv DITBALAi
i
where:
DITBALI = Deferred Tax Balance Factor for jurisdiction i.
DITBALAi = Deferred tax balance allocated to jurisdiction i.
(Deferred tax balance is allocated by a run of PowerTax
based upon the above factors. PowerTax is a computer
software package used to track deferred tax expense &
deferred tax balance.)
N — Number of jurisdictions.
The DITBAL Factor is used to allocate deferred tax balances to jurisdictions.
Division Generation—Utah Factor("DGU")
SG-i
DGUi = N
f i-1 SG*i
where:
DGUi = Division Generation—Utah Factor for jurisdiction i.
SG*i = SGi if i is a pre-merger Utah Power jurisdiction, otherwise
0.
SGi = System Generation Factor for jurisdiction i.
N = Number of jurisdictions.
The DGU Factor is calculated as the ratio of the pre-merger Utah Power jurisdiction's SG factor
for a jurisdiction divided by the sum of the pre-merger Utah Power jurisdiction's SG factors. The
DGU factor is used to allocate some Deferred Investment Tax Credits.
Gross Plant System Factor("GPS")
PPi + PTi + PDi + PGi + PIi
GPSi = zN 1(PPl + PTi + PDi + PGi + PIi)
where:
GPSi = Gross Plant System Factor for jurisdiction i.
PPi = Production plant for jurisdiction i.
PTi = Transmission plant for jurisdiction i.
PDi = Distribution plant for jurisdiction i.
PGi = General plant for jurisdiction i.

Rocky Mountain Power
Exhibit No.3 1 Page 38 of 46
Case No. PAC-E-25-14
Witness:Joelle R.Steward
Pli = Intangible plant for jurisdiction i.
N = Number of jurisdictions.
The GPS Factor is used to allocate property taxes. It is calculated using the ratio of gross plant
for a jurisdiction divided by the total gross plant for all jurisdictions.
Portfolio Allocation Factor One ("PAl")
PA1 = 100% —SGF*i
where:
SG-F*i = SG-Fi if i is Washington, otherwise 0.
SG-Fi = System Generation—Fixed Factor for jurisdiction i.
The PA1 factor in which Washington receives a fixed allocation. This factor is used to calculate
the SGSA and SESA allocation factors. The SG-Fi factor is defined below.
Portfolio Allocation Factor Two ("PA2")
PA2 = 100%
The PA2 factor in which Washington does not receive an allocation. This factor is used to
calculate the SGSB and SE513 allocation factors.
Portfolio Allocation Factor Three ("PA3")
PA3 = 100% — SGFR*i
where:
SG-FR*i = SG-FR; if i is Washington, otherwise 0.
SG-FR; = System Generation—Fixed Factor for jurisdiction i.
The PA3 factor in which Washington receives a fixed allocation. This factor is used to calculate
the SGSC allocation factor for Rolling Hills Wind. The SG-FR;factor is defined below.
Schedule M—Depreciation Expense Factor("SCHMDEXP")
SCHMDi = DEPRCiN
Yi l DEPRCi
where:
SCHMA = Schedule M—Depreciation Expense Factor for
jurisdiction i.
DEPRCi = Depreciation in FERC Accounts 403.1 -403.9 for
jurisdiction i.
N = Number of jurisdictions.

Rocky Mountain Power
Exhibit No.3 1 Page 39 of 46
Case No. PAC-E-25-14
Witness:Joelle R.Steward
The SCHMDEXP factor is used to allocate Schedule M items related to depreciation expense.
Situs—Situs Factor("S")
Si = 100%
where:
Si = Situs Factor for jurisdiction i.
System Capacity Factor("SC")
sc — Ej=
i 1 TAPij
— ry lz TAP
1�j=1 ij
where:
SCi = System Capacity Factor for jurisdiction i.
TAPiy = Weather-normalized peak load of jurisdiction i at the time
of the system peak in month j. The peak load is further
adjusted to exclude the peak load of Load Control Demand-
Side Management programs as defined in the 2026
Protocol.
N = Number of jurisdictions.
The SC factor is calculated based on the relative capacity requirements of each State as
determined based on 12 monthly coincident peaks. The SC factor is used to calculate the System
Generation factor and the SO factor.
System Energy Factor("SE")
SE• —_ E12 j=1TAEij
` N� 12 TAE i=1 Ej=1 ij
where:
SEi = System Energy Factor for jurisdiction i.
TAEii = Weather-normalized energy at input of jurisdiction i in
month j.
N = Number of jurisdictions.
The SE factor is used to allocate non-firm wheeling revenue, calculate the SO factor and to
calculate the SE5 factor. It is calculated as the ratio of the weather-normalized energy at input
for a jurisdiction divided by the total weather-normalized energy at input for all jurisdictions.
System Energy(five state)Factor("SE5")

Rocky Mountain Power
Exhibit No.3 1 Page 40 of 46
Case No. PAC-E-25-14
Witness:Joelle R.Steward
SE*i
SESi = N *.
Ei=1 SE ti
where:
SE5i = System Energy(five state)Factor for jurisdiction i.
SE'i = SEi if i is a CA, OR, WY, UT, ID jurisdiction, otherwise 0.
SEi = System Energy Factor for jurisdiction i.
N = Number of jurisdictions.
The SE5 factor is dynamically calculated for customers in California, Idaho, Oregon, Utah and
Wyoming. It is calculated as the ratio of the individual five state jurisdiction's SE factor divided
by the sum of the five states SE factors. The SE5 factor is used for the calculation of the SE5A
and SESB allocation factors.
System Energy(five state)A Factor("SE5A")
SESAi = SE5i * PA1
where:
SESAi = System Energy(five state)A Factor for jurisdiction i.
SE5i = System Energy(five state) Factor for jurisdiction i.
PAI = Portfolio Allocation One Factor(PA I).
This factor allocates energy-related costs for Jim Bridger Units 1 and 2 and non-firm wholesale
sales and purchased power. The SE5A factor is calculated by multiplying the SE5 factor by the
PA 1 factor.
System Energy(five state)B Factor("SESB")
SESBi = SESi * PA2
where:
SESBi = System Energy(five state) B Factor for jurisdiction i.
SE5i = System Energy (five state) Factor for jurisdiction i.
P42 = Portfolio Allocation Two Factor(PA2).
This factor allocates energy-related costs for other thermal units excluding Chehalis and Jim
Bridger 1&2.
The SESB factor is calculated by multiplying the SE5 factor by the PA2 factor.
System Generation Factor(IISG")
SGi = 0.75 * SCi + 0.25 * SEi
where:
SGi System Generation Factor for jurisdiction i.
SCi = System Capacity Factor for jurisdiction i.
SE; = System Energy Factor for jurisdiction i.

Rocky Mountain Power
Exhibit No.3 1 Page 41 of 46
Case No. PAC-E-25-14
Witness:Joelle R.Steward
The SG factor is used to allocate transmission related costs. It is also used to calculate the SG5
factor. It is calculated using a weighting of 75% of the SC factor and 25% of the SE factor for a
jurisdiction.
System Generation (five state) Factor("SG5")
SG*i
SGSi = N *
Ei_1 SG i
where:
SGSi = System Generation (five state)Factor for jurisdiction i.
SG*i = SGi if i is a CA, OR,WY, UT, ID jurisdiction, otherwise 0.
SGi = System Generation Factor for jurisdiction i.
N = Number of jurisdictions.
The SG5 factor is dynamically calculated for customers in California, Idaho, Oregon, Utah and
Wyoming. It is calculated as the ratio of the individual five state jurisdiction's SG factor divided
by the sum of the five states SG factors. The SG5 factor is used for the calculation of the SGSA,
SGSB and SGSC allocation factors.
System Generation (four state) Factor("SG4")
SG*i
SG4i = N *i
Ei_1 SG
where:
SG4i = System Generation (four state) Factor for jurisdiction i.
SG*i = SGi if i is a CA,WY, UT, ID jurisdiction, otherwise 0.
SGi = System Generation Factor for jurisdiction i.
N = Number of jurisdictions.
The SG4 factor is dynamically calculated for customers in California, Idaho, Utah and Wyoming.
It is calculated as the ratio of the individual four state jurisdiction's SG factor divided by the sum
of the four states SG factors. The SG4 factor is used for the calculation of the SGSC allocation
factor.
System Generation (five state)A Factor("SGSA")
SGSAi = SGSi * PA1
where:
SGSAi = System Generation (five state)A Factor for jurisdiction i.
SGSi = System Generation(five state) Factor for jurisdiction i.
PA = Portfolio Allocation One Factor(PA I).

Rocky Mountain Power
Exhibit No.3 1 Page 42 of 46
Case No. PAC-E-25-14
Witness:Joelle R.Steward
This factor allocates costs for non-emitting resources and Jim Bridger Units 1 and 2, excluding
Rolling Hills Wind and QFs. The SG5A factor is calculated by multiplying the SG5 factor by the
PA 1 factor.
System Generation (five state) B Factor("SG5B")
SGSBi = SGSi * PA2
where:
SGSBi = System Generation (five state) B Factor for jurisdiction i.
SGSi = System Generation(five state) Factor for jurisdiction i.
PA2 = Portfolio Allocation Two Factor(PA2).
This factor allocates costs for other thermal units excluding Chehalis and Jim Bridger 1&2.
The SG5B factor is calculated by multiplying the SG5 factor by the PA2 factor.
System Generation (five state) C Factor("SG5C")
SGSCi = SG4i * PA3
where:
SGSCi = System Generation (five state) C Factor for jurisdiction i.
SG4i = System Generation(four state) Factor for jurisdiction i.
PA3 = Portfolio Allocation Three Factor(PA3).
This factor allocates costs for Rolling Hills Wind. The SG5C factor is calculated by multiplying
the SG4 factor by the PA3 factor.
System Generation Factor—Fixed ("SG-F")
SG_Fi = SG_F*i
where:
SG-Fi = System Generation—Fixed Factor Rolling Hills for
jurisdiction i.
SG-F'ki = 7.8971% if i is the WA jurisdiction, otherwise 0.
The SG—F factor is the Washington fixed factor used to allocate costs for non-emitting resources
and Jim Bridger Units 1 and 2, excluding Rolling Hills Wind and QFs. The factor is also used in
calculating the SG5A factor.
System Generation Factor—Fixed Rolling Hills ("SG-FR")
SGFRi = SGFR*i
where:

Rocky Mountain Power
Exhibit No.3 1 Page 43 of 46
Case No. PAC-E-25-14
Witness:Joelle R.Steward
SG-FRi = System Generation—Fixed Rolling Hills Factor for
jurisdiction i.
SG-FR`i = 34.8727% if i is the WA jurisdiction, otherwise 0.
The SG—FR factor is the Washington fixed factor used to allocate Rolling Hills Wind. The factor
is also used in calculating the SGSC factor.
System Gross Plant Distribution Factor("SGPD")
SGPD- = GPD-N
E- l GPD-
where:
SGPDi = System Gross Plant Distribution Factor for jurisdiction i.
GPDi = Gross plant distribution for jurisdiction i.
N = Number of jurisdictions.
This factor is calculated by taking the ratio of gross distribution plant for a jurisdiction by the
total gross distribution plant for all jurisdictions. This factor is used to calculate the SO factor.
System Net Plant-Distribution Factor("SNPD")
SNPD- = N PDi + ADPD-
E-=1(PD- + ADPDL)
where:
SNPDi = System Net Plant—Distribution Factor for jurisdiction i.
PDi = Distribution plant—for jurisdiction i.
ADPA = Accumulated depreciation distribution plant- for
jurisdiction i.
N = Number of jurisdictions.
The SNPD factor is used to allocate non situs distribution costs. The factor is calculated as the
ratio of net distribution plant for a jurisdiction by the total net distribution plant for all
jurisdictions.
System Net Plant Factor("SNP")
SNPi
PPi + PTi + PDi + PGi + PIi + ADPPi + ADPTi + ADPD- + ADPG- + ADPI-
EN 1(PPi + PTi + PDi + PGi + PIi + ADPPi + ADPT- + ADPD- + ADPG- + ADPI-)
where:
SNPi = System Net Plant Factor for jurisdiction i.
PPi = Production plant for jurisdiction i.
PTi = Transmission plant for jurisdiction i.

Rocky Mountain Power
Exhibit No.3 1 Page 44 of 46
Case No. PAC-E-25-14
Witness:Joelle R.Steward
PA = Distribution plant for jurisdiction i.
PG = General plant for jurisdiction i.
Pli = Intangible plant for jurisdiction i.
ADPA = Accumulated depreciation production plant for jurisdiction
i.
ADPTi = Accumulated depreciation transmission plant for
jurisdiction i.
ADPA = Accumulated depreciation distribution plant for jurisdiction
i.
ADPGi = Accumulated depreciation general plant for jurisdiction i.
ADPI, = Accumulated depreciation intangible plant for jurisdiction
i.
N = Number of jurisdictions.
The SNP factor is used to allocate interest expense and miscellaneous deferred tax treatment.
The factor is calculated by taking the ratio of the system net plant balance for a jurisdiction
divided by the total system net plant balance for all jurisdictions.
System Overhead Factor ("SO")
Sol — SCi + SEi + SGPDi
3
where:
SO; = System Overhead Factor for jurisdiction i.
SC; = System Capacity Factor for jurisdiction i.
SE; = System Energy Factor for jurisdiction i.
SGPD; = System Gross Plant Distribution for jurisdiction i.
The SO factor is used to allocate system overhead costs. The SO factor is calculated by taking
the sum of the SC, SE and SGPD factor for a jurisdiction and dividing by three.
Tax Depreciation Factor("TAXDEPR")
TAXDEPRi = TAXDEPRAiw
Ei TAXDEPRAi
where:
TAXDEPR; = Tax Depreciation Factor for jurisdiction i.
TAXDEPRAi Tax depreciation allocated to jurisdiction i.
(Tax depreciation is allocated based on functional pre-
merger and post-merger splits of plant using Divisional and
System allocations from above. Each jurisdiction's total
allocated portion of tax depreciation is determined by its

Rocky Mountain Power
Exhibit No.3 1 Page 45 of 46
Case No. PAC-E-25-14
Witness:Joelle R.Steward
total allocated ratio of these functional pre- and post-
merger splits to the total PacifiCorp tax depreciation.)
N = Number of jurisdictions.
The TAXDEPR factor allocates depreciation-related tax costs.
Trojan Decommissioning Factor ("TROJD")
TROJDi
ACCT22842i
= N
Yi 1ACCT22842i
where:
TROJA = Trojan Decommissioning Factor for jurisdiction i.
ACCT22842i Allocated adjusted balance in FERC Account 228.42
(Accumulated Provision for Decommissioning Trojan) for
jurisdiction i.
N = Number of jurisdictions.
The TROJD factor is used to allocate decommissioning-related costs associated with the Trojan
plant.

Rocky Mountain Power
Exhibit No.3 1 Page 46 of 46
Case No. PAC-E-25-14
Witness:Joelle R.Steward
APPENDIX D-LEGACY INTERRUPTIBLE CONTRACTS
The following Legacy Interruptible Contracts covered under Section 3.3 are:
• Nucor-Steel Utah beginning on March 1, 2022
• P4 Production beginning on January 1, 2022
Legacy Interruptible Contracts with Customer Ancillary Service Attributes
For allocation purposes, Legacy Interruptible Contracts with customer ancillary service
attributes are viewed as two transactions. PacifiCorp sells the customer electricity at the
retail service rate and then buys the electricity back during the interruption period at the
ancillary service contract's rate.
Loads of Legacy Interruptible Contract customers will be included in all load-based
dynamic allocation factors.
When interruptions of a Legacy Interruptible Contract customer's service occur, the host
jurisdiction's load-based dynamic allocation factors and the retail service revenue are
calculated as though the interruption did not occur.
Revenues received from Legacy Interruptible Contract customer, before any discounts for
ancillary services attributes of the Legacy Interruptible Contract, will be assigned to the
state where the Legacy Interruptible Contract customer is located.
Discounts from tariff prices provided in a Legacy Interruptible Contract that recognize
ancillary services attributes of the contract, and payments to retail customers for ancillary
services will be allocated among states using the SGSA factor.
Buy-Through of Economic Curtailment
When a buy-through option is provided with economic curtailment, the load, costs, and
revenue associated with a customer buying through economic curtailment will be excluded
from the calculation of state revenue requirements. The cost associated with the buy-
through will be removed from the calculation of Net Power Costs,the Legacy Interruptible
Contract customer load associated with the buy-through will not be included in the
calculation of dynamic allocation factors, and the revenue associated with the buy-through
will not be included in state revenues.

Rocky Mountain Power
Exhibit No . 4
Case No . PAC-E-25-14
Witness : Joelle R. Steward
BEFORE THE IDAHO PUBLIC UTILITIES
COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Joelle R. Steward
Washington 2026 Protocol
August 2025

Rocky Mountain Power
Exhibit No.4 1 Page 1 of 8
Case No. PAC-E-25-14
Witness:Joelle R.Steward
The Washington 2026 Protocol
Introduction
PacifiCorp d/b/a Pacific Power and Light Company(PacifiCorp or Company)proposes this cost
allocation protocol to address the imminent removal of coal resources from Washington rates, as
required by Washington's Clean Energy Transformation Act(CETA), and the reallocation of
existing resources using fixed allocation factors.
Background
PacifiCorp is a multi jurisdictional electric utility that provides services in six states (California,
Idaho, Oregon,Utah, Wyoming, and Washington). Currently, Washington uses the Washington
Inter-Jurisdictional Allocation Methodology(WIJAM) for determining which costs are eligible
for recovery in rates from customers in PacifiCorp's Washington service area.t
In the context of inter jurisdictional cost allocation, the Washington Utilities and Transportation
Commission(Commission) will consider a resource to be used and useful to Washington
customers' if the resource "provides quantifiable direct or indirect benefits to Washington
[ratepayers]commensurate with its costs."3 To modify a cost allocation methodology, "any
changes should be considered in the context of an overall review of that methodology."4
Additionally, Parties must demonstrate that"any changes proposed more closely aligns with the
allocation of costs based on causation[.]"5 Finally, "the party advocating for the change must
make a detailed and persuasive showing demonstrating that the proposed change is
appropriate."'
Terms of the Protocol
1. Implementation. The Washington 2026 Protocol includes modifications to the WIJAM
subject to approval by the Commission, including the implementation of fixed factors,
removal of coal resources, and the situs allocation of the Chehalis generating facility
among other changes. The Washington 2026 Protocol will be implemented in two phases.
The Washington 2026 Protocol is part of the larger integrated transition to the 2026
Protocol for all the states in which PacifiCorp serves customers and represents the first
step of Phase 1. Phase 2 will involve the introduction of fixed allocation factors in other
states, a possible reconciliation of new issues that may arise as other states review
implementation of the 2026 Protocol in their jurisdictions, the use of market settlements
and locational marginal pricing to track net power costs, and potential review of
transmission allocations.
1 Prior to the WIJAM methodology being approved in Docket No.UE-191024,PacifiCorp had used the Western
Control Area methodology,which was approved in Docket No.UE-061546.
2 See RCW 80.04.250.
3 Docket No.UE-050684,Order 04¶68.
4 Docket No.UE-130043,Order 05¶92-94.
5 Id.
6 Id.

Rocky Mountain Power
Exhibit No.4 1 Page 2 of 8
Case No. PAC-E-25-14
Witness:Joelle R.Steward
2. Prudence. The proposed allocation of a particular expense or investment under the
Washington 2026 Protocol is not intended to and will not prejudge, or prevent any party
from taking a position on the prudence of those costs or the extent to which any particular
cost may be reflected in rates. Nothing in the Washington 2026 Protocol is intended to
abrogate the Commission's right or obligation to: (1) determine fair,just, and reasonable
rates based upon applicable laws and the record established in rate proceedings conducted
by the Commission; (2) consider the impact of changes in laws, regulations, or
circumstances on inter jurisdictional allocation policies and procedures when determining
fair,just, and reasonable rates; or(3) establish different allocation policies and
procedures for purposes of allocating costs and revenues to different customers or
customer classes.
3. System Transmission. All existing system transmission costs and benefits will continue
to be allocated using the System Generation(SG) factor as specified in Attachment 1.
4. Existing Resources. Existing resources will be allocated using the Fixed SG-Factor
(SG-F) as identified below.
4.1. Existing Non-Emitting Resources.' The allocation factors for non-emitting
resources that are not qualifying facilities as defined under the Public Utility
Regulatory Policies Act are as follows:
Allocation Factor
Rolling Hills Wind SG-FR 34.873%
Existing Non-emitting Resources 7.897%
(SG-F)
4.2. Existing Natural Gas Resources. The Hermiston natural gas plant will be removed
from Washington rates. Washington will be allocated the following natural gas
resources using the fixed factors identified below:
Allocation Factor
Chehalis 100%
Jim Brid er 1 SG-F 7.897%
Jim Brid er 2 SG-F 7.897%
5. Existing and Future Qualifying Facilities. The costs and benefits of existing
Washington power purchase agreements for Qualifying Facilities, as defined under the
Public Utility Regulatory Policies Act, will continue to be situs assigned to Washington.
6. Existing Coal Resources. Consistent with RCW 19.405.030, PacifiCorp will remove
from Washington rates all operating costs and benefits associated with Bridger Units 3-4
and Colstrip Unit 4 on December 31, 2025.
7 Existing Resources are non-emitting resources that have been system allocated and in-service before January 1,
2027 and included in the 2025 PCORC.

Rocky Mountain Power
Exhibit No.4 1 Page 3 of 8
Case No. PAC-E-25-14
Witness:Joelle R.Steward
7. New Resources.New Resources, that are not qualifying facilities as defined under the
Public Utility Regulatory Policies Act, acquired for Washington after April 1, 2025,will
be assigned on a situs basis to Washington unless circumstances justify a cost-sharing
proposal with other states. If circumstances allow,then PacifiCorp may propose an
alternative allocation at or before a prudence review occurs for a new resource.
8. Net Power Costs. Forecasted net power costs for ratemaking purposes will be allocated
consistent with Sections 3,4,5,6, and 7. Additionally, Washington customers will receive
all direct and indirect benefits associated with their proportional system-allocated share
of existing transmission, including Western Energy Imbalance Market and Extended
Day-Ahead Market benefits.
8.1. PacifiCorp's energy supply management's risk management policy will be modified
to create a separate book for Washington. The risk management policy will create
limits to address resource adequacy and price volatility based on the Washington
load and resources. Purchases made in the Washington book in accordance with the
risk management policy will be sites assigned to Washington.
8.2. Actual Net Power Costs. Actual net power costs for ratemaking purposes will
include only the generation resources and situs assigned purchases in section 7.1 that
are included in Washington rates.
9. System Overhead (2026 SO Factor). Costs that support more than one function, such as
generation, transmission, or distribution plant, will continue to be allocated on the System
Overhead(SO) Factor but will be calculated based on an equal one-third weighting of the
System Capacity(SC) Factor, System Energy Factor, and System Gross Plant
Distribution (SGPD) Factor as identified in the 2020 Protocol as the Post-Interim SO
Factor.
9.1. PacifiCorp will propose a mechanism to manage the Company's excess liability
insurance costs and separately address the inter jurisdictional allocation of these
costs in that filing.
10. Decommissioning Costs of Coal-Fired Resource Being Removed from Washington
Rates. Washington will continue to be allocated ongoing and expected decommissioning
expenses for a WIJAM/WCA share of Jim Bridger Units 3-4 and Colstrip Unit 4
consistent with the previous terms of the WIJAM.
11. Decommissioning Costs of Gas-Fired Resources for Washington. PacifiCorp will
address the decommissioning costs of gas-fired resources that have been removed from or
reassigned to Washington in a future rate proceeding or through Phase 2 of the cost
allocation process.
12. This Protocol proposes modifications to the WIJAM, which serves as the basis for
allocating costs in Washington. PacifiCorp will allocate costs based on the WIJAM and

Rocky Mountain Power
Exhibit No.4 1 Page 4 of 8
Case No. PAC-E-25-14
Witness:Joelle R.Steward
the preceding WCA subject to the modifications in this Washington 2026 Protocol for
ratemaking purposes in Washington unless a different cost allocation method is approved
by the Commission.
13. Attachment 1 contains updated allocation factors that reflect the changes necessary to
implement the Washington 2026 Protocol in this 2025 Washington power cost only rate
case (PCORC). Allocation factors will default to the approved WIJAM allocation factors
if they are not specifically contained in Attachment 1. Attachment 1 may be updated
again when PacifiCorp files its next General Rate Case to revise the factors to reflect the
implementation of this Protocol as described in Section 1.

Rocky Mountain Power
Exhibit No.4 1 Page 5 of 8
Case No. PAC-E-25-14
Witness:Joelle R.Steward
ATTACHMENT 1

Rocky Mountain Power
Exhibit No.4 1 Page 6 of 8
Case No. PAC-E-25-14
Witness:Joelle R.Steward
Any account/factor combo that does not show up in this table is not part of the proposed changes in the Washington 2026 Protocol and default back to thf
WDAM approved allocations
FERC ACCOUNT DESCRIPTION WDAM Modified Factors
447NPC Sales for Resale-NPC
SG SG-F
SE SG-F
Steam Power Generation
500,502,504-514 Steam Plant 0&M
Colstrip 4 CAGW System-Non-WA
JB 1&2 JBG SG-F
JB 3&4 JBG System-Non-WA
501 Fuel Related
SE SG-F
Colstrip 4 CAGW System-Non-WA
JB 1&2 JBE SG-F
JB 3&4 JBG System-Non-WA
501NPC Fuel Related
Colstrip 4 CAEW System-Non-WA
JB 1&2 JBE SG-F
JB 3&4 JBG System-Non-WA
503NPC Steam From Other Sources
SE SG-F
Hydraulic Power Generation
535-454 Hydro Plant O&M
SG SG-F
Solar Power Generation
558 Solar Plant 0&M
S Situs
Wind Power Generation
558 Wind Plant 0&M
SG SG-F
Renewable Generation
559 Renewable Plant O&M
Geothermal SG SG-F
Other Power Generation
546,548-554 Other Production Plant O&M
Chehalis CAGW Situs-WA
Hermiston CAGW Situs-Non-WA
547NPC Fuel-NPC
JBG SG-F
Chehalis CAGW Situs-WA
Hermiston CAGW Situs-Non-WA
Other Power Supply
555NPC Purchased Power-NPC
SG SG-F
SE SG-F
556 System Control&Load Dispatch
SG SG-F
557 Other Expenses
SG SG-F
SO SO

Rocky Mountain Power
Exhibit No.4 1 Page 7 of 8
Case No. PAC-E-25-14
Witness:Joelle R.Steward
FERC ACCOUNT DESCRIPTION WIJAM Modified Factors
565NPC Transmission of Electricity by Others-NPC
SG SG-F
SE SG-F
Depreciation Expense
403SP Steam Depreciation
Colstrip 4 CAGW System-Non-WA
JB 1&2 JBG SG-F
JB 3&4 JBG System-Non-WA
403HP Hydro Depreciation
SG SG-F
4030P Other Production Depreciation
Chehalis CAGW Situs-WA
Hermiston CAGW Situs-Non-WA
403XP Solar Production Depeciation
S Situs
403WP Wind Production Depreciation
Wind-Except Rolling Hills SG SG-F
Rolling Hills Wind SG SG-FR
403RP Renewable Production Depreciation
Geothermal SG SG-F
Amortization Expense
404HP Amortization of Other Electric Plant
SG SG-F
Deferred Income Taxes
41110 Deferred Income Tax-Federal-CR
Production SG SG-F
SO s0
JB 1&2 JBG SG-F
JB 3&4 JBG System-Non-WA
Colstrip 4 CAGW System-Non-WA
Chehalis CAGW Situs-WA
Hermiston CAGW Situs-Non-WA
Rolling Hills Wind SG SG-FR
Adjustments to Calculated Tax:
40910 SO SO
40910 SG SG-F
Steam Production Plant
310-316 Steam Plant
Colstrip 4 CAGW System-Non-WA
JB 1&2 JBG SG-F
JB 3&4 JBG System-Non-WA
Hydraulic Plant
330-336 Hydro Plant
SG SG-F
Solar Production Plant
338 Solar Plant
S Situs
Wind Production Plant
338 Wind Plant
Wind-Except Rolling Hills SG SG-F
Rolling Hills Wind SG SG-FR

Rocky Mountain Power
Exhibit No.4 1 Page 8 of 8
Case No. PAC-E-25-14
Witness:Joelle R.Steward
FERC ACCOUNT DESCRIPTION WIJAM Modified Factors
Renewable Production Plant
339 Renewable Plant
Geothermal SG SG-F
Other Production Plant
340-346 Other Production Plant
Chehalis CAGW Situs-WA
Hermiston CAGW Situs/System-Non-WA
Unclassified Production Plant
106.3 Unclassified Production Plant
SG SG-F
General Plant
389-398 General Plant
SO SO
Total Rate Base Additions
22841 Accum Misc Oper Provisions-Other
CAGW Situs-WA
282 Accumulated Deferred Income Taxes
Production SG SG-F
SO SO
JB 1&2 JBG SG-F
JB 3&4 JBG System-Non-WA
Colstrip 4 CAGW System-Non-WA
Chehalis CAGW Situs-WA
Hermiston CAGW Situs-Non-WA
Rolling Hills Wind SG SG-FR
Production Plant Accumulated Depreciation
108SP Steam Prod Plant Accumulated Depr
Colstrip 4 CAGW System-Non-WA
JB 1&2 JBG SG-F
JB 3&4 JBG System-Non-WA
108HP Hydraulic Prod Plant Accum Depr
SG SG-F
I08XP Solar Plant-Accumulated Depr
S Situs
108WP Wind Plant-Accumulated Depr
Wind-Except Rolling Hills SG SG-F
Rolling Hills Wind SG SG-FR
108RP Renewable Plant-Accumulated Depr
Geothermal SG SG-F
108OP Other Production Plant-Accum Depr
Chehalis CAGW Situs-WA
Hermiston CAGW Situs/System-Non-WA
General Plant Accumulated Depreciation
108GP General Plant Accumulated Depr
SO SO
Accumulated Provision for Amortization
111GP Accum Prov for Amort-General
SO SO
111HP Accum Prov for Amort-Hydro
SG SG-F
111IP Accum Prov for Amort-Intangible Plant
SO SO